Swift Energy Company's CEO Hosts Investor/Analyst Day (Transcript)

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Swift Energy Company (NYSE:SFY)

Investor/Analyst Day Call

March 15, 2012 09:00 ET


Paul Vincent – Director, Finance and Investor Relations

Terry Swift – Chairman and Chief Executive Officer

Bruce Vincent – President

Bob Banks – Executive Vice President and Chief Operating Officer

Steve Tomberlin – Senior Vice President, Resource Development and Engineering

John Branca – Vice President, Exploration & Geosciences

Steve Schmitt – Vice President, Energy Marketing

Alton Heckaman – Executive Vice President and Chief Financial Officer


Leo Mariani – RBC Capital Markets

Neal Dingmann – SunTrust

Michael Hall – Robert W. Baird

Adam Leight – RBC

Andrew Coleman – Raymond James

Mark Lear – Credit Suisse

Paul Vincent – Director, Finance and Investor Relations

Good morning and welcome to the Swift Energy 2012 Annual Analyst and Investor Day. I am Paul Vincent. I am the Director of Finance and Investor Relations here at Swift Energy and I'd like to thank you all for joining us both here in Houston and on the webcast over the internet, really appreciate the participation. And for those of you here in Houston, we really appreciate you choosing to make Houston and the Greenspoint area your spring break destination of choice.

We have a great presentation here for you today that’s going to detail some of our highlights of 2011, operational activities, and focus areas of 2012 as well as our financial position. We think you’ll really learn a lot today. Before we begin, I just want to point out a few things to the folks here in Houston. We do have emergency exits here at the back of the room and should there be an event or any type of emergency that requires an evacuation, the hotel will provide instructions over their loud speaker system. We also have first aid available for folks, should they require that kind of assistance. I’d also want to remind everyone that we are webcasting today’s presentation, and as such, we are going to try to stick to our agenda that’s posted in front of you as closely as possible and we'd ask that you keep your cellular and wireless devices on either silent or vibrate type mode to avoid any interference with the broadcast.

We do have one break scheduled today. We are going to try to honor that and keep that to between 10 and 15 minutes. It should give everyone plenty of time to get their refreshments and make any necessary phone calls etcetera. With that all being said, thank you gain for your attention and thank you again for your participation and interest at Swift Energy. And as always, I'd say it’s a distinct honor to introduce to you Terry Swift, our Chairman and CEO of Swift Energy Company

Terry Swift – Chairman and Chief Executive Officer

Thank you, Paul and thank you for joining us today. We always found ourselves each year gathered here and we like to go through all the activity of the past year and show our accomplishments, but we also really like to focus on what’s coming next. I think that’s what you are most interested in, but today you will see a little bit of last year, and some of the things that set us up, but we are still excited because this year we can see even more visible inventory and I want to clearly lead with two very important statements I think.

The Swift Energy Company is absolutely positioned for the future and that future has a very significant footprint in liquids. And as we’re very familiar with the times liquids, liquids, liquids that’s really the focus of not only the industry right now, but Swift Energy Company is a very interesting dynamic. This is not new for us. We have always had liquids. We have always had an inventory of such, but today we are going to be focusing on that. That’s not to say that we won’t have the same issues in terms of forward-looking statements, we'll have to make sure that from the legal perspective that you understand that we are going to be showing you scenarios today, and we put forward this forward-looking statement to remind you that the future is somewhat uncertain, but not to overlook the fact that we need to show you what we think we can do and today we are going to do that.

As we dipped into today’s agenda, we are going to begin with a strategic overview and an industry overview, I’ll take that first opening part, then Bruce will come up and then we’ll go into the details of the operation from South Texas to Louisiana, both in the Central and Southeast areas, and then we’ll wrap up with a financial overview before we go to the Q&A.

Today’s speakers we have listed here myself, Bruce Vincent, President; Bob Banks, our Chief Operating Officer; Alton Heckaman, Chief Financial Officer; Steve Tomberlin, Resource Development and Engineering, Senior Vice President; John Branca, Exploration and Geosciences; Steve Schmitt, Energy Marketing, and of course, Paul has introduced to us as Director of our Finance and Investor Relations.

This is just a sample of the talent we have at Swift Energy Company. I hope you will see today that in these presentations, we have brought a lot of depth to our operations. We are very focused on the asset teams that we have, and I hope that shines for today that we not only have the inventory of great projects, we also have an incredible staff of very highly skilled individuals work in these projects, and we’ve got the balance sheet and the financing to be able to do the things that we need to do.

To not avoid the obvious, a lot of companies, I don’t want to talk about gas at all and I thought that we talk about gas at the very beginning, kind of get that out of the way. There maybe a few more discussions, a little bit later in the day, but I thought we would share a little bit of the industry history, and some of the rationale for why we find ourselves right now with some very low natural gas prices.

You could see by this chart that the natural gas production in the U.S. from 74, back to 74 all the way at present, has had all the seasonal variations from summer to winter and that’s what all of our cycles are at the spikes and valleys, but in general we had that gas bubble in the mid 80s, that we all went through, and then we had the period of declining production in the early 2000 and then we have had this phenomenal change in our industry as a result of resource plays and as a result of technology. We’re going to show you a lot of technology today and of course we’ve seen this incredible increase in natural gas production although it’s a very different than productions from the past. Production from the past came from much more high quality reservoirs in terms of porosity and permeability had much lower declined curves back in the 70s.

Today’s natural gas is more than manufacturing process with much higher declines, but much more certainty in terms of many, many locations to drill as you go forward. You can see the projections from the EIA in terms of gas production going forward; they’re predicting it to be about flat at 65 Bcf a day into the next several years. What this meant for gas prices. Well, here we’ve done the cycle, look, and we go all the way back -- not all the way back, but to January 2001, where we had a really nice peak. And so we index that as zero and say what happens when gas prices go through the cycles and go down and go up. So we’ve taken the peak, January 2001, we saw a cycle that had a bottom about 12 months after the peak. And then it rose again and popped up two years after the peak and came back to the next peak not 48 months later and then we have another cycle that began in March 2003, that cycle had its trough about eight months into that cycle and then a peak 32 months out. And then October 2005 another trough that was pretty flat 40% down for a long period, but about 24 months later, we’ve started rising again to a new peak.

The new cycle is not like the old cycle. As you see we come from the last peak in June 2008 and we’ve had quite a trough and the trough has gotten deeper as of late. So, it’s pretty clear that natural gas at least from a historical standpoint and cycle standpoint in terms of that supply and demand cycle we’re used to it’s very different. I think there is a bold and bright future for natural gas going forward, but it’s not the thing to be focusing on today. Just a few more comments about natural gas before we move to oil. What’s the pricing outlook? All of us look at the futures market and we found this to be very interesting information, where you take the historical gas prices for the past two years or so in terms of spot gas prices and if you look from that blue line on this chart what are known, where you can see going forward the EIA pricing in terms of Henry Hub natural gas prices and its a purple line, it shows rising up to about $4 in the next several years. If you look at the NYMEX price you can see that being similar a little under the EIA pricing.

But what’s interesting to me is there is a lower confidence bandwidth at an upper confidence band, and when you look at the options market going forward, you see about 95% of the confidence stays within these bands, But there is more optimism about gas coming up and people putting their money, where their optimism is when gas going down much further. So hopefully this chart is indicative that we’re near the bottom, though it’s not going to necessarily recover really quickly.

If we look at one more chart in terms of trying to cover you downside and we look at that this probability of how low might the gas go or how might it recover. We have one more in applied chart in terms of the natural gas options market and is about a 60% or greater, 60% in the near-term or 80% in the longer term looking about 18 months out. The natural gas prices will be staying about $2.50 in MMBtu based again on the futures market in the option pricing that’s out there right now.

All that said about pricing, how is the market reacting to this? So, we look at the rigs and again we see a very different trend in terms of the past. We see on the chart here looking at all rigs, they now account for about two-thirds of all activity. I’m on slide 16 or 19, I think that's 16, the title of the slide is oil rigs now account for about two-thirds of oil rig activity.

The U.S. drilling rigs going back to 1990, you can see that big uptick in natural gas rigs, where we got up to 1,600 rigs around 2008 and oil rigs were down there pretty low about 200 oil rigs prior to that, but you can see the big ramp up in oil rigs. That’s clearly because we are seeing phenomenal oil prices relative to gas prices and its almost unprecedented differentials in terms of MMBtu equivalents.

On the right side of this chart, we look at the actual percentage of the rigs that are drilling for gas versus oil and you’ll see a similar trend, but it’s actually a much more encouraging trend, because natural gas really come down from almost 90% of all drilling back in 2005 about 30% of drilling is still following right now. I don’t think we’re seeing the bottom in this curve. The oil is now over 60% of the drilling activity, but with oil does come some natural gas, and that can be a good thing in terms of the associated liquids and it’s a very important for you to know what plays where and whether you'll be looking at dry gas or gas is associated with liquid.

The oil processing is very good. If I look at this next chart, the EIA short-term price projections, we can see that forecasting about $100 oil going forward, NYMEX future price is very similar. And again, if we look at this 95% confidence band, we see that there tends to be in terms of the marketplace more upside to the pricing right now than downside.

Finally, in terms of looking at the external industry, I want to wrap up with this slide, I am sorry, next side 12 there, I believe, production from the Eagle Ford shale is nearly 50% of the liquid. It’s phenomenal. If you look back in 2010 roughly you could see about 20% oil and condensate liquids coming out of the Eagle Ford shale and the trend has been ramping up and as of late year about 50% oil and condensate liquids coming from the Eagle Ford shale that’s a phenomenal growth that tells you, you’re in the right place that leads us right into the day of presentation in term of liquids, liquids and liquids. I’ll talk for a minute about our strategic growth with Swift Energy Company.

We have balanced diversity and focus. We are in three core areas along with U.S. and Gulf Coast. We’re very focused in that regard. We’ve got an extensive long life property base with a reserved production ratio of over 15, 15.2. We believe it’s very balanced in terms of spread of the number of properties, number of wells, number of locations, and we diversified across the commodities that most oil and natural gas liquids as well as what we believe that kind of natural gas, the natural gas – it does have associated liquids with it.

We also have a low risk development program with high reward exploration particularly in South Louisiana where we show a lot about our development programs today as well as some of our higher reward activities that are liquids focused in South Louisiana. We have significant resource base – that comes with the assets that we’ve had so many years, 80% of our fourth quarter 2011 corporate oil, crude oil price received in HLS and LLS pricing, we are going to talk about that today, that puts us in a great advantage because most part people look at it – your typical U.S. pricing and cushing, and we actually get much closer to the Brent pricing, we show these some of that today.

Proven reserve and resource plays with multi-TCF upside over 100,000 acres perspective in the Eagle Ford and Olmos. And then significant operational expertise again we’re going to show you a lot of our data in terms of our geosciences, our 3D, the things we’ve done with the technology, and show off some of the actual work products from some of our professionals who are very good at the new technology both horizontal drilling combined with horizontal multi-stage factored completion.

And again it’s very important that we keep a strong balance sheet and the liquidity to be able to adapt to these markets. And take advantage of the opportunity that comes with them. Our corporate strategy has been very consistent from many years, we’ve had a tandem drilling and acquisitions approach, we’ve always been technology focused. We always like to be in areas with more than one opportunity or multiple formations South Louisiana it’s a beautiful place we drill a well and you normally get at least to some times three or four behind pipe completions for your future. And then South Texas we got this beautiful opportunity not only in the Eagle Ford but the Olmos we love to be in where we can both exploit and explore.

We do focus on reducing operating risks and maintaining the right R/P ratios. We like to operate our properties so that we have control of our operations we do operate the vast line share what we are doing and again a diverse resource and reserve base. And not to – to stay away from the fact this is the time where you got to be very excited and make sure that as you look at to your pricing, particularly natural gas and you bring on more liquids as you bring yourself more in line with cash flow.

So we’re going to talk to you about how our drilling programs are built, how we did raise money in the past that position ourselves to have very strong year and not lead too or too concerned about liquidity, but going forward we can assure you we’re focused on the balance sheet and making sure that under the various scenarios that would come out that we would have a strong balance sheet with good liquidity going forward.

At this time, I’d like to turn over the presentation to Bruce Vincent and have Bruce continue with the presentation talking about our strategic objectives.

Bruce Vincent – President

Thanks Terry. Good morning everyone and thanks for being here. What’s Terry and I really wanted to cover today was some of the high points. We really want to spend most time let you see the team and action talking about our core areas and our operations and then what our specific plans are. So what I’m going to touch on briefly is our short-term 2012 strategic objective, what do we hope to do this year and I’m going to highlight some things about our assets by looking at our reserves. Most of you have seen that information in the 10-K, but I’ll use that to kind of highlight some things that we think are particularly important about it.

So when we look at 2012, we want to grow production. We want grow production double-digits. We think we can do that 14% to 20%. Many of you know follow us, thought we had put out a little higher number in the fall, but as we relook at our budgets given the gas prices we really see a complete shift that virtually 95 plus percent of our capital being directed to liquids and that just really means lower volumes and so that’s why we pulled it back a little bit.

The bulk of that’s going to happen in South Texas that’s where 70% to 80% of the capital is going. We think we can grow production this year in a very similar fashion of what we did last year and you will see that in more detail. One of the nice things about South Texas and the assets that we have down there is your inventory is so much more line of site. It’s so much more predictable. It’s so much more reliable and that makes a huge difference in being able to do it and set out and accomplish your objectives because you can look further in advance.

We can directly target and pretty much tell you what we are all, we are going to drill not just this year, but next year and the year after that and that makes a huge difference in planning your business and the predictability of that. It’s a cost business particularly in this resource play as you move into the manufacturing operation you really want to drive your cost down. The lowest cost producers are always going to win in a low price environment. The high cost producers where they can do once get lead it out prices come down. Obviously the gas market we think, gas is going to cause some shake out in the business, what it concerns us is when we look at our own cash flows being 50% liquids doesn’t bother us as much and we got an inventory of projects that we can devote virtually all our capital, not just this year, but the next couple of years in liquid focused area. While we will get some gas with that, the economics are really driven by the liquid side. So, we can let this gas market shake out and it will do that. Historically in this business, we’ve gone through these cycles before and when you get a low price environment, the industry pulls back capital, low prices stimulate demand and over time that brings the price backup. That will happen.

Now, do I think that natural gas is going to have those high prices that we’ve seen before, no, I don’t, because one of the things about this line of sight predictable inventory that many of us we have when gas prices get to a certain level, we all know had a bring at the market and we can do it pretty quickly. But ultimately it’s got to complete for capital for liquid, if you look out several years from now. And what that price is – about how to predict it, but I do believe it in time, you’re going to find gas, volatility reduced in pricing, but it’s going to have a swing that it allow us to complete for capital with liquids because the industry is building its other predictable line of sight inventory for liquids opportunities and can easily devote capital, if the economics don’t like them certainly in the dry gas window.

So, one of the things we’re going to focus on a lot, you are going just quite a bit about it, it is driving our cost down. And one of the things because you are moving into that development manufacturing operation is the number of things you can do both in terms of the efficiency of your development plan, but also on the supply chain side. People in this business that haven’t really moved their professional supply chain management where you are looking at all of the things that you are bring to bear that the drill to produce oil and natural gas is missing both particularly on the cost side and we’ll talk about some of that today. And then ultimately by driving the cost down, working on the volume side, we want to take your per unit cost down and we believe that’s going to happen.

Obviously, we don’t want to forget about our legacy inventory. We think it makes a lot of sense strategically to have a balance between resource plays and traditional or legacy type properties. Our Southeast Louisiana properties and Central Louisiana particularly Lake Washington is 99% crude oil is a wonderful cash count today and they both have tremendous future inventory as well, different kinds of inventories, not quite as predictable as Eagle Ford, Olmos development in South Texas, but it’s a wonderful inventory.

And so we want to maximize that value, extend that life, continue to allow to be a cash counts, and so one of the things you’re seeing us do it, increase the activity particularly in Lake Washington and actually we’re going to increase the activity in Austin Chalk and Central Louisiana as well, which does have some gas, but it’s a very, very liquids rich. It has a lot of good oil that comes with it and the gas has very BTUs of probably two-thirds of the volume stream is actually liquids. So, the liquids actually drive the economics just like they do in most of the liquid which plays in South Texas.

Financial strategy, Terry talked a little bit about that in terms of financial strategy, but particularly given what’s happening in gas market. We believe and we always have believed in maintaining strong financial leverage, where we keep our leverage down, we keep our liquidity up, but allows us to be flexible in difficult times. We have been here over 32 years and one of the reasons we have been here for over 32 years as we’ve always been conservative on the financial side. We think maintaining that liquidity, keeping that leverage down is going to be particularly important as we move into this low gas market and one of the things that –when you look at the hindsight it was obviously pretty smart strategically to do, we did that debt deal in November that allowed us to pre-fund deficit spending for this year.

So that we lot of reasons we did that, they allowed us to go ahead and make some of these supply chain commitments and whether they are rigs or whether its tracking services or other things that allows us to help drive our costs down, but knowing that we can maintain financial integrity while driving our program the way we want to create the kind of growth we are looking at. Specifically for production, I mentioned the 14% to 20% growth after $12 billion Boe, the $12.6 million Boe target, reserve growth we are looking at 10% to 15% again move to liquid changes those volumes side. The other thing that we are all mindful of, I am sure all of you are, and I thought about it is as we move through this year.

