Murphy Oil Corporation (NYSE:MUR)
2012 Analyst Day
May 08, 2012 3:00 pm ET
David M. Wood - Chief Executive Officer, President, Director and Member of Executive Committee
Kevin G. Fitzgerald - Chief Financial Officer and Executive Vice President
Thomas McKinlay - Executive Vice President of World Wide Downstream Operations and President of Murphy Oil USA Inc
Roger W. Jenkins - Executive Vice President of Exploration & Production and President of Murphy Exploration & Production Company
Sam Algar -
Roger Jenkins -
Unknown Executive -
Barry Jeffery - Director of Investor Relations
Paul Sankey - Deutsche Bank AG, Research Division
David M. Wood
Thanks. I believe we've now gone live here. I'd like to welcome everybody here that's made the journey to El Dorado. We are also webcast. I would inform everyone this is the first time we've done this. We know that people are very busy this time of the year, and we wanted as many participants as possible. And so we're trying out a webcast technology.
Let me talk about some housekeeping and agenda items for the day before I make just a few comments and get started. I would ask that as we go through each of the section today that we keep questions until the end of that section. I think that will make things run a little bit smoother for the presenters and also allow the questions to be asked in a straightforward manner.
Barry Jeffery, who's our Investor Relations person, is going to ask the webcast questions as they come in. If there are several questions that are asking the same topic, he will pick one. We're going to try and get as many of them addressed as possible in the time that we've got here.
I have asked the presenters that if questions are asked from the floor that they do repeat the essence of the question before answering, and I think that will help people understand both in terms of what was asked and also what's being answered.
The target is to finish around about 5:00, time for those here to freshen up before cocktails and dinner and expect here at this building starting at 7:00. The agenda is up on the screen right now. Kevin is going to start with the financial overview. Kevin is our Chief Financial Officer. We'll then go right into our exploration business and Roger Jenkins, who's the president and runs that business, will do the bulk of the presenting.
Sam Algar, who runs our worldwide exploration program, will talk about that within that presentation. We'll take about a 10- to 15-minute break, and then we'll come back and Tom McKinlay, who runs our downstream business, will go through that. And then I'll come back at the end and be able to pick up any issues or make any points, I think, that need to be covered right at the end.
Let me make a few comments about framing of what you're going to hear today from us. This is a long horizon value-driven business that we at Murphy Oil are. We are repositioning our business. That is underway. We're working to exit the refinery business. We have one left to sell. The first quarter results of Milford Haven refinery have been much better, and of course when you're selling something, that helps quite a bit.
We do have parties at the table for the refinery parties at the table for the retail and parties at the table for both assets together. And so I see that being done sometime this year. And I can't be more definitive than that. And clearly, while we're engaged in that process, I don't see any need to trigger the option to convert the refinery into a terminal, which I've mentioned before.
U.S. retail is an excellent business. It's a homegrown business. We started it in its form in 1996. I've we've mentioned before that we have engaged investment bankers to help us consider and value separation of that business from Murphy Oil Corporation. That work is ongoing. I would like to look at that and take it to my board this year, and that's the timeline that I'm working on. Execution once approval is given there is about 9 months through the set of approvals that we have to do to just frame what we're looking at here.
Today, when Tom is presenting, you will see the trajectory of that business. We won't get into the specifics of the balance sheet of that business or in the details going forward. Clearly, I want my board to bless all of that before we start talking about it publicly. But I think you'll get comfort as to where that businesses is today and where that business is indeed going.
The first quarter was a relatively poor quarter for that business. But if you look at the last 10 years first quarters, other than 2 years, they were all good. So there was nothing particularly unusual from our perspective for the first quarter. And here as we got into the second quarter, that business has picked up as we expected it would.
As part of that separation analysis, we've also taken a look at the stub company and our ability to cover dividends and other things here in the U.S. and also cover our foreign exploration write-offs. All of that is part of the analysis that is being done and the assessment that's being done that will be taken to our board. But I don't see anything in there that I can't get comfortable with and ultimately, I don't think that the board can't get comfortable with also.
On the upstream side, we have good growth in very good prospects. At the AGM last year, 2011, I talked about a production target of 300,000 BOEs a day achieved in 2015, and that included an expansion of our dry gas facility up in Canada and we call that Tupper Phase 2. If you took that number out of the whole numbers, you would end up with about 265,000 BOEs a day. As we go through the presentation today, the number that you will hear about is 260,000 BOE, is kind of an equivalent to that number or to the same milestone. And so I regard that as being equivalent. We've gone through a quite a rigorous assessment of how to get there, and we'll talk more about that when Roger's up.
We've also taken another close look at our production forecasting process, how things are gathered together, what risking is applied to them. And our aim here is to get better. We haven't been where I wanted to be, and so we're making steps to get better at that. That has been done, and in that 260,000 BOE number, all that work has been incorporated.
In addition to that, we've looked back and said hey, how much did we miss our previous forecasts and applied that same factor going forward to our production profiles? So if you will, another cut out. That's about 7%. Now it doesn't apply to the dry gas piece because clearly, shutting in, we have plenty well capacity. If prices improve, we could step it up. But within that profile that you'll see, we have that additional incremental assessment as I call it.
We announced in the first quarter that we would cut dry gas production back at Tupper. I think it's the right thing for us to do. It's a value call bias. It will hurt the near-term projections and you'll see that. But I think as we look at '14 and '15, you can see the impact and the strength in our program. I regard Tupper as being kind of a $4 dollar gain, and clearly, gas isn't fair today. I believe that $4 is going to be around in 2015, or at least I don't think there's anything to stop it from getting there. I think getting beyond $4 post 2015 is a whole lot of issues.
As you look at the components of our production, you can see the role of Kikeh, which is a great field for us. It is a great field now, and it will be a great field in the future. We have had completion failures associated with streams. We have a solution; that solution is working. And we have rigs working in the field to effect that solution. So we're not in the same position as all as we were 12 months ago, and so I feel much, much more comfortable about where we are in that.
Kikeh is an important contributor to our company, but by 2014 and 2015, in terms of net production, will be overtaken by the Eagle Ford. Eagle Ford is going extremely well for us. And also about 2015, it will make up about 15% of our production. So that's really a reflection of all the other good things we're doing and not necessarily any impact or any negativity at all on Kikeh which, as I've said, is a good field. And also in Malaysia, if you look at the production in 2014, Kikeh is less than half the production. This shows, again, the ramp-up that's taking place in other parts of our business.
I mentioned Eagle Ford, it's an important focus for us. We've made great strides in execution and capital efficiency. I see that as about $40 gain. By that I mean CapEx and OpEx. We're advantaged over other players as we did not write a big check. I'm not a great big check writer. We're in there for about $1,800 an acre, and I think that distinguishes us and the types of returns we can get in that program by the fact that we entered in, in a appropriate manner.
It's also a factor as we look at our other resource plays. When you look at the projects Roger's going to talk about up in Canada, we got in there for a very, very small dollars and one of them, particularly in Southern Alberta, I think is going to be potentially very, very attractive for us. And part of that is the fact that we recognized it and we got it very early and quite cheaply.
I've mentioned resource plays. We do have them. We're very focused on the resource plays we have. Other than Tupper, there are liquids. We are not making a move to be a resource player. I see a contribution to our overall production from resource plays, but not a replication or a replacement of our normal resources. I just see it as a value proposition.
We're really an independent E&P player with good assets. We operate just about everything that we do. We have an active, impactful exploration program. 2009 and '10, good programs for us. There was no single big discovery, but they did the things that we asked them to do. 2011 did not. We only drilled 4 wells. We did not make a discovery.
This year, we're off to a very good start. We've drilled 3 wells, made 3 discoveries, going to have a very active year this year, very active year next year. And Sam Algar, who leads that and does a great job with his folks in identifying and capturing good opportunities for us that will move the needle within that program, will talk about that.
So that's kind of where you're going to go today. There's lots of things to look. We're going to try and keep this train moving. I'm going to get off the stage, and I'm going to turn it over to Kevin. As I said, I'll come back at the end and pick up anything if there's any questions.
Kevin G. Fitzgerald
Thanks, Dave. As Dave has mentioned, I'm going to give a little financial overview. I'm going to start with our financial position, which of course is top-notch like I think as far as our balance sheet goes and basically second to none. [indiscernible].
First, we have our cautionary language, our cautionary language that this presentation has a lot of forward-looking statements. Naturally, there are a lot of factors that could cause actual results to differ materially. And of course, we're not take no duty to publicly update or revise any of these statements as we go forward.
Lets take a look at our first quarter, net income of $290 million, about $1.49 a share. Cash flow of $730 million and capital expenditures of $740 million. As you might recall, our operating guidance work under the mantra of trying to keep cash flow/CapEx parity. And so in the first quarter, we met that.