The way the SEC competes the gas price we use for calculating reserves on the gas side it’s opt to go down compared to what you had at year end. And so we think that the opportunity is there, I am not sure opportunity is the right word for companies that have the threat of failing to have write-downs, particularly through full cost accounting. But even some of the successful effort companies have had to do write-downs in specific areas, where they are vulnerable in that gas price. And so we want to account for that possibility, we don’t foresee any specifically today, because it’s hard to know exactly what’s going to happen in the future, but we think that threat is there for the industry.

On the CapEx side, $575 million to $625 million kind of a midpoint of $600 million is a good number to use. This particular slide, I won't go through each particular one, but it details a specific guidance for our DD&A, lease operating expenses, general and administrative expenses, interest expenses, severance, and ad valorem and all on a per unit basis with the exception of severance and ad valorem, and that's pretty much along the lines of what it’s been on the severance and ad valorem side.

We talk a little bit about our reserves. Couple of charts, first. I am a big believer in picture being worth a thousand words. We guys talk a lot about balance and diversity at the same time being focused. And if you think about it, it’s hard to achieve balance and diversity while at the same time being focused. We think Swift done a very good job of that. You look at the pie charts here and this is PV10 value in billion of the reserve base by core area over the last couple of years. I think that you can see that impact how we have moved really to even a better state of balance and diversity yet still very focused.

We have three core areas. And on a PV10 value basis, they are balanced and diversified real wells that will allows us to really focus in on creating value in those particular areas. We are not just scattered. You don’t see 10 slivers of the pie, you see three and they are all very significant to us. You look at those same reserves, but on a volume basis what you really see is that growth in South Texas with 5%, 70% to 80% of our capital there last year. We are going to apply at 70% to 80% this year. It’s a very identifiable line of sight predictable inventory. So, we think we can continue to grow that reserve base in large part driven by South Texas, but we want to continue to apply capital into the Southeast of Louisiana and the Central Louisiana East Texas areas.

One of the things that highlighted here mentioned again or by understands the infrastructure problems we have domestically today that’s creating disparity in particularly oil pricing, a barrel of oil and North Dakota is getting $70 at the wellhead in a barrel of oil and South Louisiana was getting $125 a barrel, a pretty remarkable disparity in prices. One of the things we've got almost 80% of our oil, that’s getting roughly $125 a day. That’s a huge difference in terms of your cash flow and certainly helps mitigate the problem on the gas side whereas if you look at the cash market, it's approaching pretty close to $2, so big difference in terms of value.

Again, this information is in the annual report. I really just want to use, highlight a few things that we think are important about understanding our asset base. This really breaks it down by core area, principally on a volume basis. Again, you see the balance and diversity, but you see the real strength coming in the South Texas, but that’s broken up between the Olmos activity, which is liquids rich gas play. Sometimes you have free condensate with it, sometimes you don’t, but generally run in 1,250, 1,300 Btu gas, very, very rich, good economics and it’s much more evenly distributed or the consistency of it is more uniform than you find in the Eagle Ford, where you really have those distinct phases that you moved there, but also the Eagle Ford, which is probably in my view about the hardest resource play in the country that in the Bakken are probably that where you have the most activity, the industry itself is having a lot of success. Swift is also having a lot of success. We have done enough drilling there now to delineate our property and that’s why you will see us really moving much more into the development manufacturing phase, where we can really drive our cost down, because we understand what that asset is now and where it is.

This next slide really is the reserve reconciliation again in the 10-K. I think a couple of things I wanted to highlight there. The revision side everybody always wants to kind of know what your revisions. Well, it’s not a big number and there are two principal reasons for those revisions. One, we basically took off a bunch of vertical PUDs that we had in the Olmos and South Texas both at AWP and Sun TSH figuring that we are not likely to drill vertical Olmos wells currently. We’d be much more at, maybe look at targeting horizontals in that area. We just took those off the book. As the other big number that was in there is in Lake Washington PUD that were at the five-year mark and if you are familiar with the SEC five-year rule, they want to just book PUD, that you plan to develop in the next five years, but also not have PUDs that haven’t been developed in the last five years. So, we actually reclassified some PUDs that were Lake Washington back into the probable category because that was a five-year mark. We just think that it’s a prudent thing to do. They don’t go away, value is still there. We just have to line them up to drill them at the some point in time.

The other thing to highlight, sales of minerals, we took principally our South Louisiana properties along with non-operated property we had in Alabama and a couple of small Texas fields and divested those. And so we were able to grow production in about 20% even including that divestiture of 16 million barrels and obviously the extension of discovery side, that’s where the growth came from in large part that is in South Texas.

Lastly, you see that’s in the chart form in the 10-K, but we just kind of put it up in graphic. I think it’s easier to kind of get the essence of that. The point to make really is the PUD value in terms of PV-10 is all kind of near-term PUD. We don’t have a whole lot of issues with tail end PUDs and everything is five years or less. So, you are not going to have your six, your seven, your eight PUD still on the book. So, we really worked in the last couple of years to freshen up that PUD inventories and again much of it is much more reliable from your perspective. Well, we think a lot of Lake Washington PUDs are very reliable and a lot of value. Understand most people have been asking and you can understand the PUD content and resource plays much more so than the AKM that is driven by geology.

So, with that I’m going to turn it over to Bob, let him start focus in our operations. Again thanks for being here.

Bob Banks – Executive Vice President and Chief Operating Officer

Thanks Bruce. Good morning everyone. Okay, we are going to move into a number of operational reviews. Terry has already gone through the presenters for this section, really be myself, Steve Tomberlin, and John Branca. We will see the bulk of taking you through our core areas and Steve Schmitt is going to come up and talk to you a little bit about South Texas marketing arrangements that we have been able to put in place this past year.

So, we are really going to focus on three of our core areas today. The three primary core areas, South Texas we will spend the most of our time there and then that’s going to be led by Steve Tomberlin and then John Branca is going to review our Central Louisiana/East Texas for you and then Steve is going to come back and really show you a fair bit of detail on Southeast Louisiana assets. Now I will just kind of wrap up at the end of that before we get into our financial overview.

So, before we really start, I was like to talk a bit about our vision and mission, which is very import to Swift. We worked hard on our culture, understanding what we want to be, where we want to go. This is a very bought into vision statement by a very large cross section of the company and it simply states that we are committed to being a premier oil and gas company and a top tier industry performer. So, we take those things very seriously in our day-to-day work. We move in to top Tier, are we top tier, how we know when top tier and so we try to measure ourselves and benchmark ourselves against the best thing of business to understand where we fit in.

The mission to delivering that vision is to being committed to outstanding, operating and financial results by aggressively building and managing a balance portfolio of oil and gas properties. And so, we focus on these things was really every week in our work activity. Supporting that vision and mission, our seven core values that the organization has developed to guide ourselves and how we achieve our vision and mission and that’s starts with stewardship, which is really being leaders of our (VMBB) culture being very good students of our people, our assets, our communities, where we work the environment. We take those things seriously.

We are very committed to an improving culture, where we’re learning and teaching organization, focused on lessons learned and look back and how can we do things better, how can we embrace change performance. We know we have to perform in this business. So we’re very focused on a performance metrics and how we do create value for our stakeholders. And of course how do the passion and integrity really helps us meet our improvement and performance standards. As we have passion as we work and come to work every day, we find that we deliver better results, and we have a very passionate group of team members now in our asset groups and we love coming to work and seeing that enthusiasm as everybody collectively teams together and really understands these assets better than we’ve ever understood them before.

So, what I’d like to do for you to start is just look at 2011, some of our accomplishments and I’d like to tie those three of our core values, performance improvement and stewardship. Just to highlight some of the things we think we did that are worth recognizing. So, how did we perform on the production and reserves 2011 increased 26% over 2010 levels. That’s the second highest U.S. production volume in the company history, its second highest production growth rate since 2000. South Texas production grew 77% over 2010 while a big increase for South Texas and we think 2012 is poised now to deliver the highest production volumes in the company history.

On the reserve side, we increased our reserve volumes 20% over 2010 levels, and that’s taking into account a divestiture of our South Louisiana assets. So, if we ought to get those Louisiana assets back, then it would be a much bigger reserve increase. But that represented the largest year-end reserves position in the company history, and South Texas reserves grew 62% over 2010 volumes.

So, how did we perform on the portfolio. We expanded Austin Chalk position, our original AMI with our joint venture partner, has been extended to 79,000 acres. We entered into a second AMI that covers almost 96,000 acres. We have a very active leasing program in this Chalk trend. We put together 105,000 acres so far. We’re continuing to lease position in that play. As I mentioned we sold our non-strategic South Louisiana properties for a purchase price of $53.5 million and we transported all of our future plugging and abandonment liabilities with those properties.

And as Terry and Bruce both mentioned, we have negotiated arrangements through whole of our Eagle Ford dry gas acreage. At Fasken, we have 8,300 acres there – some of the highest quality Eagle Ford rock in the trend. We have now earned all of that acreage position through our drilling commitments, so we have no more wells to drill there until we are ready to drill.

In our Southern AWP acreage, we have about 31,000 acres of Eagle Ford that we would categorize in the dry gas window and we’ve negotiated extensions on those leases by drilling liquid rich Olmos wells in replace of Eagle Ford dry gas well. So, kind of a win-win for everybody. It was a large piece of work. Our land department did a great job restructuring our agreements that was a lot of work we were doing in the fourth quarter – third and fourth quarter of last year, get ourselves into the position where we can present what we are going to show you today. And as both Terry and Bruce said, we have no dry gas drilling in our current three-year plan scenario.

Had we performed on drilling and completion? Well, we drilled 12 horizontal Olmos wells, 26 horizontal Eagle Ford wells. We have spent a lot of time this past year with our 3D seismic data set. We are going to show you some more of that today. We did a lot of micro–seismic work that’s proven to be very useful for us, lot of production logging in course of our history matching back to our pre-drilled models and we have taken a number of bottom-hole pressure survey. So, all of this work that we did this past year really has allowed us now to understand our assets much, much better, and we’ve developed non-unique, declined models that we track each well against really on a quarterly basis.

So, we have a very good understanding by some of the work that we did this past year. We also reinvigorated the drilling down at Lake Washington with some medium depth well. So, Jelly Bowl and Hershey were very successful projects for us, that’s up more running room in Southeast Louisiana. We are going to be talking more about that today.

Of course, infrastructure, we think we performed on our infrastructure last year in South Texas. We negotiated and executed new AWP gathering and processing agreements with Southcross Energy. We now have 90 million cubic feet of firm gathering and processing capacity. We commissioned that on September 1, 2011, that system has been working very, very well for us.

We also negotiated and executed new gas transportation and processing agreement for the SMR oil area of AWP with DCP Midstream. So, we have all of that taken care of, and as most of you remember we did have a pipeline interruption on the Meritage system last year coming out of our Fasken Ranch area and Webb County. As a response to that, we’ve worked with on Meritage on a whole new integrity program for their system, but we’ve also developed a backup system for Fasken Ranch to mitigate any potential further interruptions on that Meritage line.

So, our guys did a very good job getting us a backup plan. We’ve tested the backup plan. I’m happy to say it’s worked very well for us. We talk now about improvement as one of our core values of starting with cost effectiveness. We have implemented a number of changes in our drilling and completion, designs, and approaches, and in the drilling side, we’ve really brought a drilling cost down about $0.5 million of wells through some changes that we’ve implemented in our designs in the way we eliminate some of our different hole-opener runs as we run our long strings of pipe in the lateral.

And on the completion side, we captured over 500,000 a well by reducing the gel loading and acid volumes that we’ve been putting into the wells. One of the things we’ve talked to you little bit about is we did do a direct supply chain initiative to input some of our high strength proppant from overseas. We’re bringing that proppant into now below wholesale, which has really brought some of our cost down. It’s been a very good win for us and associated with that we’ve instituted our own logistic system to manage and truck that proppant, and store that proppant and deliver to well sites in time for our fracing operations.

So, all of these things have led to some very good cost improvements on the completion side. And we’re going to talk to you some more today about additional savings we’re going for on the pad drilling and the zipper frac approach. Steve is going to get into little bit more for you today.

So, we also in South Texas did something that’s a little bit unique in the industry. We’ve installed what we call a drilling operation center. We call it the DOC, supported by communication tower and high speed wireless communication system. We have state-of-the-art systems for monitoring our drilling operations 24x7 from the central location. We have reasoning software associated with these computer systems that the text potential problems in real-time for.

So, we are looking using the systems and software to look for a possible washout, any twist-off things that might be getting ready to occur and stuck pipe risk, any well control issues that develop very quickly down hall in advance of our company people on the rig four being able to understand what’s happening. And we think that reasoning software has really helped to spring our non-productive time down in our drilling operations.

And then of course, the 3D seismic set that’s all been integrated to our SMT workstations and visualization tools and we plan and drill our current wellbores using this visualization tool. So, we can steer those wells using the best 3D seismic data that we have right there communicating between the DOC in our Houston office.

Improvement on the strategic growth side, we have enhanced our exploration organization and we did form a new acquisition business development team to attract, develop and evaluate some new liquid rich opportunities. We are particularly focused on some new resource plays and some types and carbonate, type reservoirs where we think we can use our horizontal technology that we have been working so hard on in South Texas as well as evaluating joint venture opportunities and some acquisition candidates. We’ve improved on our organization development. These are important things to us having a very strong and healthy workforce. We really have an initiative what we call making Swift a great place to work which is important to us.

We have done a lot of work on succession planning for our key positions. We have done a lot on career path development, where we have technical ladders as well as managerial ladders, professional development plans have been put in place for a lot of our key personnel, especially some of our younger personnel, and we got into competency assessment tools where people can evaluate themselves on various competencies as to whether they would progress against the technical ladder or managerial ladder. And then we apply corresponding training to those assessments and we developed a formalized mentoring program for some of the younger staff to bring them along and help them find their best career path in Swift Energy Company. So we are very proud of some these things we are doing.

On the Stewardship side, I want to talk a little about our HSE, I am particularly proud of this one, we’ve worked hard on this. We’ve implemented a behavioral base safety program and we are now measuring ourselves and benchmarking ourselves against the industry and what’s part of TRIR, Total Reportable Incident Rate, these are rates over 200,000 man hours. We include our contractors and our employees. We reduced our TRIR from 2.3 in 2010 to about 1.7 in 2011 that’s 25% improvement. So we thought behavioral based system is paying off for us and also we’ve reduced lost time accidents, they’ve gone from 10 in 2010 to 6in 2011. And we did all that while we doubled our rig count and activity and that’s a 40% improvement. So, we think we are being good Stewards with some of the programs we are putting in place there.

We are also what we think kind of leading edge of all the players in the Eagle Ford on the way we are implementing our air permitting protocols and processes and the way we are working with the TECQ. And we have developed through this process and being leading edge, very good reputation and very good relationships with TCQ. I think this is a very important area for the Eagle Ford. I think some operators don’t treated this as important as others. We are proud to become on the leading edge of how we're handling our air permitting issues. And we developed some enhanced HSE systems. I have spend a lot of time training people on enhanced investigate, incident investigation. So we understand when things go wrong what happen and we can correct those things that will be a learning organization.

All of our people in the field now are (indiscernible) in coding, when they are working on a shift for Swift Energy. We developed a safety award program that incentivizes people to meet specific safety performance targets. We put field safety coordinators in place, assigned them with the drill – within the drilling organization and within the completions organization and within the production organization, so they are there with our staff, working on the safety 24x7 and we have also developed lot of procedures for safety on a various operations discussed here. So, with that behind us, I want to talk a little about 2012 and kind of setup where we think we are going for the year before we get into detailed asset review and maybe before that, I want to just show you one slide that – (indiscernible) put together for us. That really shows a leveraging of Eagle Ford acres to enterprise value.

And you can see what the chart show us is Swift really is kind of leading the way on leverage. And what this really tells us is we have almost 41 net acres per million dollars of enterprise value. That’s the highest of the Eagle Ford players who have more than 60 million barrels oil equivalent booked as of year 2010.

So, if we like the Eagle Ford, we think we are well positioned in the Eagle Ford for you. As Bruce mentioned 95% plus of our 2012 drilling is really targeting to the oil and the high condensate areas of the Eagle Ford. 57% of our 2012 CapEx is allocated to Eagle Ford development and we’ll have 4 to 5 rigs at any given time working the liquids-rich areas, two were probably in the LaSalle County acreage the most of the year, this year.

So, what we think that will translate into for South Texas is some good liquids growth. And so what these charts are showing you are projected net daily production rate growth. So, on the left hand side, you are seeing how we are going to grow our oily production from the beginning of the year to the end of the year, and the splits between Eagle Ford and Olmos on the liquids. And so we see – we are projecting about a 38% growth in our rate.

On the gas side, we are seeing about a 9% growth in gas rate associated with that liquids production. We take that same kind of look in Southeast Louisiana. We think we can grow our liquids rate by 12% and we see a corresponding decline in associated gas of about 12%.

In CLAETX, with our Austin Chalk drilling program, we see a liquids rate growth of about 100% and corresponding associated gas growth of about 90%. And then if we roll it all up with our base and our other properties, we think that means that our total corporate liquids rate will grow about 34% for the year and our natural gas rate will grow about 3% for the year.