I will make a comment that the cash flow and capital expenditures, these numbers represent what I'll call old school accounting. It's more of the working capital bases. If you look at the financial statement in 10-Q, it will show actual cash provided from operations and actual cash capital expenditures. This is cash from the old school of accounting, which includes working capital changes and of course, these capital expenditures include accruals.
Our long-term debt at the end of the first quarter consisted about 30-year, 2029 maturity of $250 million. Of course, our 10-year maturity that expired or matured May 1 of this year is paid off last year of $350 million classified as current and short-term at the end of the first quarter. Stockholders' equity of $9 billion. Long-term debt as a percent of capital deployed of 2.7%. And then if you add back that $350 million of 10-year maturity, that would put the percentage of capital employed at 6%. So well at the single digit and extremely strong balance sheet.
The financial crisis of 2008, if it taught us anything, it was that liquidity is a necessity and we have to have a lot of sources of liquidity. Looking at it for this year, estimated cash flow of $3.4 billion. It was a $95 WTI and $3 Henry Hub pricing. With that assume a midyear conversion of Milford Haven refinery to a terminal. What that means is we have about $300 million of cash flow in our numbers, and you'll see it reflected a little bit later in one of the slides related to the liquidation of inventory at Milford Haven.
Of course, if we go through with the sales process, we will recognize the sale of those inventories anyway. So that amount of additional cash flow will go into the financials regardless which route we go. By leaving it in our forecast as a terminal, we didn't have to mess with estimating what sales proceeds might be. So the effect in the cash flow from liquidation of inventories is the same on both scenarios. In the current inventory at Milford Haven, typically runs anywhere between $500 million and $600 million. Of course, a lot of times there's some payables associated with that and that's why we use the $300 million number.
We have in place our revolving loan facility. It's $1.5 billion that we entered into last year, with out in 2016. There's about $350 million borrowed directly underneath that revolver. That was what we used to pay off the maturity, that 10-year maturity last week.
We currently have about $200 million of other funds that are borrowed under uncommitted facilities we've had with various members of our bank group. And if we do proceed with excess the bond market, which we're currently anticipating over the next week or 2, $500 million for 10 years, we'll use those proceeds to pay off the $350 million under the revolving loan agreement. The rest of it for general purposes at this time would be to pay off those additional incrimative [ph] lines that we have outstanding.
Our intention is to maintain our long-term bond rating. We're currently investment grade BBB with Standard & Poor's, Baa3 with Moody's. Stable outlook under both, and our goal is to go ahead and maintain that investment grade rating.
I've shown this slide for several years at these meetings and just like to reiterate that one of the criticisms Murphy goes through over time is that we run too conservative of balance sheet, and we should lever up. What it shows that in the past, we have actually levered up typically when we had a specific project to do that. That way we could borrow the money, develop that project, get the processes in that project towards operating and pay those loan proceeds down.
Specifically, here you could see we deal with the Ninian field back in the late '70s, and of course we were developing Kikeh earlier in the decade. Now Kikeh was sort of a twofold. We've got about half way through the process there in developing Kikeh. We sold some properties in Western Canada. It paid off a lot of that debt. And then finished off borrowing some money to finish off the development in Kikeh and then showing it coming down after Kikeh came on in 2007. That the debt is steadily declining since then with oil prices that we've seen. The big dip in our debt in a percent of capital employed in the early '90s, we got down to virtually zero as a result of Murphy selling the drilling rigs that were related to the ODECO acquisition that took place in the middle of '91.
Then to take a look at what our financial position may look like over the next couple of years. There's quite a few changes coming up next year, and we'll try to go through those.
First of all, the oil price assumptions, we have WTI $95 across-the-board last year. For 2012, '13 and '14, we were in the mid to upper 70s for assumption of WTI, so quite a jump in the oil price. We put our Brent prices in here this year starting out with $15 differential for this year and declining $5 per year forward. Now the reason we've done that is about 80% of our oil production is fully about 62% of our overall production is based on Brent pricing. So it actually gives a better reflection of what we realize in a lot of our sales.
Natural gas Henry Hub pricing, you can see here last year
primarily as a result of 2 different areas. One is the drop in the slowdown in the dry natural gas production and also with the 7% additional cut that was taken to our forecast going forward as David mentioned earlier.