And if we look at the corporate projected net daily rate by key focus area, you can see over the three-year period kind of how we are growing our production. You see down at the bottom, the orange is our almost kind of staying pretty level. You see the big trench of growth really coming out of the Eagle Ford that next wedge and then the blue wedge you really see very good like Washington contribution to the profile going through 2012, and then the red is the Austin Chalk program just starts to expand in the second part of the year, that’s really due to timing, but we all expect to see that red wedge grow as we go into 2013.

Okay. Moving to slide 50, I want to touch a little bit on reserve adds. And what I am doing here with this slide is showing you 2012 reserve adds by looking at it two different ways. On the left side, the pie chart really shows reserve adds by the phase of the property. So, what this is telling us is our reserve adds in the company 62% are going to come from oil properties, what we would classify as oil properties and 38% would come for what we would classify as condensate or gas condensate properties. So, that’s a phase comparison when you translate that over into the right hand pie chart that just shows you the reserve adds by product or stream coming from those two different property mixes. So, from that, you see some nice contribution of oil 37%, nice contribution from natural gas liquids 23%, so about 60% liquids, then about 40% associated gas with those liquid streams.

Then if you just look then at proven reserves comparison 2011 versus 2012, as we talked about on the conference call if we look at the phase grouping again, on the left hand pie chart, 2011 basically shows you that of our reserve bookings – our proven reserve bookings, about 21% are coming from dry gas properties, 28% are coming from oil properties, and 51% are coming from gas condensate properties. And so rolling forward into the end of 2012, we show how we think that’s going to change. We’re growing nicely the oil properties component of that reserve base about 36%, the gas-condensate shrinks a little bit to about 47% and we’re driving our dry gas wedge down from 21% to 17% yearend bookings.

So, our today’s focus really is going to talk a lot about South Texas. We probably spend about an hour on South Texas, the Eagle Ford Shale. As Bruce mentioned that’s a multiple year horizontal development program. We have oil, condensate and gas in the Eagle Ford. Our 2012 to 2014 focus is purely on liquids rich growing at this time. And then in our AWP Tight sand, we have again multiple year horizontal drilling potential and there we have oil, condensate and rich gas opportunities.

Southeast Louisiana, basically our Miocene Sands, Bay de Chene and Lake Washington, this is oil and High GOR Oil and a great opportunity set across a range of risk and reward categories for U.S. And then in Central Louisiana/East Texas, this does have the potential for some multiple year horizontal drilling and potentially the Wilcox, we will touch on today a little bit for you and these are very good oil and High GOR Oil properties.

And just to put that in map view of what you’re to look at today. First South Texas, you can see down there in the orange that counties that we’ve been most acted in, particular the three field areas that we’ll talk to you about mostly today AWP, Artesia Wells & Sun TSH and Fasken areas. You can see the 2011 production and reserves for South Texas core area.

And then we will move up to Central Louisiana/East Texas. You can see the places that we are working there. The Brookeland Field, Burr Ferry that we’ll talk about Masters Creek, all Austin Chalk Field and then we’re going to touch on a little bit today South Bearhead, Creek where we think we had some nice Wilcox potential. And then moving lastly down to Lake Washington and Bay De Chene, what we call a SELA Southeast Louisiana, where we have very good oil production and good reserves, booking as well as lot of PUDs to continue to develop in that asset area for us.

Last slide before I turn it over to Steve is just some assumptions. So, that we clear that up for you. You’re going to see a number of economic analyses. You’re going to EUR estimates a lot of that data is going to come at you. And so what I want to do is set the framework on the pricing decks for economic evaluation. We started our pricing in 2012 at $95 oil and $3.25 Mcf natural gas pricing. So that gives you a frame of reference to the numbers you’re seeing. Our EUR estimates are not equivalent to our SEC reserve bookings. So, we want to be sure that there’s not any confusion with that. And then we’ve really rounded off a lot of our acreage numbers and IP numbers to kind of ease the presentation, so we are not too detailed on very specific numbers if you go through the different models.

So, with that I am going to ask Steve to come up here and take you through South Texas.

Steve Tomberlin – Senior Vice President, Resource Development and Engineering

Thank you, Bob. Well as Bob said, we’re going to spend about an hour on South Texas, which means we are going to go through a lot of data, but I think that’s appropriate because the 2011 unfolded, our understanding of the Eagle Ford and Olmos the phases, the different production characteristics, the different operating characteristics has really been enhanced over that years time. So, what we will do is, that the big things, that we are going to talk about is going to be the nine models and the data that we used to come up with those nine models, is not only Swift wells its also a bunch of the offset wells that are nearby our acreage.

We will talk a lot about our operating efficiencies, the drilling and completion side, which really leads off with having a great quality 3D seismic set and having some great people to work that seismic set, so that we can put the wells in the right place, which is very important and John Branca will give us a lot of detail on that. And then the other thing is, as you all are aware in 2011 we did have some marketing problems. We think we are in much better shape for 2012 and Steve Schmitt will come up and talk about that in all three counties.

Here’s just a quick overview map. You can see in McMullen County, in that big piece of acreage there, we have all three phases oil, condensate, and gas and LaSalle County where over 50% of our wells are going to be drilled in 2012. It’s in the oil and condensate window. And then Fasken is out there in the dry gas we’ve already talked about that that we actually have that acreage earned, but we will show you how good those wells are because they are tremendous wells.

So, we already talked about liquids focus. We are going into the development and manufacturing stage. You are going to see some diagrams about our four well pad program that’s going on right now. We are real pleased. We are about 25% of the way through that program and seeing some great results. Also, we will tell you that from this point on, we aren’t drilling any single appraisal wells. One of the things we talked about the last couple of years as soon as we go out there and drill a single appraisal well because it takes a lot of money to hook it up, it takes a lot of time to get it to the market that those costs had been a little bit higher. You are going to see some dramatic decreases in costs from what we showed last year and we’ll go through each of this specific nine areas and show specific costs for each of those.

And then last, again, Steve Schmitt will come up here and tell you about our market out. We’ve got firm transportation in almost every area plus in the lot of areas we already have secondary interruptible connection though we think that those issues that we had in 2011 are not going to show up in 2012. We’ve already talked about this in our three year plan. We have actually less than 1% of our wells will be in the dry gas area that 1% comes from the fact that we’ve just finished drilling in our last Fasken well probably over a month ago so from here on out no more dry gas wells at least for three years as a matter of fact internally we had a five year plan and we see no dry gas wells in South Texas throughout the hole five year plan. So, something is really unique to Swift as we can turn and go to liquids pretty quick and then for some reason the gas prices turnaround. We got a lot of great acreage that we can turn back around and hit the gas if we need to.

Just talk about this so after we classify the areas almost 70% of our wells over the next three years in South Texas are going to be in the oil window something that’s really going to have a dramatic increase in our oil percentage out there in South Texas. Here is actually an overlook of the nine models you’ve got the six models that we’re going to concentrate on in the three year drilling program. You’ve got the approximate IPs and Boe, very importantly the percent liquid and then you can see the number of projects that we have slated in each of those models and as Bruce said these are very firm in terms of really knowing what’s going out there in each of these areas though we can count on the fact that these opportunities are there.

Then if you look at the things that are excluded from three year program you can see they all say gas, either rich gas as far as the Olmos is concerned and then the two dry gas areas we have and only one well that last Fasken well that has already been drilled and is waiting on completion. This is a little bit different way to show how the production is going to change in South Texas as we come into 2012 right now probably mostly because of Fasken and the very high rates we’re getting there. Our gas percentage as far as total production is 69%. As you go throughout just this first year and you get projected January 2013 that gas percentage would drop from 69% to 59% and correspondingly the oil comes up almost that same 10% from 15% to 24%. So, you can see in just a very short period of time we can make a dramatic effect on the liquids percentage in South Texas.

We had put up a diagram that we talked about last year. In any new development you go through early the evaluation, data capture exploration phase, and once you’ve done that you get into the appraisal phase and last year when we talk to you we’re really in the appraisal phase.

Then you go into the development and manufacturing, really if you like that’s where we are right now. We understand the properties. We understand the geology of the properties. We understand our drilling costs. We know what we need to do to keep those costs low and going lower. So, we’re really moving into that manufacturing process. A big part of that process is no one where to place the well. So, John is going to get up and talk about the 3D seismic. He probably has about 10 very interesting slides that will show you how he and his group help us in putting the well boards in the right place.

John Branca – Vice President, Exploration & Geosciences

Thanks, Steve. Good morning. What I’m going to show you is some 3D seismic that we have and how we steer and place these wells. It’s critical to our development of these properties. This is a 3D visualization of our 3D in South Texas at AWP field. Before I talk to you about this, I’ll tell you that we have a substantial size in the database and we talked about this in past years. We have 4,000 square miles of 3D seismic in Louisiana and about 800 square miles of 3D seismic in Texas.

We process this very high hi-tech processing and we’ve created these images. And that’s all very exciting to us as geoscientists, but in terms what it can help us do it helps us visualized where these formations are and it also helps us plan and steer and drill our wells. Now, this image here shows a number of things. You can see we have mapped three horizons in this.

We map dozens of horizons in the 3D, but these are three particular ones. This blue plane here is a false that we turned on. We’ve got a well trajectory here that steered into one of these zones and you can see the structural complexity and some dry peers in this. We can rotate this, look at this at any direction and it helps us understand exactly where to place the wells, which is critical giving the good production and good recovery.

I want to build this up a little bit just to see understand the – what we can do with this data. This is a conventional map here on the right and this is the map that every geoscientists makes and it’s a two dimensional map and you have these contours and the colors show the depth of the formation. This is not on the top of the Buda, which is the formation of (map), which is what is actually the base of the Eagle Ford formation and helps us gear into that.

These brown lines here are faults showing the offset. And so, it gives you a good view, but you really don’t have a feeling for the significance to the faults. The faults on this map on the right looked pretty similar in size. Here we go to a 3D view and its mapped, this map and this map are identical, they are absolutely identical, we’re using a different visualization.

In this visualization you can see the three dimensions. So this fault here which is this fault here, you can see the size, a huge fault, several hundred feet versus the faults here, which are just a few tens of feet. We can also see on this and I’ll show you on the later slide some texture in the 3D view, which is actually some fracture patterns, which are critical to our well our production.

And now we have a couple of different views, this is a coherency volume. You know what coherency does, is this gives you, this is a structural view and these two maps remain on the same horizon, but they’re different tools. And this one gives you a structural view. And so, in this you can see that a very large faults, I pointed out before, another faults here and some smaller faults that are radio faults into these others and then the textural pattern and this is really a fault and facture indicator.

And what we use this for is here we have planned a couple of wells and these wells have come down here and drilling upwards in the well towards this fault. We don’t want to cross that fault. That fault would cause potentially drilling problems, also the in depth on the other side of fault in another formation, which would not add any production. So, this is a fracture and fault indicator. Now, we've taken the volume and we’ve correlated with the wells and so now we can tell you what the rocks are like and this illustration here is identical horizon. You can see the – here which is this fault and you can see here this fault, you can see the differences in colors. And this color is Porosity indicated that we calibrated to seismic data set. So, we can place the wells in the best structural position, we can put them in the highest fracture density and then we can put them in the best rock. So, we get the optimal performance from these wells and we’re seeing this in subsequent performance as we start to produce these wells with this very, very detailed placement.

Now, what I’m going to do next is I’m going to take these two surfaces and these two maps and combine the two into a total view. And so what we’ve done is we taken the coherency volume which is the structural fracture indicator and you can still see those, see the faults and the fractures. And then I have overlaid the Porosity volume and so we can use this, we collaborate with the drillers, the people in the field and we take this and we plan our wells very carefully, so that we get in the best position with along with laterals in the best rock. As we start to get this resolution and data we start to find things that we would never seen without the 3D and we actually see some small pools on this formations. And so in order to enhance the wells we optimize and we plan we them we actually have turn this wells nor for vertical and then back down so we stay in the best zone of the Eagle Ford.

By drilling the early wells we’ve identified which parts of the Eagle Ford to the best that where we place our laterals and we try to stay in that. We have people at the rig side looking at the rocks. We had the drillers, we have real time logs and so we can plan these wells and then we follow them as we drill them. I show you a drilled well right now. So, this is a slides seismic on this is more conventional seismic on this slides and the dash line here in blue is our planned well, and this purple line here is the well as drilled. This is the Eagle Ford formation where were targeted. We are trying to stay down here in this zone here and we can see we pulled up the well bore here and then brought it back down to stand that maximum placement.

Now, what happened just after this well we had to move our surface location resource slightly because of some issues on the surface or (indiscernible), so we did do that, but didn’t affect us because we planned the well. We got down here we made our turn and stayed in zone and right on top of plan. We had a few were off the plan just were so slightly that totally insignificant. This is a great well and so we drilled that out to total length as planned, doing this real time the whole way. After we drilled well this is the well we’ve drilled and this is the well bore here and this is the log. And so we’ve a number of curves and data that we collect as we are drilling and this resistively curve here and we have a gamma ray curve here.

So, we drilled the well, once we drilled it, we completed, and we do multi-stage fracs. This well has 17 frac stages and these are purple dots and the stages all across the wellbore. We have collected and recorded data in this well bore, Microseismic data. The Microseismic data, the different colors represent different frac stages, the circles represent the rock breaking. We are recording this rock breaking what this does is it allows us to see what kind of fractures are we creating in the earth. What kind of connectivity are we getting into that porous rock with the hydrocarbons in it and so we can see how well we’ve done.

In this case, we get a good spread around the well bore, and so we feel we’re confident. And also is letting us know how closely we can space the wells together and you might have – we started out at about 640 acres spacing, and then we downsize. This will let us know where we get our maximum production, and our maximum recovery. We then go in where we run production logs in here to see how each of these frac stages perform, and that helps us completely close the loop on our understanding. So that’s how we are using this 3D data and the seismic and the well planning in the microphones. That’s it. Steve.

Steve Tomberlin – Senior Vice President, Resource Development and Engineering

Okay, thank you John. So, what do we do with all the stats, what does it result in? It’s been a great presentation by John and how much planning goes into these wells and how much collaboration there is between the geosciences, the reservoir engineer, the completion engineer, and the drilling engineer. And earlier you saw Bob talk about the drilling operations center, so you’ve got great planning, and then as you are executing you have leading indicators as to whether or not you are going to get yourself in trouble, whether it’s step high, the wash out, loss circulation and the people on the rigs didn’t have that advance warning, so they can stay out of those particular instances that give you the non-productive time.

So, now what we are going to do is we are going to go in and see what that means for drilling efficiency. And we have got a series of curves here that are actually on the Y axis' debt and on the X axis' days. The first one here is LaSalle County and what you have in here is what we have done in 2011 in terms of cutting the drilling time for our wells. So, you can see back in the second and third quarter of 2011 in LaSalle County, it was taken us about 25 days to TD these wells. The last well that we drilled here in LaSalle County, it took us about 10 days less or 15 days. So, you can imagine what that translates into well cost savings that's driving our cost down. You are going to see several other plots and it’s the same type plot talking about different areas.

So, the next one is McMullen and even a much more dramatic improvement there as we have gone from anywhere from 35 to 45 days, all the way down to a little less than 20 days. So, again the efficiency with what John is doing and what Homer Adams who is our VP of drilling is doing with the drilling operation center is really working in our favor right now. We are still in McMullen County and now we are looking at the Olmos. The Olmos is about 2,000 foot shallower than the Eagle Ford. You think that it take a little less time to drill it, but it actually drills a little bit slower than the Eagle Ford does, but we still have been able to drop our times from 25 to 32 days down to just over 20 days.

And then this is another dramatic, the Olmos condensate area which is a little bit further south and little bit deeper, same type of story. This type of planning, this type of focus on execution, having the right people in the right places, the right people on the rigs is really paying off for us, and I’ll show you what it done to our cost here in just a minute. But it’s not just on the drilling side that we are making big strides. As you know, we have had a dedicated frac crew for the last year in three quarters then we really are pleased with that relationship and have seen some really great results in terms of knocking down our a non-productive time and actually showing some great results on the safety side.

As a matter of fact, our contractor had a big safety celebration just about a month ago, where Randy Bailey, our VP of Production went down, and he was really taken by the fact that, that particular crew was really happy to work for Swift because of the relationship that we had with our service provider and we think that’s extremely important all the time, especially going forward as gas prices have gone down, we need to make sure that we have that relationships.

The first slide on fracing that I want to show is our stages per month. It’s pretty easy to see the improvement there to where we are up to about 60 stages per month. About two years ago, when we first started frac and Randy Bailey came up with a little jingle that said do we want to strive for five, which meant we wanted to do five frac stages in a 24-hour period. We are actually, I got my Jack, that I have only wanted once, may be twice, and now it’s antiquated, because now routinely we are getting seven stages a day. So, we are going to have to come up with a new slogan or Randy will especially after we start doing the zipper fracs, which I’ll show in just a minute.

Here is just some of the things that Bob already mentioned and I am not going to go through, which you can read it, but a lot of good work on the design side to lower the cost. What you have on top, there is actually a well board diagram? As you steer the well, you probably can’t read it but these are the different formations. This just happens to be the measurements that we take as we are drilling and then these bars right here are the actual places where we put the perforation for the frac stages. And a lot of work goes into the completion in terms of looking at this data seen where you’re in the right spot with the right process and then making sure you place your perforations correctly. And so, where does all of this lead to in terms of costs?

So, here’s the next slide. What you have there is you have the dollars per stage on the left hand side, so, that’s in the dark blue and the light blue. So, you can see our dollar per stage has gone down to about, I think it’s exactly about $227,000 of stage coming down from over $327,000 a stage in the first quarter of 2011. A lot of that has to do with a non-productive time.

The yellow bars there are non – average non-productive time in hours during the frac job. So, you can see it was – we did pretty good in the first part of 2011. We had some problems in the later part of the year, but we’ve had some really good quarters in 1Q and what we expect to have here in 2Q. So, here is what I wanted to talk about the cost. I think the last time we got together when we said – what sort of development cost going to be and we coated a number of $8.5 million to $9.5 million.

Actually what we do now is we look at the nine different areas and we track each area because they are all a little bit different. What you got here is a range, I kept the million dollar range, but the numbers here are actual cost that we just had with some of the wells that I showed you at the drilling cost on – the drilling curves the base versus depth. So you can see it ranges anywhere from LaSalle County to just a little over $7 million up to some higher numbers, which is its Eagle Ford, Condensate and McMullen.

The reason why that’s higher is a lot of those wells are right there on the re-trend. When you get in that re-trend, they get a little more tricky in terms of stirring the well. So, it takes a little more time. The other two outliers are down here in the Eagle Ford dry gas and the Olmos rich gas in McMullen that’s because those are deeper. As a matter of fact, we talk about the fact that we are not drilling any dry gas wells over the next three to five years that’s because we will be drilling the Olmos Condensate up in here and actually it’s – we’re really surprised by our last Olmos well in the Condensate area, it came online at 3 million a day and 720 barrels at Condensate a day.

So that’s over 240 barrels per million yield at the surface. So you are almost getting to be where that’s an oil well. So, we are really excited about the fact that through continuous drilling clauses in our leases will be able to hold all that Eagle Ford dry gas acreage while drilling some very, very rich Olmos Condensate wells and a few Olmos Rich – oil wells.

Okay. We are going to go through a little diagram here. This is what we call in our next phase of efficiencies and cost reduction, and we are actually in the middle about a third of the way through this program as we speak right now. We’ve got one of the walking rigs down there, drilling a sequence of four wells. What we do is the first phase as we drill all the surface holes with water based mud.

Surface holes usually go down to about 6,500 feet. Now what’s interesting here is when you do this you are actually moving to rig by 20 feet. A normal rig move if you have a conventional box-on-box rig down there, might take you four days to move that rig, so that could be couple of 100,000 dollars. With this walking rig, the first move from the first well to the second well took 29 hours. The second move from the second well to the third well took 18 hours, and we just finished the surface hole on the third well and we are getting ready to go to the fourth well.

Talk to our drillers just yesterday and said how is the program going, and what do you think you say so far in terms of this type of program versus the conventional box-on-box moving a rig. And right now even though we’ve only done the three surface holes. Their tally of savings is $415,000. So, a little over a $100,000 of well and we’ll just a little ways into this program. So after we get the surface hole drilled, we then switch out all the equipment and we switched out the mud.

We go to oil base mud and we come back the other way. We drill the well all the way up to the lateral, into the lateral and then go back all the way to the first well and finish it. Then when we do that we start the frac and that here is what we call a zipper frac. We do two wells at a time. I have got another slide I am going to show to you that’s a little more explanatory. We finished those two wells and then we jump over and do the next two wells and as you can imagine tons and tons of equipment out there, you can put it in one spot, get it manifold it up, you don’t have to move it around, you really start to gain some time efficiencies.

The other way that you gain time efficiencies is in the zipper frac. So, when you do a typical frac, if you’re doing one well by itself, you go in, you perforate the toll of the lateral, you’d frac that particular set of perfs, you go in set a plug, then you frac and perf and frac the next, you just do that sequence all the way up. Well, it takes about as much time to perforate and set a plug as it does to actually pump the frac. So, what you do here on these zipper fracs is you’ll start, you’ll perforate and frac, while you’re fracing the first well you move that perforating equipment over to the second well. So, you’re doing that simultaneously. So you start to cut your time almost in half and then you just continue that process. Frac the second well, go back to the first, at the same time perforate the first well, back and forth and back and forth.

What happens there is your frac efficiency in terms of time will increase anywhere from 30% to 50%, when you increase that efficiency you decrease cost. So, where do we think this is going in total? Right now, we feel like that on the drilling side, we can save about $250,000 to $350,000 a well and on the frac side it’s possible that we could save another $350,000 to $450,000 a well. So we’re looking at it. This works for us operationally. We can take those costs that are $7 million to $8.5 million drill complete and equipped down to maybe $6.5 million to $8 million. So, that’s the next step that hopefully, this time next year we will be talking to you about even lower cost.

Okay. So, that’s where we are on getting the production out of the wells and so Steve Schmitt is going to come up and talk about, where it goes from there.

Steve Schmitt – Vice President, Energy Marketing

Thanks, Steve. Good morning. We thought we follow-up, excuse me some of Bob Banks earlier comments about infrastructure and show you a little more details about some of the infrastructure arrangements and also some of the infrastructure in and around our acreage in South Texas.

Of the first slide we show here, this is focused on Northern part of the AWP area and starting at the top you can see a line, the DCP line. Historically, our production up in the Northern part of AWP at the SMR lease was connected into enterprise, but recently we connected that lease to DCP. Now, if you are not familiar with DCP, DCP is one of the largest midstream players in the country and it is the joint venture midstream company formed by the combination of Simple Energy formerly Duke and ConocoPhillips. So, we entered into an arrangement recently in the first quarter with DCP that provides for the transportation and the processing of the rich gas production from this particular lease.

Now moving to the centre of the slide, where you see PCQ. In that particular area, we have the PCQ area and (Technical Difficulty) connected into the Houston pipeline system by virtue of the Swift gathering line and at that particular point our gas is transported downstream to processing on the Houston pipeline system. You maybe familiar with Houston pipeline its part of the integrated transport company its very large intrastate pipeline system here in the state. And also at that same point their enterprise is very close, so we always have the flexibility to make our connection with enterprise they’re very proximate there to that particular delivery.

If we move to the west or to the left on this particular side, you’ll see Y Bar. We are currently planning to build a line to the east to support upcoming development in the Y Bar and other leases in that particular area there. Such that we plan to connect into almost northerly connection point with Southcross. So we can access the firm transportation and processing that we have on the Southcross system. Also, interesting enough in that same yard we currently also have active connections with both Enterprise and Houston pipeline as well. As you can see we have a lot of infrastructure here in the northern AWP area that we can access.

Now next slide we took a – we step back and took a, we zoomed down and took a wider view of the greater AWP area primarily to focus on Southcross here. As you might recall we entered into an agreement with Southcross last year that provides for 90 million a day of firm processing and transportation from the various delivery points we have established with Southcross in AWP area and those particular blue dots on the screen those represent the several delivery points we do have at Southcross. Now we still enterprise the system that we historically delivered much of our AWP area gas into its still there obviously and we still have those active delivery points that are there with enterprise as well.

The next image you see here this is related to the pipeline options we have for our Fasken area. Now our primary average for the gas production from the Fasken area is still the Meritage systems. We entered into an agreement that we announced back in -- I think of the fourth quarter of 2010 what we announced we had contracted for 40 million a day a firm capacity on the Meritage system. But Bob alluded to some operational form Meritage had last year. So as a backup we have built a gathering line to a nearby system calling Nevada gas gathering and that is a gathering system that is operated by Louis energy and nearby operator and that system delivers gas into the energy transfer system, which we mentioned earlier. And so that provides us a nice secondary outlet for our gas production from this Fasken area should be operational problems on Meritage.

Now this last screen we are focused – our last slide we are focused on LaSalle County. And we may look a little busy up there especially in the Northern part. Frankly that’s good so that’s shows us a very extensive pipeline network up in this area and we probably do is show you that there is a lot of pipelines right there – in and around our acreage there in LaSalle County and I will just talk about a few of those pipeline options there and I will tell you that we are currently in negotiation with pipeline with some of these pipeline in this area to secure firm transportation and processing for our gas development here in this particular area. Just kind of for this move around the slide here at the very top right you see Teak Midstream.

A Teak is a Midstream company that was founded and is now lead by former executives of CrossTex Energy and Teak currently is building a 200 million a day plant, a processing plant over in B County. And then they’re building a pipeline system for B County that’s traversing several counties across Texas and that line terminates here as you see it in the LaSalle County. Good news obviously is the passes right through our acreage and provides a potential opportunity for firm transportation and processing in our system.

Moving just south of there just down the slide there, you’ll see Kinder Morgan Copano JV lines is noted. That’s what they call their Eagle Ford gathering system or this particular system here wining the service in August of 2011 in access of several processing plans down along the Gulf Coast. And as you can on the screen there by the black dots and the strip lines that are on the screen to the left and the right and then to the upper left. You can see that we’ve already laid a couple of lines over to this particular system and those black dots represents active delivery points were currently delivering gas to that particular system.

Also you’ll note that the enterprise has two lines that run across LaSalle County right through here these are two new 24 inch lines they built as part of their expansion to serve the Eagle Ford and as you can we already have down towards the bottom left you can see we’ve already established one delivery point with enterprise and other discussions were ongoing, again the advantage of much of this infrastructure is that it passes either directly through or as near much of our acreage, so is very accessible for our future development out there.

Those are the few slides that I want to pass through to show you to highlight the infrastructure out there and I think that the feeler that is we have multiple opportunities out there of outlooks for our gas through excess processing for our rich gas development plan for the coming years. Steve?

Steven Tomberlin – Senior Vice President, Resource Development and Engineering

Thank you. Okay. Now we’re going to get into the nine models and you’re going to see a series of slides – two slides for each of the model areas. So the first two, I’ll go over in quite a bit of detail so you can understand the content of the slides and then we’ll move on through the rest of them. So we’re going to start with Eagle Ford oil and what we’ve got here up here in the box, you will be able to see net acres which is over 16 for this particular model, number of wells you could get if you go to 80 acre spacing, the number of wells we’re going to drill in 2012. The capital to drill complete an equipped, so this is all capital to bring that well online. That number looks probably little different then what I showed earlier because I showed ranges and all the slides that would just be the midpoint of the range.

So the economics we didn’t do at the high end or low end, we just split it right down in the middle. Then you’ll have your EUR and MBoe and then you will be able to see what percent liquid that we have when we look at that Mboe. The net present value for our well and rate of return at the prices Bob talked about earlier. Then on the map you got the blobs, this one happens to be McMullen County and then these arrows point to where we got the particular acreage outlined, all the rig symbols are actually original exploration wells or appraisal wells, so that’s how much data we collected to really understand this particular area. So, now we are going to talk about and I am going to let this play a couple of times let it go first and then I’ll tell you what we’re doing here.

As you look up here, you are going to see from Offset and Swift and you'll see a couple of Swifts. What happens is if you look back over time when we started doing our exploratory work back in 2010. The first initial wells, we drilled are exploratory wells, typically were somewhere between 3000 to 4000 foot lateral anywhere from 7 to maybe 12 frac stages. As we did that and started to learn more about what was going on in our areas and looking what everybody else was doing in the area, it became pretty obvious that people will move into longer laterals and more frac stages. So, when as we moved out of exploration into appraisal, which in this particular example would be these wells here.

We extended the lateral and went to few more frac stages. So those wells, which hard to see on this model these are light purple, those three wells right there. What we said this time last year is we weren’t satisfied with 4,500 foot in 13 stages and we are going to go to 6000 feet and 17 or 18 stages. And that’s actually what this model is so the next two Swift development wells got real close to that and we got 5600 foot in 17 stages and actually this last well is just under the 6,000 foot model. Well in all these areas, we don’t to look just at ourselves. We’re going to look across the fence and learn from everyone else. So we go in and we took every well that we could find that had enough data will confident in the decline curve and had at least 4,500 foot lateral in 14 stages.

So that’s what all these offset wells are, so these are immediate offsets, some of which come all the way up to our acreage, and you can see those are in blue, and there is quite a bit of scatter, but the lowering the hold the outliers are the ones that are the longest, and have the most stages. So that’s the scene you are going to see from here on out were actually pushing beyond the 6,000 foot laterals, and trying to get at least 6,300 to 6,800 foot laterals. Now some places we can, some places we can’t because it depends on the TDD depth of the Eagle Ford, but that’s what you’re going to see from us in the future. Longer and longer laterals more frac stages.

The next what we’re going to talk about is Eagle Ford oil La Salle County, it is well Artesia wells area, up here in the northern part of this blob here is where the oil is. Right now we have about 3,900 acres of oil acreage there. We’re going to drill 14 wells in 2012. These are little more gassy, so there is 73% liquid as opposed to 86% for the McMullen County, but with that gas you actually get a little more lift and you actually get more recovery on the Boe side and you still get some really good economics.

Over in LaSalle we actually have just now drilled several wells and with the wells we’re sitting there waiting on frac we should get them fraced sometime in early April. So what we’ve used here is a series of wells several of which actually about up to our acreage that were drilled by El Paso. And again you are seeing the same type thing, the longer these laterals get the more stages that you do, you can actually beat this 6,000 foot model. So we’re really pleased to see what El Paso has done up there and we think all wells are going to be very similar.

Okay, let’s move back to McMullen County and we’re going to move into the Eagle Ford condensate. So you are actually moving a little further south kind of in this area here. What we’ve got is about 6,400 acres there. The costs are a little bit higher, these are the wells that I was talking about that are right up against that reev trend and are little bit harder to this steer. So we’ll take just a little more time. But again some good liquids right at 50% some great returns, we just completed two wells in this area just to give you an idea how strong the wells are both of them are flowing at 5 million a day with a little over 500 barrels of condensate a day. So they’re over a 100 barrels per million just pre–condensate at the surface. And so you can imagine the BTU content is also very high and you probably up around 90 to 100 barrels per million of NGL once you send it through a processing plant.

Okay. Same story again. You’ve got six Swift wells that had an average of 5,400 foot lateral and 16 frac stages most of them are here, one of them is hidden here this was our longest lateral. This well is – this actually overlaying by the offset wells. But again as you look at the offset wells you can get somebody who went out there all the way to 7,100 foot lateral in 20 frac stages is not surprising, that’s the best performing well of the lot. Bob mentioned earlier. We look at this quarterly. There is team for each of these nine models. They will sit down with upper management and actually show the actual decline curve and make sure that we are still standing within the model parameters. And if we have to switch model we will, but right now everything looks real solid.

Okay. Flipping back to LaSalle County, we talk about the oil acreage here actually the rest of the acreage over there is condensate. We have really no dry gas in the LaSalle area where we are going to drill half our wells this year, 9,200 net acres in this condensate window, little bit cheaper cost, some pretty good EURs and MBoe, over 1 million barrels, 44% liquids and again very strong economics. Again, same story again, you can see the Swift wells in the dark blue. Three of them here and one of them up here, 5.200 foot lateral, I’m sorry that’s the offset wells and then the Swift wells, three of them 5,000 foot lateral, 15 stages with the last one coming right on the model.

So same story again, the longer these laterals go to more stages, the more recovery you’re getting. Okay, now we are going to shift down into the dry gas. Bob, has already talked about 8,300 acres at Fasken, down here in the Webb County. What’s so great about that is – that its 8,300 acres that is contiguous. The other thing is, it’s one of the few places that we’ve seen around that you can earn on 640 acre spacing, the big portion of the Eagle Ford is about 320. So, we can actually go out there and drill well whole 640 and if you get down to 80-acre spacing, you have seven more wells that you can drill whenever the time is right. And these wells hyperbolic decline, these particular wells because of the high porosity here in the Eagle Ford, we’ll probably line out at about 1 million and 1.5 million a day and stay there for a long, long period of time. Now, some of the parameters here, again we just finished the one well. The EURs, if you convert that to gas with the 6,000 foot laterals, these are 10 Bcf wells, pretty outstanding for shale well. No liquids and then at the 325 pricing, you’re making a return. Obviously, we’re not quite at 325 right now, so, I’ll show you some sensitivities here in a minute.

Now, most of the wells in plot are all wells. They average about a 5,000 foot lateral in 14 frac stages. They are all hug in kind of down here, right just below the model. But we do have one well that we went to 6800 foot, 19 stages just to give you a little color on that well. All of our wells we won’t bring them on anything larger than the 20/64 choke. So you bring these wells on most of the Eagle Ford will decline off pretty quickly during the first year. This particular well at Fasken we brought on in August at 12 million a day. Right now it’s flowing 12 million a day after 1.6 Bcf is come out of the ground. So, you can imagine what the key momentum is going to be. It’s going to exceed 10 Bcf. So, these are very, very strong wells.

So what is that mean for economics, just threw a few prices out there 325 I’ve talked about gets you up around 39% rate of return. You went to $3 flat, you are still making 23% rate of return. And then if you wanted to get your money back on a 10% basis, you could go all the way down to 2.44. Now obviously we’re going to wait for the right time now that we have is – what we think is the annuity out here when gas prices return whenever that maybe, this acreage will be there and we know what to do with it and we will go out there and make some money after that.

Okay, shifting over to McMullen County dry gas, a lot of acreage here but also a lot of unexplored acreage. Most of the drilling that has gone so far has been in this area. This is our Petrohawk joint venture area and then there is actually another little sliver up here that’s in that joint venture. As you go up here though you are getting into the condensate round, even wells that would get up to 200, 300, 400 barrels a day. What we’ve done is because these are large leases here, what we done with Petrohawk is we have agreed to get out of the dry gas window and concentrate up here, and because of continuous drilling clause as we can actually hold this acreage for an extended period of time down to about this point by drilling those condensate rich Eagle Ford up to the north and that’s what we are planning on doing.

As you moved down to the south down here, its’ actually unexplored as far as our acreage. We obviously expect the Eagle Ford to be deeper there and higher pressure and probably higher recovery than what we seen up here and will go through those here real quickly. Because that’s what we’ve seen in the Olmos as we gone south in the Olmos the pressure, radiant has gone up, the recoveries have gone up and actually it hasn’t gotten any less liquid rich in the Olmos. What we will be doing with this area below the JV line especially over in this area again we have some big leases and with continuous drilling we’ll be drilling the condensate area of the Olmos. We actually hold this acreage for at least five years without doing any Eagle Ford drilling.

Reserves are quite high as Fasken. They are about 7 Bcf a well, no liquids right now a $325 pricing it just about breakeven on the 10% rate of return and obviously its $2 where Henry Hub is right now you would not make money on these wells. So let’s look at the curve and see what these look like. Again the same thing the offset wells are in blue here and here, the Swift wells or Swift Petrohawk wells are in the light blue something to note here even though we’ve done some long laterals with the Swift wells we haven’t done as many frac stages that would because early in the appraisal us in Petrohawk really spaced out, the preparations on the first two or three wells. We actually drilled almost 6000 foot laterals and only had 10 frac stages, very quickly we decided that wasn’t the thing to do went back to the normal 350 foot spacing between frac stages or purposes.

Okay, we just went over the six Eagle Fords we are now going to shift gears and go into the three Olmos models. First, we are going to talk about is almost oil. We've got about 4,700 acres, 29 wells to drill. A lot of those wells are drilled in here, where there is a channel that comes through here, but we also have a big acreage plot over here, which is the bulk of these 4,700 acres, because of small title issues have not been able to drill well there. Those issues are about to get taking care of and will be shortly we can move over there and drill those almost all wells. So, a lot more wells to drill just not this year. Again, 84% liquid, it’s a little over 0.5 million barrels and some probably the best economics that we've got, because these wells have a really high initial rate.

Here is a couple of the wells that you can see in here, it is our model. We have got one well that's right under the model and one well that's above the model. If you are really were looking at this and seeing those are 5,000 foot and 14 frac stages and this is the 6,000 foot model and 17 frac stages. Your inclination would be to move it up and say actually this model is conservative. We are not ready to do that yet. We really like to have at least half a dozen wells as examples before we change your model, so we'll be watching that very closely.

Okay. Moving on to Olmos condensate, quite a number of wells here in this acreage here and a big bunch of acreage that we can move into, this is the area here that holds a lot of that southern dry gas Eagle Ford. We're very excited about this. One of the things that we aren't showing you today is the 3D seismic over that area and our geophysicists are, geoscientists are really excited, because they actually think that they are thickening in the Olmos as you go down south. We also believe that in this particular case, the way the oil trends, you can see the oil lines kind of drawn in through here. We actually will probably see the liquid yields come up as we go in this general direction. So, you are going to see us over the next three to five years. There will be quite a bit of drilling in here.

And here are the curves. Again, the one that I talked about a while go is we just brought online, we don’t have enough data to put it into the curve here, came on very strong, 3 million a day and 720 barrels of condensate a day, and that’s right there at the separator, so a lot richer than we thought obviously that’s going to be way more than a 34% liquid content as the well producers.

Okay, last but not least is Olmos rich gas. We called this rich gas, because it is quite different than the two dry gas models that we talked about. Normally, this gas is somewhere between and probably 1,100 to almost 1,200 BTU. Obviously, we process it. We get a great NGL yield. I think it averages probably around 70 barrels per million and probably we'll even get higher than that as we move further south and west into the more liquids-rich area. So, with that, you get 28% liquids, you get about 6 Bcf and then those associated liquids and still getting a good rate of return at $3.25. I haven’t run this down to $2, but we actually won’t be doing any of this drilling in our five-year model. There are no wells in there, but it's always something as Rich as it is. Again, you could come back to it and drill some good wells.

Again, all of these are – these are Swift wells, because there is not a lot of Olmos drilling going around us. So, we don’t have a lot of offset data. The first three wells, the appraisal wells only 34,000 foot laterals in 10 frac stages, the last four which are these 5515 frac stages, you can see our models. This one is the one actually that we talked about and we decided not to change before this meeting, but it looks like we do need to change that model and actually bring it up a little bit, because it looks conservative.

We show this slide earlier. I want to hit it again. Just to remind you what we are going to be doing over the next three years and even beyond into the two years after that. These are the models that are in our program the IP, percent liquids, the number of projects each year, if you look at the three oil if you just took these numbers up here and through here that 70% of the program these numbers are about 30% and here is our less than 1% at Fasken well that we drilled. And here is an economic summary slide if you want to do any modeling on what our portfolio looks like. I’m not going go through all these numbers but it takes many of the other slides just combines it into one for a quick reference, but a really robust portfolio a lot of liquids we can go to, that’s where we are going, a lot of gas that we have set off to the side for a future date, but it’s there we got ways to hold it. And when that gas price comes back we will be up here telling all about some really good gas wells.

Again, this is the summary of what we told you. And now I’m tired, so we will get to take a 15-minute break.

Unidentified Company Speaker

Thanks, Steve. All of our presenters so far – you guys are doing a great job here in Houston and with that’s you keep on – help us keep on schedule and try to come back to room and start coming back in the next 10 minutes. We have plenty of refreshments out there for you. There is plenty of privacy if you’d make phone calls, et cetera, whatever you need to do, but just please try and start making your way back in the next 10 minutes or so, so we can get you out of here on time this afternoon. Thank you.


Unidentified Company Speaker

Great thanks for returning on time. We are going to get the program restarted here with the review of our central Louisiana and East Texas core operating area and its pleasure to introduce John Branca, you’ll remember for earlier. Thank you.

John Branca – Vice President, Exploration & Geosciences

Yeah, I am going to take you through our Central Louisiana/East Texas area. Okay, the, what we call, CLAETX is comprised of four fields, Brookeland, Burr Ferry, and Masters Creek, which are Austin Chalk fields, and then we have to the South here, South Bearhead Creek, which is a Wilcox field.

And we are really excited about these fields. We are doing things in each one of them and I’ll take you through those, but at a highlight in Burr Ferry, we see numerous locations to drill within our area of mutual interest. And we estimate the resource potential to be $30 to $40 million barrels. In Masters Creek, this field has been drilled on 2000 acre units and we are testing the concept of infilling this and drilling on smaller spacing and this will yield about 15 million to 20 million barrels potential. And then in South Bearhead Creek, this is the field of Wilcox. We are – there has been a lot of offset activity, which has caused us to re-look at the field and we are looking at some applying or almost horizontal technology there. And particularly important is this is a very oily area and 65% of this resource is oil and natural gas liquids, further its brand pricing, so we get the uplift on the West Texas in immediate.

We have significant acreage position in these fields and that’s really a good thing for us. In Brookeland, we have 105,000 gross acres, 68,000 net; Burr Ferry 122,000 gross, 74 net; Masters Creek, we have 51,000 gross and 38 net; and South Bearhead Creek, we have about 6,000 acres gross to net. So, you can see the totals about 284,000 acres, 186,000 net acres in this area.

Okay. Starting with Burr Ferry, Burr Ferry is our chalk field and it sits here. We have a couple of wells that we have drilled there, we partner. And in 2010 and we have previously announced this, but I want to remind you those, there is a GASRS 5-1 and the GASRS 18-1. And both of these wells had some pretty impressive IPs. The 5-1 was 1,000 barrels a day and 13 million cubic feet of gas and the 18-1 was 10 million and 840 barrels a day. And both those wells are still producing today about 200 plus, 300 plus barrels of oil a day, so not only high IPs, but a more moderate decline, so very, very nice wells. We have drilled two wells in the past year here and I’ll talk about those in a little bit and show you the implications.

Okay. So, in 2012 with our joint venture partner following on the success of the 5-1 and the 18-1, we are going to drill six wells in this area. And so that’s where we are going to focus and you can see the locations in the order of drilling on this slide. The 5-1, I mentioned it. Here is the decline curve. And so they started out at about 1,000 barrels a day and you can see they are coming down here still at about 200 barrels, this is approximately today. We estimate these wells to produce 318,000 barrels of oil and NGLs of 209,000 barrels, an additional 1.5 Bcf of gas. This will pay out in 14 or has paid out in 14 months. 18-1, 350,000 barrels of oil and 385,000 barrels of natural gas liquids, 2.7 Bcf of gas, this one paid out in 8.1 months, so very, very strong oils.

We drilled off with partner on the 16-1. This was near the southern end of our only mutual interest. We had a 6,000 foot lateral. We were disappointed in as well it only encountered seven or six shows and we’ve interpreted this to be sooner at the limits of the high fractured density that we needed for production. So, we’re going to continue to look at this, but we’re going to stay away from this part of the AMI for now. There is a picture of the wellbore, up top you have the (indiscernible) that we ran while drilling. This is the Austin Chalk interval, the greening interval; the blue line is well trajectory as it was drilled. The star shows during drilling fractures and this is very low fracture density. So, there is a disappointment, but we’ve learned a lot about the area and we’re going drill all well based on that.

The 20-1 is an infill well. And this well had 21 shows and no indications of depletion. We drilled 3,600 foot lateral. We encountered some mechanical problems during the completion phase, but that doesn’t make us any less excited about this. This has excellent shows while drilling and we’re evaluating the possibility of side tracking this because we want to get a completion in this zone. And here is the well bore, now if you recall the 16-1, it only had six shows and here we have 20 odd shows in this 3,600 foot lateral. So, this looks like a very, very excellent piece of rock here. We’re going to do another wellbore in that to produce.

So in this year, we have two rigs coming, they are going to come towards the end of this month. And the first rig is going to drill two wells and the second rig is going to drill four wells for total of six wells in Burr Ferry. So that’s going to start off pretty quick now. You could also see the similar to what Steve was showing before what these wells look like, they are going to cost little under a $11 million and here is the EUR 403, the NGL’s 447,000 barrels in the gas 2.5 Bcf. So fantastic return on these wells, so we are – that’s why we were focusing here with hard priced oil.

And now I want to move from Burr Ferry, which we just spoke off to Masters Creek, and we’ve drilled the well, entitled the Exxon Corp. 10-1 this location. We are pretty excited about this well. This is end so well it’s proposed down foot lateral, 6000 foot offset. When we drilled we encountered 24 excellent shows. We only drilled 2,500 feet in the lateral, because we had some steering problems and we decided rather than have a mechanical problem, we wanted to go ahead and complete the well and we did so. We did some testing. The IP for this well is 836 barrels oil per day and 5.4 million cubic feet of gas per day, and this well we are preparing to turn on in about 10 days or five days, excuse me.

So, here’s a look and you can see the fracture density in this well, this is fantastic. So, in a short lateral, we had over 20 fractures that we encountered. So, this is a very exciting for this input program, I will remind you that these wells have been drilled on 2,000 acre units and we are infilling. Here is a significance for this, here is the Exxon Corp 10-1, the black lines here are wells that have been drilled in the field, the orange circles with the lines are the infill locations we can go ahead and exploit this. So, this is a relatively low risk opportunity, and we have a lot of infill and so you can see the acreage and the recovery per well, and their potential.

And here is the type well for Masters Creek and 863,000 barrels of oil, 372,000 barrels of natural gas liquid and 3 Bcf gas payout in 7.4 months, $11.5 million, and you can see the returns, the rate of return, return on investment.

Bearhead Creek, I want to talk about something little bit different here, and it’s south of the Creek Chalk Field, this is a Wilcox Field. We’ve – there has been a quite a lot of activity, here’s our South Bearhead creek field, the blue outline, these green triangles and squares are activity by El Paso. The purple triangles and squares are activity by mid-states. They permitted a significant number of wells and completed a significant number of wells. They are getting great recovery and so we are re-looking at this and preparing to drill well late this year or early next. What’s really interesting is although it’s a different geologic formation. The Wilcox here is very similar to the Olmos formation in South Texas in terms of the porosity and the permeability, even similar depth.

And we almost, we’ve been very successful in drilling those horizontal wells, you saw that in the previous South Texas presentation and we haven’t tried that application here. So we are looking at drilling a horizontal well in the Wilcox in South Bearhead Creek and then doing a multistage frac. So we are working on that and we will probably do something late in 2012. So, just giving you an idea of the opportunities that in Central Louisiana, East Texas. There is Burr Ferry and Masters Creek and South Bearhead Creek. You can see the IPs. We are going to drill the six wells in Burr Ferry in 2012.

We are going to drill the whole, probably horizontal well in South Bearhead Creek and Masters Creek, the Exxon 10-1, that’s Infill well. And we have done the initial tests, you saw that has 800 barrels a day, what we want to do flow that for a while, see how it producers, see how it holds up and you will get enough information to understand the ultimate recovery and that’s why you don’t see any wells here. We’re confident that’s going to be successful, but we won’t have an idea of how successful and then we’ll in 2013 and 2014 will initiate drilling Infill program there. And the on the back of the successful South Bearhead Creek well, we will have a program in that field as well.

And just back on the economics, these wells cost $9.5 million to $11.5 million. They have between 400,000 and 800,000 barrels EUR with the associated natural gas liquids in the Chalk and 2 to 3 Bcf gas in the Chalk and so very strong returns in – return on investment. So in summary, we have got a lot of running room in Burr Ferry, numerous locations to drill. We drilled six wells in 2012 with 30 to 40 million barrels of resource in Masters Creek. We have drilled the Infill well. We’re going to turn that also production, testing the Infill of the 2,000 acres units with 15 million to 20 million barrels resource and South Bearhead Creek and looking at the offset activity and preferring a horizontal well and just reminder very liquids rich and brand pricing. Okay, that’s it.

Unidentified Company Speaker

Okay, now we’re going to transition into Southeast Louisiana, which will be Lake Washington and Bay de Chene. Of course, everybody is familiar with where these are right down here in close to Plaquemines Parish, (indiscernible) Parish. So little summary on SELA, I think is everybody knows since Swift this had field in 2001, there has been a tremendous record of efficient exploitation of this property. We still have some very low cost development opportunities. I am going to show you some statistics and whether it’s a drill well or whether it’s a re-complete, you are talking to average development cost of somewhere between $10 to $15 to $16 a barrel. When you’ve got 83% royalty, net revenue interest out there and the fact that Brent prices are up over $120 a barrel, you can imagine what the economics are and what the payouts are, so, very robust. Of course, it gives a very strong operating cash flow. And it's just the guess that keeps on giving. And one of the things that we are going to talk about here in a minute the fact that we are excited, we have kind of turned the corner in Lake Washington from 2009 to 2011 in terms of starting to drill deeper. And we are actually going to spend more capital in Lake Washington and Bay de Chene this year than we did the two previous years.

Here is the development track record over the last three years. The thing that I really want to bring your attention to is as we came out of the end of the 2008 and the 2009 when the economic crisis hit and prices dropped for both oil and gas, we really retrenched in Lake Washington. We decided that we were going to drill really, really shallow wells, because you’ve got production anywhere from 1,500 feet down to almost 14,000 feet right now of Lake Washington. So, that’s what we did. And you can see a drill and complete cost of $1.4 million. Thos had to be really, really shallow wells.

Then in 2010, we really continue that being except we went here is the little bit deeper, maybe from the 1,500 to 2,000 feet range down to 3, 4, maybe 5,000 foot, but still average drill and complete cost only $2.1 million. As the new team got together and refocused their efforts on putting together drilling opportunities, we’ve got into 2011, we really switched gears. It was time to move out of those shallow wells and get back down into what we call the LICC series and start drilling some wells that were a little more risky, not that much, but have a lot more reward with them, and that reward was not only production coming out of that well in terms of initial potential, but also bigger EURs, but more importantly, it would prove fault blocks that were adjacent to it, not prove it up, but actually bring them up to where they were drilled ready, that you felt good enough that, that was something that you could make economic of that. So, that theme is going to come throughout this.

And again as you look at the average $12 a barrel, really good, especially when you think about, where oil prices are. The next series it just shows you in relation to the field and usually the dome is right up in here. So, these are the shallow things that I talked about that we did in 2009 and 2010. We still have a number of those to do up in this area, now individual wells have lot smaller EURs, but between the north, east and the west, we still have an inventory of 16 million – up to 16 million barrels of those types of opportunities.

As we move deeper into LI and CC, now you are getting into the area, where you all be familiar with Newport, where we have produced 9 million barrels, 57 million barrels up here, and 25 down here. In 2011, we drilled a well here, and here both of which found hydrocarbons. If you add all those numbers up, you can see you could get up to over 50 million barrels of potential just in the LI to CC series. That same series carries over to Bay de Chene. We haven’t drilled wells in Bay de Chene for a couple of years, but we do see a lot of potential there again about 15 million barrels and we have at least one and we may have another one late in the year that will be very impactful wells for Bay de Chene in this sand series.

This is something we haven’t shown before, but it’s the SELA team is what they call their opportunity hopper. So, they have got several teams that are mapping all over the dome, that are mapping all around Bay de Chene and actually they have some close to 70 prospects that they have out there that they generate. Then they go through a series of peer reviews, some rough order of magnitude costs and then they will start to share it through those 69 opportunities and they will start to say okay, some of these opportunities need to go to the next level to where we really feel like that these are robust enough that we’re going to drill them. Where we are right now is that would be called our 2013 opportunities. Now our 2012 drilling program is already in the queue and is actually being executed. So these guys here in the blue would have been back here last year, now they move up. So you continually see these ideas then, you refine them, you get your next year ready, you’re executing this year, what that does for you is that it really allows you to plan your business. Like Washington because of the salt, because of some level zone can sometimes be difficult to drill, you want to make sure that you are drilling and completion facility engineers have enough time to research the wells in the area they’re going to drill, so they do an effective job of drilling those wells and that’s something that’s really working well for us this year.

Okay, I’m going to shift gears now. I’ll get back to show you some specific prospects a little bit later, I’ve shifted now from drilling to rig recompletions. So, again one of the things that you’ll see, is I’ll show some logs section. When you drill well here you may get hydrocarbons anywhere from 1,500 foot down to 13,000 foot. Where you normally going to complete in the lowest zone allow that to deplete and then bring a rig out there and plug that zone off and come up the hole. So, there are a lot of recompletions that here that are done with a rig. You can see usually, we do somewhere between 10 and 20 a year. Here some of the production rates and you’re talking about an averaging about 450 barrels a day, the average cost less than three quarters of a million and some development cost that are in here around the $11 range. We have actually added something new this year, as we think we’re always looking for new technologies or borrowing technologies a lot of people have used and we have all these back pace, some of them are thick, some of them are pretty thin.

When they get that thin, the economics gets a little shaky when you want to bring a rig out there because a rig is very expensive. We’re actually now that there is technology where you can go in with the coil tubing unit and actually go into the existing wells, do you perforating, do you gravel packing, have a small screen in there and then you can actually produce these zones and access those reserves where you couldn’t in the past because it was too expensive to do with the rig. So we did seven of those this year and see they’re not quite as good as the others, but still $16 a barrel, the reason they’re not quite as good because they’re smaller zones. But you can still imagine what the economics look like at $16 a barrel and commodity prices being in excess of 100.

This is just a visual of what a coil tubing unit looks like. We actually couldn’t find one that was in Lake Washington, so you have to pretend that this is actually water out here. So, Lake Washington is pretty shallow, sometimes the water does look a little brown. But anyway like I said doesn’t require a rig, it’s less expensive. There is lot of these we can do and you can really do the same thing you did with a rig, it’s just a smaller format. When it’s smaller like that you actually can’t pull the well as hard, but you still can make a lot of money doing this. So, we’re really excited about it. And the resource development manager for Lake Washington through this slide and he said, you’ve got to keep the slide because he always like to talk about his payout.

And this is what we call a through-tubing recomplete. So, what means there are some wells out there that you don’t have to grab the packet, they’re deep enough and you can just actually go in and set a plug in the bottom of the well, plug off the old zone and then just go in and perforate, once holds in the pipe and let that formation come in. Again, most of them are really thin. This is a log here to choose that the zone maybe 12, 14 foot thick. But you can see it costing $48,000 to do this job, well came on at 880 barrels a day, less than 24 hour payout.

So, the picture I’m trying to show you there is multiple opportunities out here whether it’s a rig recomplete, whether it’s coil tubing recomplete, whether it’s a through-tubing, whether it’s another thing we call a sliding sleeve where we switch from zone to zone in a well, gas lift, water handling this is a gift that truly keeps giving. Future recompletion potential, one of the things we do is we track this at all times, whether it’s a sliding sleeve or rig recomplete. A lot of these wells will have a zone that will be down to 40, 30, 20 barrels a day and you’ve got 400 to 500 barrel day well up the hole that you could recomplete too. We watch that real close when it gets to a point where that well is really down there below 20 barrels at the time we’ll say I think it’s time to leave that one and come up the whole. And so, you’ve got with that up to about 70 recompletions, and these are rig recompletions, this doesn’t count coal to them, the sliding sleeves or through to them recompletes.

This is just a graph of what’s been going on with like Washington production, the light blue is the drilling that we’ve done, the dark blue is the base, you can see there is some fluctuations and you will see a decline come in and then the activity comes, decline activity. And right now we are going back into another activity mode so it’s something that these wells do decline, an individual zone will decline, but there is always a zone up the hole that you can go to, so, the actual wellbore done decline, but this is zone within the wellbore decline, before you switch it to another zone. This is just the opposite of what I showed, this gets into more detail about what the contribution is from enhancements, which would be acid job, gas lift sliding sleeve, that drilling completions and then the rig recompletions. So you can see, if you just start from new January 10, as a zero point, you can see the amount of production that comes out of the program and actually the program in terms of capital spend, not that robust, $49 million in 2010, $33 million in 2011, and now will actually looks like somewhere between $60 million and $80 million will be spent on Lake Washington this year. So more than double what we’ve spent last year.

So let’s talk about what the future holds. We’ve got a couple of turns and here that I want to explain. When I talk about extension wells and I’ll show you some examples. We are taking about a well that’s in a hydrocarbon province, that has seen nearby hydrocarbons or maybe even hydrocarbons to a small extent in the fault block that it had been. But it doesn’t have a proven producing well in that fault block that’s commercial. So that’s what we call extension wells because we are drilling that well and it also effects the fault blocks next to it in terms of what we think the potential land might be.

So, as we look at this years’ program, it’s going to be about half and half, most of the well – half of wells will be extension wells there will be Li to CC and maybe down to the K level because there is some bigger targets in the K level. And in the others, which are lower risk development wells will be a little shallower and there are very high chance factor 90% plus type chance factor wells, so good mix of the portfolio there. This is just the cartoon of where the wells are, the blue, light blue is the salt, the dark blue with the names on it are the extension wells and then the green are the development wells, which in the SEC (indiscernible) call PUDs.

Here is our schedule we actually started in the 2012 program in the middle of December. We’ve already gotten two successful wells drilled that I’ll show the results on the CM 419 and 421. We’re now drilling the CM PPP, but I think it’s actually called the 423 now. And then we’ll keep this program going and actually get into the deeper wells as we get out later in the year. Anytime we start a program, we’d like to start with some of the less mechanically difficult wells so that the new crew, the new rig, the new drilling engineers get used to the rig before we buy it off the deeper wells. The other thing that we’re considering very seriously is bringing the second rig out here. We’ve got four more PUD wells that are ready to go, as we get into April and May and see how cash flow is going, and we’ll be making a decision as to whether or not we’re going to bring that second rig out there.

Okay, now I’m going to get into a series of pretty simple math. Hopefully it will show you concept. So this is a Jelly Bowl well that we drilled last year that’s an indication where the well is. This is a log over here so any place that you see green coloring over here means oil, that’s good. So, we would like to see a lot of oil. This well is drilled. It actually came online at about 2,000 barrels a day. It’s got multiple fleets in it some were really, really excited about. We’re excited about as you now have proven commercial hydrocarbons here from an older well. We have proven commercial hydrocarbons here. This is the well that we are going to drill this year. Of course if that comes in, it’s going to be pretty easy to say let’s go there next and then on down the line. So, things – deeper drilling, things that can give you a higher rate up to 2,000 barrels a day and give you some other opportunities.

Same thing happened with our Hershey well. A little bit different. It’s on the west side. Here we found a whole lot of pay. What has happened is there is some much pay and this stuff is a little bit tighter, so it doesn’t flow as readily as the jelly ball. We have got this first well we have drilled. It’s doing really well. We are going to drill another well here. And then as things go on, we are going to probably look at drilling down in here. We haven't colored and it is potentially yet, but after we drill this well if it’s good we are probably going to drill here. So, another one of those examples, where that one well gives you a lot more opportunities to put in that opportunity hopper that I showed earlier, the funnel as we look at these prospects.

Okay. Now, we are getting into the wells that we are drilling in 2012. The CM 419 has been drilled. We’re in the process of completing it. We had 87 feet of total net pay and four different sands. There is the location of the well right there. So, obviously we have got a lot of hydrocarbons produced out of this well, but it also allows us to feel a lot more confident about this fault block and that fault block.

Similar story in the second well we’ve drilled in this program, the 421 which just finished drilling, has not yet been completed. The hydrocarbons were found right here. The blue is the salt. Here is all the pay that's associated with the well. You can see there is possibility of over 200 foot a pay. So, lot hydrocarbons and then a lot of other fault blocks to step out to in succeeding years as we start to go. Okay, let’s go to this one and let's go to this one, and let's go to this one. And this is how the hopper starts to get fit. These new opportunities are now going from the appraisal stage in the hopper down to something that could be executed in the next year or two.

Okay. Now, this is one of the prospects that a lot of people are excited about, mainly because it could be a really, really big area. It’s down on the kind of the eastern side of the dome, where you’ve got a little inset into the salt, which is similar to what we saw at Newport and Hershey, big acreage. We normally aren’t out here. We are drilling for usually for 5, 10, 15 acres. It’s unusual to have a fault block that’s up to almost 40 acres and has a down structure well that sound a little bit of hydrocarbons. What we hope is the sand stays together as you go back towards the salt. And this is all one continuous reservoir, and if this is true, then all the expansion fill up with oil as you drill this well.

Okay, very quickly the same story in the same sand series over at Bay de Chene. This is our Magnolia prospect. It actually is even bigger on an acreage size, up to 130 acres. We are going to drill the well. In this particular position, we got a down structure well, that’s all about 5 or 6 foot of oil in one of the sands, so same content.

Now, I am only going to show one development well, because they are all very, very similar. Normally, when we talk about a PUD or a development well, it’s a situation like this to where you drill the well and you found commercial hydrocarbons. At this point on the structure in the fault block, you can see there is the log and these things are tested out very well. What we have done now is this well has depleted? The water has swept through, but as you go up in the structure back to where you have another inset into the salt, we are going to drill another well and recover all those hydrocarbons that have not been recovered in here, and most of PUD or development wells look like that.

So, let’s sum up with future opportunities in our three-year plan. We've got enough re-completes out there that we expect to do 10 to 20 a year development well, anywhere from 6 to 10 per year and then the extension wells, three to five.

And you can see the IPs that are associated with those types of wells. And then here is some stuff on the economics, we can get some really robust economics out here, usually the one fix royalty you are talking about pretty low development cost. So everything is pretty much greater than 100% rate of return. So, we are going to continue to have the team work this and get as many opportunities that we can because obviously the economics are extraordinary. So back to the summary slide, Swift has done a great job of exploiting this asset, still have a lot of low cost development and extension opportunity, it’s a very oily, you get rent prices obviously you get some really strong cash flow and it’s a gift that keeps giving, in my mind it’s going to give for many-many years to come.

Okay, I transition in to Bob, who is going to do a summary for us.

Bob Banks – Executive Vice President and Chief Operating Officer

Great job, guys. I just want to try to wrap up here. Some of what you saw, I will leave you some with some take ways. We really have a great inventory going forward. It is as good as I’ve ever seen. We have a tremendous mix of properties that are really multiple-year now. We have a lot of line of sight that we’ve never had before the reserves and production growth for a few years out.

We are very focused into oil and high GOR oil, as we showed you in Southeastern Louisiana, the Miocene Sands are excellent. In south Texas, we have the Eagle Ford shale and the Olmos tight sand. And in Central Louisiana East Texas, we have the Austin Chalk and Wilcox. And then we have a good mix of properties in the condensate and rich gas windows, both of them are in South Texas, the Eagle Ford shale and the Olmos tight sand. And then for the future we have some very, very good gas acreage in the Eagle Ford shale, but we have parked that acreage now for the future. On our strategic initiatives we didn’t focus too much on this today, but we do have some teams working on some new liquids rich plays, we are focused on new resource plays, some tight sand and carbonate reservoirs where we can use our horizontal technology, looking at joint venture opportunities and some acquisition candidates as well.

So this is what we want to put into the pipeline for the next three and five year period following this good growth we are going to through the projects we just showed you today. And so the three key areas, just as a recap, the Eagle Ford shale development, that’s about 78,000 net acres, dry gas wells are about 7 to 10 Bcf EURs, the liquids rich wells are anywhere from about 380 to 1125 MMBoe EURs and we have just a little under a billion barrels of resource potential in the Eagle Ford shale development. And then same kind of story in the Olmos, we’ve about 37,000 net acres there, 500 to 1,260 MMBoe for our EURs and a little over 200 million barrels of oil resource potential in the Olmos.

As John showed you in Central Louisiana East Texas, we’re going to focus a fair bit this year on the Austin Chalk drilling program. Masters Creek, we have about 38,000 net acres. We see the potential for a very good infill program about 14 million to 21 million barrels of oil equivalent resource potential net for Swift, and over in Burr Ferry, we have about 74,000 net acres in a drilling window about 30 million to 40 million barrels of resource potential net to Swift. And then as we teased you at little bit that the South Bearhead Creek and Wilcox, we are going to continue to work on that through our field development reviews and possibly drill a well there late 2012, early 2013.

And Steve just wrapped up Southeast Louisiana world-class asset Lake Washington and those Miocene Sands, up against that dome. We’ve about 17.3 million barrels of oil equivalent, booked reserves about 53% of its developed. It’s a very rich inventory of development in exploration, prospect inventory. I think we can generally categorize what Steve showed you as multiple extension opportunities, maybe in the 1 million to 3 million barrel range each. We’ve got some exploration prospects in the 1 million to 50 million barrel range and we even have a very good sub-salt prospect that could be in the 100 million to 300 million barrel range, but that’s going to require little more technology and money. These are going to be deeper targets.

So, I think we’re poised for growth like we’ve never been before. We’ve got a very great operating team. I can honestly say it’s a really the best team, I’ve worked with in maybe my 35 years in the business. We have a lot of good camaraderie, a lot of good chemistry and everybody is kind of working same to make this portfolio go. Lot of our industry experience we’ve embedded our core values into organization, we think that’s been an important step to get the kind of growth that we need. The Eagle Ford and almost evaluation as efficiently moved, we believe from the evaluation phase to the appraisal phase where we’re now getting into the development and manufacturing phase. We derisked our acreage and we really believe now it can be counted on future growth and performance.

The dry gas acreage is held without drilling. And I hope we showed you today that we are capturing some of our operating efficiencies in South Texas. We’re utilizing new technologies. We are not afraid to try new technologies and push the envelope. We got a team that accepts that and is willing to change practice our drilling and completion performance in costs are starting to be optimize. We’re bringing the cost down, we’re bringing the time down. We have our supply chain initiatives thinking in with those operations very well now and through all of this, our lease operating costs are becoming more efficient, especially with the way we’re managing our water and sharing our manpower in the field.

Lake Washington, Steve said, it keeps on giving. We think it’s realizable, continuous cash flow from very high value oil wells, and a lot of upside from some deeper objectives and the Austin Chalk is going to be potential for multiple year growth on top of what we’re already doing in South Texas and South East Louisiana. Again, there are high IPs and EURs, very high value oil, NGLs. It’s resourced like and that’s repeatable and I hope we demonstrated to you very strong economics and cash flow out of that program.

So, with that I think we’re wrapping up. I just want to leave you with a few takeaways from what we saw today and I’m going to turn it over to Alton Heckaman to do the financial overview.

Alton Heckaman – Executive Vice President and Chief Financial Officer

Great, thank you. Bob and his group, great operational update. I’m Alton Heckaman, Executive Vice President, Chief Financial Officer. I’m going to wrap things up with the financial overview and tell you how we’re going to fund these exciting opportunities. We start out on slide 177 and give the proverbial cautionary statement, pricing and performance. Obviously, which you’re about to see include some forward-looking activity. Its non-historic, it’s not intended to constitute, nor does it constitute guidance with respect to the actual activity. So please take it as such.

I will start off with a reiteration of our 2012 guidance. We intend to follow up a stellar year of production growth in 2011, which was 26% with 14% to 20% growth and see the volumes we are expecting there. Our current reserve guidance for 2012, its 10% to15% growth and CapEx is in the 600 million range that we're going take them down a little bit for you today. To reiterate the cash costs, well, I guess both capital on cash cost side, DD&A per barrel is expected to be about $22. And then you can see the incremental per barrel cost here for LOE, G&A interest expense and severance and abalone factors. We will talk to you on one of our slides about the margins and what this represents going forward.

Capital expenditure by core area is currently shown on slide 180, indicates South Texas is the biggest share at 75% to 80% of our CapEx. It is expected to be 70% in Central and South Texas, on the activities that you saw today, Southeastern Louisiana with a rig back in there, kind of ramp in that backup given it's oily component very positive expectations there. And then in CLAETX, back in there, little more backend loaded given the timing of some of that activity, but you can see from the presentation today kind about ramp up, that we are excited about each of our core areas, but this one clearly has some resource like potential down the road.

And as always, we’ve got a portion of our CapEx that we designated this questionnaire what the board has given us the question if you will that are based on pricing and the results. We have the ability to ramp up any particular core area that we’re having success in and so that makes the complemented the 575 to 625 range that we currently have for 2012 CapEx program. Our financial strategy has not changed much if it all in our 32-year history. A couple of the takeaways from that, as we continually strive and improve our credit profile. I think we’ve done that over the years very successfully. We’ve always been very physically responsible and that’s why we’ve been able to survive the lows, don’t get too hyped in the high (indiscernible) in the lows, but maintain maximum financial flexibility, low leverage, high-liquidity is kind of mantra.

We strive to preserve a strong balance sheet through the appropriate mix of equity and debt and the timing of such, I think the last couple of years, we’ve proven that quite well and we’ve realized we’re in a risky business. So, we try to identify and mitigate any risk that we can in the borrowing industry cycles and we’ll show you a slide on that in a bit. This is looking at our cap table, really the last two published annual financials, yearend results of 2010 and 2011. I think the takeaways from this is clearly with the ‘08 and ‘09 as financial tsunami and that we saw and we have mentioned a couple of times today of similar things we have done, both operationally and financially. I think we took all the right steps.

We had kind of earned our way back to a reasonable debt-to-capital level in 2010 and had a very successful offering – equity offerings toward the end of 2010. They got us in good position heading into 2011. I think took all the right steps, had some very successful projects and clearly and looking at the opportunities that we had for 2012, we determined in November when the high yield market was open, that it was an opportunity to see that the projects we had to successfully execute them in South Texas, with outrun cash flow in 2012.

And so we effectively prefunded 2012 cash flow deficit with a bond offering in November very well executed. I really like the results of the lettering of our bonds, the nearest term maturity is 2017 and new ones we issued out in 2022. So, it’s a little bit lettering of the long-term debt that we have with the cash on the balance sheet ready to implement. It puts us in a very comfortable net debt to cap still in a low 30% range, historically that’s very comfortable level for us and well below most of our peers.

On my note obviously our bank line is completely undrawn that’s a 10-member bank group. I think just virtually all of them are representing here today, but it’s a very good group that has been together for a long time, the $500 million facility is actually we have set at $300 million as far as the commitment amounts that we pay stand by fees on. But it’s all dry powder and with an opportunity comes along that is available to us and enhances our liquidity, reiterate now once to May 2016, so plenty of running room there. This also shows that the bottom the effective liquidity that we have as well as some of the credit stats. I think the next slide actually goes into the stats that will come up in a minute. We have mentioned today our Gulf Coast pricing and how that’s been a real boost for us. This just sort of graphically depicts how that's shaking out the last, almost a years' time here.

I think when this first came on us, people were expecting this maybe to be a phenomenon that lasted for maybe a month or two, but you could see here that it’s really lasted longer and it’s probably on average been $15 to $25 at the feet, probably $15 to $20, it’s kind of the spot works that’s settling out and here of late it’s been about a $20 delta. So, it’s worked out very well for us, especially again since 80% of our crude is all based on this Gulf Coast premium either getting HLS or LLS pricing.

I mentioned the credit stats here on slide 184 that shows the last five-year history. As far as the top two are really kind of net debt approved reserves, the net debt to cap at a very comfortable level for us, the bottom to coverage ratios look really strong as well. So, we like currently where we are positioned relative to moving forward with executing our strategy.

Another metric that we look at that may be is not as domain as it has been in the past given some of the movement in the PV10 numbers, but you always want to look at how is your leverage stacking up compared to your PV10. This just does graphically shows your PV-10 the last three years as well as the comparison to the debt, we have outstanding debt and bank borrowings, if any outstanding as well as whatever the facility amount is that's available or your available liquidity. In other words, what your leverage could be at any point in time compared to PV10, again a very comfortable level given, and I think this stack up very well compared to our peers.

Talked about our price risk or the fact that we try to identify and mitigate any risk in our business that we can obviously operationally we do it on a daily basis as well as financially. But one of the things that we do that’s a little bit unique as opposed to swapping out all our prices, we feel like people have Swift Energy Company in their portfolio as a complement to their other activity or as a hedge. So, we don’t consider ourselves that be the ones that need to be picking the exact gas price or oil price, where we lock it in and that’s going to be the high side. So, we typically have layered in floors and near term forward sales and even done some participating calls with callers, but the bottom line is we see it as insurance against a precipitous decline in prices.

The things we like about it is it’s really a fixed premium, it's kind of like the house insurance that you have. You pay your premium, you know what your outlay is, you hope your house doesn’t burn down, and you hope your house doesn’t get flooded, but you got insurance in the event that happens. And I think probably the poster child for that for us was fourth quarter 2008, where we had about 50% of our crude oil and 50% of our natural gas protected with floors. That’s the good news we are protected. The bad news is the price as we all know went south very quickly for both commodities, but we had insurance and we are able to correct, I think little over $30 million, which it worked exactly as the strategy was in place to do. It gave us the money to sort of slow things down and ramp down our activity and kind of bring us in for softer landing. So, it’s one of the reasons and again highlights the fiscal conservatism and position that we always want to be in of being able to protect yourself against the declines and downturns, which are inevitable in our business.

So, we typically target 20% to 50% of the volumes and obviously it probably goes without saying that we are try to buy into the strength. Given our strategy of just buying floors, you can typically only go out maybe 90, 180 days the four-time value and volatility starts costing more than you are willing to pay for premium, it be like going and trying to get insurance on something for 10 years versus going to get insurance for a year. So, in any event, that's our strategy. It's worked well for us. Never say never, we continue to have discussions and they have been having discussions about our price risk management strategy for the last 25 years, but given the predictability of some of that activity in South Texas, and given the rest of the expand of any hurricane exposure and things of that nature, it’s something that we’re like talking about that maybe accelerating some of the activity down there by rocking and some pricing might be something you hear about us in the future, but again I will tell you this strategy has worked well for Swift and we feel like a complements people that have this in their portfolio.

Okay. The next slide is our 2012 CapEx budget. It is slide 187 for those scoring at home. It really depicts two things I think. On the left hand side, which is historical expenditures for Swift. The last five years, it shows we practice what we preach. We basically have been spending cash flow. You see how that’s deviated over the last five years, but we stuck to our guns and really pull things in with the tsunami, and I think we made all the right moves and it ramped back up.

As I mentioned in 2012, we saw this as a year that by pre-funding the shortfall that we could get out in front this in South Texas and get it to the point, where it’s sort of the break over point of becoming self-funding of which we can see that happening given success and pricing. So, on the right, we just sort of split up the $600 million, we expect spend for 2012. That’s a new here really shows 80% being in development in nature of lion share, which is going to be in South Texas. We do have some prospect cost and seismic and obviously some facilities and some of the newer projects and then clearly the discretionary pie slide. So, we set in 2012 to we ready to execute.

Couple other slides. Here just sort of talking about the future. Here is our actual 2010, 2011 cash flow per share data and then we show you the way we kind of computed and the model here we’re going to show you today as well as sort of a range as far as what first call has out there for us the cash flow expectations. And then in the next slide is really the same information relative to earnings per share. Obviously, people follow cash flow a lot more closely, this is a quite a big delta range between the different first call estimates, but nonetheless there is sort of a spread on the earnings per expectations for 2012, but there are a lot of variable involve here.

Okay. Given all the information that we provided you today and sort of slicing up our expectations for our money is going to be spend in 2012. We’ve decided to kind of wrap things up, as we traditionally have done in our last several analyst meetings, kind of run through a model. I guess just kind of framework or give you benchmark that when new modeling and things, you could see its close.

So, on slide 190, we talk about the assumptions that are in the model and the results we’re going to show you today. We ran in market price. We took the strip as of March 2nd and it basically with $106 for accounting year 2012. Gas is under $3. Again, we are talking about the strip in NYMEX. It’s somewhere around 50% of NYMEX oil. The guidance estimates, we talk about CapEx, midpoint of $600 million, production assumptions low in the high case and then ending reserve growth expectations.

And the next slide shows you the results of that, on the low case production side on the left, high case production side on the right, shows revenues, income, EBITDA. As you can see here cash flow $350 million to $380 million, exactly what we said relative to bridging that gap with the debenture we did in November to cover the $600 million cash flow. You see the earnings that would result from that low and high side as well as cash flow per share approaching $9 on a high case production component.

And then the next slide, which is slide 192, shows the sensitivity relative to prices. If you take the strip pricing that we use, the gas price on average for the calendar 2012 is up or down a dime. Our oil prices were up or down a $1 from the strip that we used for this. You can see the effect that would have up or down generally speaking relative to EBITDA and cash flow per share to deviate $0.09 to $0.11 gas versus the oil and then income side from $0.05 to $0.06 on a fully diluted basis.

And this really just shows the scenarios of any credit stats as a result of those two cases kind of fast forwarding into the end of 2012, what our coverage ratios would look still very comfortable and strong, our worst case, gross debt, the book cap gets you up to 40%, which again is it’s something will be very comfortable with on a Boe basis and compared to the PB10, would still be less than 40%. So again very still and a very strong position and hopefully had kick started some of the assembly line relative to show activity in South Texas as well as in the other areas.

Okay. And this is a favorite slide of mine and this is showing the history which you could extrapolate it out going into the future as well, but it’s all about the margins. And we show this slide because people seem to get sort of tied up in details times and when I talk about too much gas, not enough complement of oil this is too high, that’s too high. It’s something that our founder Earl Swift used to talk about all the time that if you look back for a long enough period of time, the way the world works is whatever price you are getting on average for your hydrocarbon that over reasonable amount of time it’s always going to come back to in the equilibrium, if you are doing what’s suppose to be doing if things are working right we are about a third of that price whatever it is, is going to be for cash cost.

So it’s your LOE, it’s your G&A, it’s your interest expense, it’s your severance tax and that’s what we demonstrate here with the bottom part of each of these bars. I would tell you what color it is, but I’m color blind but the bottom part of this is where the cash cost, the middle part is DD&A which is sort of a proxy for what your return on capital is, okay, you got a upfront money that you are paying for this. But over time it’s about a third or what the cost should be if the world is working right. So these companies at times might get a little bigger piece of that pie or in this case bar, but it’s going to work down overtime when prices come down and we are seeing that service cost is coming down to sort to get in line with this. And if you are performing as you should about a third over time of what that hydrocarbon prices should be your margin or your profit.

And, I’ll be – if looking back- there has been some real – sometimes when this has gotten little out of whack, but if you look back – three or four quarters or maybe in some cases the year and half you have to it has some real out swing it works out to its about to a third of third of third and I think again this sort demonstrates what kind of back on the path of that. So if prices come down and we are seeing this luckily, we’ve got a big complement of liquids improve, so keeping our price up okay, I guarantee folks that have waited heavily for gas right now, that’s given out whack for them big time okay, but for Swift, this complement, it shows it’s working and if you push us into 2012 given the at least a model that we shown it would be very close to be in the third of third of third category. So I think it’s a great slide kind of shows, how our business works from a macro point of view.

Okay, let me wrap up with – we always tell folks when we are out have an opportunity to tell a story that we realize we’ve told you a lot today. But we have tried to bore it down to five things as you walk out here, if you remember nothing else to be these five things. Hopefully, we demonstrated to you today that we’ve got the folks, we got the opportunity, we got the portfolio, we got the assets and we got the operational experience that we use world-class – not bleeding edge, with cutting edge technology to support our experience in our operational expertise. We think that differentiator for Swift. We always maintain balance and focus, I think hopefully you are seeing that today in our asset base review. We have significant resource within our legacy assets. That’s something we have, a lot of folks have jumped on the shale bandwagon, the shale play came to us in South Texas. We’ve thought someone did everything right and that set us, where we have real some neat core assets that we can apply some of the shale technology to on our legacy asset base that all by the way, just happened to be hardly oily and more liquid. So that’s a real good thing for us in this pricing environment where oil and gas have bifurcated.

Two proven resource plays with multi Tcfe upside and again liquids, liquids – liquids in these resource plays and clearly last, but not least, we’ve got a strong balance sheet and we got the liquidity position to be able to execute. So, with that I will thank you very much for your attention today. I think we will have plenty of time to field any questions, that’s always a good part of discussion because we want to answer what’s on your mind.

So with that we will turn it over to the Q&A portion.

Question-and-Answer Session

Unidentified Company Speaker

We are going to have a question and answer period and this is made by, via webcast and so I think Paul has a microphone, if you can walk around to people with questions and I will likely repeat the question and then we will hand it over to the person who is going to answer the question.

Unidentified Company Speaker

We are also accepting questions over the web for those listening on the webcast will relay those as well.

Unidentified Company Speaker

Matt, for the benefit of the webcast audience you might tell us who you are and then ask your question.

Leo Mariani – RBC Capital Markets

Sure, it’s Leo Mariani from RBC Capital Markets, it’s quick question your discretionary CapEx for the year you guys talk about $45 million to $55 million, I think on your slides you’d noted that you might drill an additional four PUDs Lake Washington, just curious as to where at this point in time you might think about allocating some of the rest of that discretionary CapEx kind of given the state of the well?

Unidentified Company Speaker

Well the quick answer is the liquids. The more complicated answer is – we’ve designed the (indiscernible), it’s not just a liquid base, but it’s also results base and pricing base. So we do have more that we can do both in I believe the Austin Chalk joint venture area we want to see how that’s plan out during the year. We have more that we can do as we’ve mentioned in the Wilcox in the East Texas area. We might do something there late in the year. We also could do little more in Lake Washington that we’ve showed that, depends on the results that we are getting, but equally important and it’s going to be a competition for that capital. We are doing some of these new techniques in the old portion of the Eagle Ford, and if these techniques are working as good as we think – that would be a place that we compete for that money.

Unidentified Company Speaker

The other thing though remember about that particular number because that was probably a little bit more specified last fall when we look at our preliminary budget and we beat that kind of move little more into discretionary just because of the outlook for gas prices and the uncertainty of what our cash flow going to be. Now plan as to spend our cash flow plus the cash we had in the bank, which means you are spending out spending flow significantly, but we pretty find a debt with the fall and a debt offering. We intend to move our spending really into a cash flow neutral spending pattern by the time we moved to 2013.

We are not going to continue to that -- but deficit spending mode. And so the pricing outlook, particularly with regard to oil and natural gas pricing and how that impacts our cash flow and how we see it moving into 2013 will certainly have a bearing on that discretionary part which could shrink but it also could expand dependant on those factors. We’ve got plenty of identified opportunities and as Terry said we want the teams to kind of compete for that, so where we’re getting the best performance and how that relates to the pricing environment that’s impacting cash flows.

Neal Dingmann – SunTrust

Hello guys. Neal Dingmann with SunTrust. I'm just two quick questions, first, Bruce, there you obviously have a lot of opportunities. I'm just wondering you mentioned about the two rigs coming there quite soon. You talk a bit about maybe expected type curve obviously with the pricing there that’s pretty exceptional these days. So I am just wondering as part of laterals et cetera on that area?

Bruce Vincent

Yeah, what we’ve done is we share a lot of data with our partner and obviously with us drilling wells and them drilling wells we share that data in a cooperative manner. Some of the laterals that we’re planning to drill with our partners are actually going to go out to 7,000 or 8,000 feet. Now they think they can do that and keep that cost around the $11 million range. I think the best thing to show for the EURs what we showed earlier, you are getting between 300,000 and 400,000 barrels, you’re getting in the oil, the same thing in NGLs and anywhere from 1 to 3 Bcf and that’s pretty consistent with what our partner has done on the Texas side and what we’ve seen in the past on our side. So, we’ve already been in all of our areas, we go back in and look historical and match our type curve with what we’ve seen historically.

Neal Dingmann – SunTrust

Okay. Then just a follow up, overall you mentioned about you’re protruding your own box site and pad drilling a lot of these things that maybe company of your size generally is not doing out there. I’m just wondering if you sort of between all of that, what type of maybe six months, 12 months from now, what type of total well savings could we be talking about when you sort of encompass all of these things?

Unidentified Company Speaker

Well, yeah…

Neal Dingmann – SunTrust


Unidentified Company Speaker

I think we showed you that really we have driven that first phase. There is kind four phases to our resource play development. The evaluation phase, we were drilling shorter laterals that we were getting core data logs. We were doing a lot of extra work. We have obviously driven those costs down when we started the drill the appraisal wells, because we cut out a lot of the evaluation logs and cores and things like that, but we still weren't stretching those laterals out.

As we started moving into the longer laterals kind of into development phase, I think we told you last year, we are kind in the $8.5 million to $9.5 million. And so we kind of landed on 6,000 foot laterals in that range. Since then we have driven the efficiencies even drilling the longer laterals and have really cut that $9 million well down to about $8 million. And now as the next phase starts ramping up, what we’re working on right now with the pad drilling, with the supply chain initiatives, with our negotiations, with our efficiencies, we see another $0.5 million to $750,000 that we can start to capture beyond the numbers I just described for you. So, that kind of in a very – in a very summarized way hopefully puts that into context for you.

Michael Hall – Robert W. Baird

Thanks. Michael Hall with Robert W. Baird. I guess in CLAETX just curious things like maybe things are little slow getting started or how would you kind of characterize the risk that those two rigs coming gets pushed back a little bit and how should we think about that?

Unidentified Company Speaker

I will let you answer that, but they are common. I mean, it’s in the schedule. I think last year, what happened was our partner needed to reallocate those rigs to other acreage they had that was 100% and that shifted the joint venture 50% drilling pushed out, but we have definitely had a meeting in minds. We have had several meetings with them. Our technical teams are working well together and they have actually accelerated a little over what we originally thought, so not only the first rig coming, but they have scheduled in the second rig shortly after that.

Michael Hall – Robert W. Baird

Okay, good to hear. And then the other one for me as you do move to more pad type drilling in different fracs and what not, so we expect any sort of meaningful lumpiness and are there quarters in particular or that might show up?

Unidentified Company Speaker

The question is asking about lumpiness in our quarters in terms of production growth?

Michael Hall – Robert W. Baird

Correct, sorry.

Unidentified Company Speaker

I don’t think so. I would have to through our modeling at that level. Steve, you want to add?

Steve Schmitt

Yeah, the teams really do a good job of planning out the schedule, and yes, it does create a little bit of lumpiness for us because we'll where we had the four wells on a pad, you had to drill them all and complete them all and then you bring them all along at once. So, you are going to see a real spike in production then. Right now in 2012, we have only got one instance, where we are doing four wells, everything else is payers. So, when you get down to payers, you don’t see that delay. So, it should be relatively smooth and something that you may see one spike in production, because we bring those four wells on at once.

Unidentified Company Speaker

Yeah. And while you are going to get that, I am not sure in the overall scheme of things when you put it in with everything else that you are going to see a significant lumpiness in on quarterly numbers. I mean, Steve said is absolutely accurate, because you got to do all four wells before you write in, you bring all four on production, but mixed in with everything we are doing. I don’t expect to see a significant lumpiness in that. And if there is we will allow for that in the guidance that we put out.

Adam Leight – RBC

Adam Leight, RBC. Just you mentioned a couple of times in your strategic plans, acquisitions, could you be a little bit more specific how serious you are of size, what kinds of properties you might be looking for and how would that affect the rest of your capital budget?

Unidentified Company Speaker

Question about the acquisitions and as part of our strategy, if you look back from the time we report them and then if you go back to like one of the slides that you really had early on in. With regard to strategy, we have always used acquisitions and drilling as part of our strategy. We think it’s important that companies have expertise in both areas. You need to move back and forth. Generally in a high-price environment, you want to be drilling in a low-price environment, you want to be acquiring. We have not (Technical Difficulty) which is the last couple of years. We have been focused much more on the drill a bit, but our view is that acquisitions and deal making is something that you can need to continually kind to be involved in and stay in shape, just because you are not doing it. It’s not the kind of thing you want to just abandon and then obviously get do one. And so we do have a group that looks the joint ventures and business development or acquisitions all the time. We are looking at deals all the time.

Now, I will tell you, we are not that serious right now because we’ve got plenty to do. We are already out, spending cash flow with the drilling opportunities and so, but we don’t want to abandon that part because in an environment like this, particularly when you get a low pricing environment, some companies don’t maintain their balance sheets the way we do. We think there’s distinct possibility for companies to have trouble issue and so, we want to kind to keep our oil in the water and look for that is not a high priority for us, but if the right situation and the right area comes along we want to be in a position to take advantage of that. So I hope that answers your question very well. But I think it’s an important part of our strategy, we want to stay involved in it. Obviously, we’re not budgeting anything like that unless some good opportunity comes along, I wouldn’t expect us to do something. In terms of size, I think we want to do something large enough to be meaningful, but not large enough to create any stress on the balance sheet.

Adam Leight – RBC

I have a follow up. How backend loaded is the capital spending program, are you on pace for a $600 million number so far this year?

Bruce Vincent

The question is regarding the backend loading of the capital budget, it’s actually little more front-end loaded. If you really look at it, we want to – in order to get back into cash flow neutral spending by the end of the year it really needs to be tailing away towards the end of the year. So, we are definitely on pace to spend $600 million at least through the course of the year. We are watching that real closely, we are watching our projected cash flow known us for some time and we’re going to try to live within what we said we’re going to live within in terms of our cash flow and the cash in the bank. We are in a great position liquidity wise and we may get the question later, but we are obviously coming up with our bank (indiscernible) review and they burst lot of our bankers in the room here. So, I don’t want to speak to what they’ll do, but given that we don’t have anything borrowed, given that our borrowing, our commitment amount is actually less than the borrowing base, we don’t proceed any real difficulties from our perspective on that. We know some companies probably may have some concerns with their borrowing base reviews that also may bring them back some challenges for companies in terms of moving within their own means, I mean, which may put assets on the market back on the acquisition side if you will.

Unidentified Company Speaker

Yeah, I just want to add to the comment that Bruce made about that’s managing ourselves so that we’ll be in a much better place at the year-end with prices, not be up on natural gas, which we really don’t expect. But keep in mind, we're growing the liquids and so we’re growing those kinds of products that give us good margin. And in this plan that we got, we really haven’t put this large premium that we see between NYMEX and Brent into our plan. So, we don’t want to bet on that happening. Even though, it’s been very steady and stayed there for quite some times. So, it’s kind of some upside in our cash side, in our pricing side that gives us some flexibility as well.

Andrew Coleman – Raymond James

Thank you, Andrew Coleman of Raymond James. I had a question on that pricing. Is that given a strength of brand is does that change any of your short-term hedging outlooks, I mean our model using the strip you to get north of $700 million of cash flow plus some mix improvements that provides a lot of additional capital should those numbers going to be up?

Unidentified Company Speaker

Yeah, the question really revolves around the premium that much of Swift’s liquid or crude oil particularly getting the Brent. We are modeling the much more conservative outlook for that, but with the way our spending set and the way our inventory is, it’s very easy for us to accelerate spending if we see that cash flow increasing or what we’ve forecasted. And we've talked about earlier, HLS, LLS is running roughly 22 bucks plus or minus of WTI, I think we’ve been modeling like 7 bucks or something like that in our just internal budget. So we’re being pretty conservative now. I would tell you we are little high priority on the gas price, we have been using three in quarter, obviously it’s a little less than that, but well over 80% of the revenue is just coming from liquids. So, the sensitivity is much more so on the liquid side in terms of pricing outlook, but we have an inventory that’s specifically identified, that discretionary part that we call discretionary if you go underneath that there are specific projects really that got to that number. It’s not a blank rule so to speak and the nature of our inventory, which we hope we’ve given you much better feel for today is very identifiable. And it’s very easy for us, we believe to access the rigs or services or whatever that’s you need to do that and the budget been a little more front end loaded, telling after the interview cash flow outlet is high enough, we can just keep that activity low. Believe me the teams always coming in and ask me to do.

Unidentified Company Speaker

Yeah, as to the hedging question to actually hedge that differential is a much more complex in different marketplace in fact than your traditional hedges. We’re looking at that seeing what’s available to us, as Alton said our traditional approach has been forced, but as we build this inventory and build the liquids, we’re looking at the very tiny thing that you suggest. We aren’t doing anything real quick, real different, but we would stage ourselves into it, so we change the strategy.

Unidentified Company Speaker

One way we have done that in the past is it’s a way of hedging, but you’re actually making a forward sales to your purchaser and we generally just down that had about three months, but that is one way to kind of lock in some of those differentials because you can pretty agree with them on what that spread is and tie back to WTI.

Andrew Coleman – Raymond James

Okay, thanks. And I like just start on one more on the Bay de Chene and Lake Washington. I guess with what overall projected at 12% and gas growth, I guess declining 12% based on your current forecast there. Would you say from the capacity side on the facilities that you’ve got, which asset has more water handling capacity and I guess gas handling capacity is subset, you will be able to kind to grow into that one faster as you look at those two key assets over the next one to two years?

Unidentified Company Speaker

The question really is about facility capacity at Bay de Chene and Lake Washington at both in terms of production capacity and water handling and Bob or Steve?

Bob Banks

Really Lake Washington, were really well set. When we built that Westside facility, we really bumped up our liquids handling capability, our gas handling capability and our water handling capability. We’ve also done some water handling enhancement on some of our other platforms and Lake Washington. So, we’re probably in the best position now in Lake Washington to handle higher volumes of liquids, gas and water.

Steve Tomberlin

Yeah, just to add to that. We have enough capacity with Westside and if you ever go there, it’s state-of-the-art offshore facility and we actually, there is a production operations group is looking at the possibility of shutting down a couple of processing platforms out there in Lake Washington and routing everything to Westside to reduce operating cost. So that’s how confident we are in our capabilities out there.

Mark Lear – Credit Suisse

Hi, Mark Lear from Credit Suisse. On the infrastructure side, I know you’ve got that $90 million a day secured with Southcross, but just want to see what would be the additional infrastructure needs outside of (indiscernible) where you’re ramping there this year the kind of (indiscernible) with that three-year plan. What kind of additional infrastructure commitment might you need?

Unidentified Company Speaker

Yeah, one of the things that we showed in AWP is, we’re getting out of the gas drilling. The gas drilling we will be doing will be pretty, actually be condensate with associated gas, and won’t be a large number of wells per year. So, we are in a great shape right now in the Southcross area. Fasken, we are not doing anymore drilling. We are pretty well right now. Transporting everything that we want to transport there and then the big deal is going to be Artesia. So, I’ll let Steve talk a little bit about Artesia.

Steve Tomberlin

I think as I mentioned before, we are currently in negotiations with several pipelines in the area that do have firm capacity available on the process, again transport side. So, as those negotiations move forward and we finalize and we will of course be hearing about that.

Mark Lear – Credit Suisse

I just wanted to follow up also on the reserves side, and lot of the growth yearend ‘11 came from gas PUDs in South Texas, and you’re telling some story here that you are not going to be drilling a lot of gas wells over the next three to five years. So, do you kind help us, reconcile us that different?

Unidentified Company Speaker

Actually, we were looking at that this week, and actually look at nine different models that I showed. I sat down with our director of reserves. We went through and looked both numerically and both graphically where we had book PUDs and where we haven’t book PUDs. So what are you going to see is, if I’m remembering the numbers correctly, we booked about five to six PDPs and five to six PUDs in the LaSalle County area so obviously as we drill half our wells there. The reserve adds they’re going to come from the oil model in LaSalle and the condensate model in LaSalle. You pretty well have the same thing in the oil areas of McMullen and condensate areas of McMullen. If you look at none of them have gone to any down spacing. All of our bookings have been based on 160 acres spacing. If you look at the different areas, the ratio of PUDs to PDP well ranges from maybe two in some areas to three in others at averages 2.2.

So, we’ve taken and what I consider a fairly conservative booking strategy. Now, we’ve booked Fasken completely on 160, so you’re not going to see any additional booking there until we test 80s, which is not going to be until the gas price turns around and then we haven’t heavily booked at all in the southern part of AWP in terms of other gas area. So, all-in-all what you’re going to see is what we’ve drilled this year, we easily get a couple of PUDs and it’s going to be liquid growth as supposed to gas.

Unidentified Company Speaker

We’ll get some gas growth because the associated gas, but the liquids of the focus, so that’s where most of the growth will come from.

Unidentified Company Speaker

Yeah, I want to add to that last year when we had this meeting, we did bring forward Fasken and clearly we weren’t able to foresee and the future exactly what would have with gas prices, but we were, I believe very accurate in terms of what we said we’re going to drill out there and in fact the performance was actually better than what we’ve said we’re going to have out there well that did make the reserves larger than we had expected in that regards, it’s a good thing.

This year, we’re bringing forward in the same way what we think is going to happen in the liquids and we’re very confident, we’re going to deliver the liquids this year and I would like to focus on the fact that we don’t have a large inventory of gas wells that are not fraced, waiting to be fraced come into the market, we’re having that. We don’t have our large inventory of acreage that’s gas acreage that we have to drill to preserve (indiscernible) those assets. So, while we would like to gas prices to be high and to be able to enjoy better margins from Fasken. I think we’ve done the right thing strategically and everything has focused on the reserve growth in 2012 being liquids, they have identified these areas. I think they’re going to make it.

Unidentified Company Speaker

Yeah, I’d like to explain upon one point that I’m not shows fully appreciate with that. Because we’re developing the Olmos and the Eagle Ford and once it’s on the top of the other really a common surface area. That has given us this what I view as a very strategic advantage to negotiate – go back to the mineral owners negotiate with them, but I don’t want that dry gas for Eagle Ford drilled up either to allow how much activity to extend that leasehold for the Eagle Ford rights as well. And so we’ve been able to push off any dry gas obligations and at least 2015 that’s not true of any other operators.

One of the other things is going to happen in the industry, not just because the low gas price, but partly because of it is – you’re going to see a lot of companies that are having trouble leading their release obligations. So, you’re going to see a lot of acreage come back on the market. Now dry gas acreage nobody is going to want it – turn around or releasing because we’re not going to want to drill, but it is going to be interesting to watch what happens to different companies. We think we’re taking care of a large part of those issues with our activity. Because we have been developing this Olmos (indiscernible) we have other activity with mineral owners, but we are, however, just happy as could be with our activity and they are aligned with what we want to do.

Unidentified Analyst

Hi. This is (indiscernible) with McKenzie. The question was asked about acquisitions I had a quick question about joint ventures and it looks like some of the best South Texas metrics are in areas where you have joint ventures of Petrohawk (NYSE:BHP) is there any appetite for additional relationships like that?

Unidentified Company Speaker

Well. I take that first one Bob can fill on that, the nature of joint ventures in South Texas certainly for us I think would change going forward.

In the early part of the trend everybody was competing for acreage and those that got positions together work with others to form the joint ventures and operators didn’t necessarily work well together. We were very competitive. We are now in a phase of the industry, where there is pooling of acreage that goes on where you may have 500 acres in an area and another guy has got 2000, you've got 2001, you've got 500 in another, and we are finding that folks work together now and so I think you are going to see a lot of small ventures, I wouldn’t call them joint ventures, but you will see more cooperation among operators, more small ventures.

In terms of joint venture, we don’t really have an appetite to put any of our acreage into such a thing. I mean if there was a player that wanted to go drill the gas right now, we could probably talk with them, but I don't think that's going to be the case. We do have other areas though where we are working Bob talked about some of our strategic areas, where we are trying to put together some oil, our liquids-rich types of resource play areas and that might be an area, where you might see us do some, some more joint venture type things with similar types of players that we have done before.

Unidentified Company Speaker

Yeah. And I'll just add I think, I think we can review this after the meeting, but I think actually our financial metrics are quite a bit better and a lot of our 100% acreage than what we had in that joint venture.

Unidentified Company Speaker

We have one question from the internet. A participant wanted to know, what if any Swift acreage in Louisiana and elsewhere was perspective for Tuscaloosa Marine Shale prospectivity and development in the future?

Unidentified Company Speaker

Again, I will take that first and then I'll let our geologist, geophysicist add to that point. We think it’s a very interesting play. And if you look at the play on a regional basis, a lot of our acreage is in what I would call the fairway. We don’t have any specific plans for this year to drill any particular wells and go after. We are watching the play, a lot of things are happening. There is also the Smackover play that we are watching and that’s probably in my mind about the same kind of situation sort of Tuscaloosa Marine Shale, but definitely our acreage is in the play fair rate, maybe not the best part of that fair rate though, John?

John Branca

Yeah, that’s exactly right. We are pretty well-positioned in the play. Our chalk acreage is in the play and we have some offset players out there, drilling wells. We are watching those very carefully. We have studied the play and we are prepared, should they have some great indications, we are prepared to drill wells there. We don’t have to drill wells. The whole of the acreage has been held by our chalk production. So, it could come to us, and we have studied it quite extensively.

Unidentified Company Speaker

I think the other comment, one of the other things about Louisiana that’s need to remember that we have mentioned when we talked about our chalk acreage, is that we have a pretty significant position where we own the minerals and some of that which is north of the Anadarko, AMI, it’s probably more perspective in the Tuscaloosa Marine Shale, but we don’t have any obligation to drill it, so we can sit there and watch other people that develop the play and still there is an opportunity that works.

Unidentified Analyst

Can you just expand a bit more on down spacing assumptions over in the Eagle Ford, how confident are you that you could actually get down to acreage spacing, and what data do you have support that and if you have picked any sort of inference into your (indiscernible) assumptions? Thank you.

Bob Banks

Yeah, I’ll start and then I’ll turn it over to Steve to get a little bit more detail, but when we showed you our micro-seismic that we did, really we are basing a lot of our drainage based on looking at effective half-widths of our fracs. We are really testing for the first time now, some of the down spacing concept. The closest we have drilled in the past has been 160. We have had no interference in the Eagle Ford on 160s at all. We have run a lot of micro-seismic by putting observation wells next to one another, where we could really measure those half-width of the fracs. And it’s based on that data that we developed a lot of confidence that we could go down and test the 80 acre down spacing.

Steve Tomberlin

Yeah. I think Bobs something up well the only thing that I can add is a tag on what Terry said earlier about cooperation amongst the operators. We do have some informal consortiums that we work through where we’ve technical meetings with a lot of the operators out there and I think you’ve seen it their press releases. There are some other people who have actually done interference testing down to 55, 60, 100, 70 acres and we’re talking all those people, looking at what they’ve been doing and this is the year we’re going to test the 80 acre concept and those – all those oil areas of the Eagle Ford and then the compensate area that Eagle Ford. We’re going to test I talked about pairs. Those pairs are going to be 80 acres spacing test, but we’re real confident that’s going to work.

Unidentified Company Speaker

Any other questions? We'll thank everybody, those listening on the internet. Thank those of you. We really appreciate having the opportunity to talk to you about our company.

Unidentified Company Speaker

Okay, thank you.

Unidentified Company Speaker

And there will be lunch served right outside the doors for those are here.

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