One thing I'd like to point out, the pretty significant jump between 2013 and '14 of 50,000 barrels a day and this is a result of mainly 2 main 2 areas. One is the Eagle Ford, which was just ramping up the additional drilling we do in the Eagle Ford. We drill about 12,000 barrels a day. The other 30,000 barrels is going to come from a full year of production of a project over in Malaysia. Specifically, the oil project, the SK oil project and then the Siakap development and Kakap development. All of those projects to come on in 2013, spending a lot of capital to go there now til we get a full year production from those projects in 2014, and that's what makes up that 50,000 barrels of additional production there.
Cash flow from operations is up quite a bit from last year even though production is down as a result of having an increased reference price especially at the WTI and the Brent prices relative to last year. Capital expenditures are also up significantly from what we showed last year. Couple of things to talk about there. For 2012 and 2013, it's primarily additional spending at Eagle Ford, some additional spending related to Kikeh and then the out-years of 2014 and 2015, what we've done is have risk exploration spending in those years.
So what we've done is assumed that some of the exploration drilling that we're going to be drilling is going to be successful on a risk basis. That adds about $700 million to $800 million in the capital expenditure numbers of both 2014 and 2015. What that means is going forward, of course, if we were successful in all of our exploration drilling, those numbers will be significantly higher than that. And if we had some holes in our exploration, those numbers would be significantly lower, but it's $700 million to $800 million.
The cash flow and the capital expenditures result in the free cash flow that you've seen here before consideration of dividends. What I've done at the bottom line showing long-term debt is I've assumed that $200 million of our dividend each year would be either financed with additional borrowing or reducing that free cash flow that can be used to pay down other debt.
So you can see either with the capital expenditures running up, with cash flow staying strong, we still end up in the worst year with only $1.5 billion of long-term debt, and by 2015 going down to a minimum debt of $750 million, which would exist of the 2029 bond of $250 million, assuming we issue a $500 million bond in a couple of weeks. You can see with all our activity that our financial position is going to stay quite strong.
I mentioned the cash flow and CapEx priority that we try to maintain. This is just a graphical depiction of some of the numbers we've shown in the other slide for 2012. You can see in the downstream the difference in the cash flow of $500 million and the CapEx of $200 million. That's the additional $300 million related to the liquidation of the inventories at Milford Haven. They're showing overall in 2012, we expect a $300 million shortfall and add $200 million of dividend and that would be the $500 million of total borrowing that I showed on an earlier slide.
Staying with the capital expenditures. The $3.7 billion total this year, only 95% would be from the E&P. This should come as a surprise to no one, and that will be about the same percentage over the next couple of years. On the downstream, I've assumed building 50 additional retail stations this year. And the downstream capital expenditures going forward should be in the same $150 million to $250 million type range that we've shown in the slide earlier in the capital expenditures.
Looking at the E&P break down, $400 million of exploration. Recall 2011, our pure exploration number was quite a bit higher than that and included quite a bit money spent on some lease acquisitions mostly to Eagle Ford, but also up in Canada. It also included some drilling in the Eagle Ford, which is now classified as being development drilling. Of the $3.1 million development, you can see the 6 major projects down here comprised 90% of that spending. Plus, we have just under $1 billion at Eagle Ford.
In the deepwater Malaysia off of Sabah, $600 million of that is Kakap and Siakap, each of about $65 million to $70 million each that will be spent this year. The $500 million at Sarawak, about $100 million of that goes to the gas project. Net of $400 million goes to the oil projects that I alluded to earlier that was sanctioned by our board last year.
Looking now by region across Malaysia and the U.S., it should be no surprise there with developments we have gone in Malaysia, with the ramp-up at Eagle Ford, that is bulk of the spend in those countries. Canada's being dropped down at the third place with the reduction in the Montney drilling. And the other column is all the other funds that we're going to be spending in Indonesia, Australia, Congo, et cetera.
Finally, looking at downstream, the $200 million, the largest piece of that is in the marketing segment, represents building about 50 sites this year. And so the $200 million, so 85% of it is going into the marketing group, the remainder to U.K. retail and refining.
So to conclude on the financial side, again, we have our operating groups continue to live within the goal of cash flow. That's how they sort out every budget process, every outlook processes as we go forward. If we can stay within the cash flow that's being generated, you'll lose a lot of dry powder with the liquidity sources and access to market that we have, and we can take advantage of those opportunities that come up.
We have a lot of financial flexibility within the CapEx program. That's shown by what we've been able to do with the money. Just on a very short time frame, we have those scale that back, move those rigs into the more oily areas of Eagle Ford and in the field. And of course, we have plenty of liquidity and access to market to take advantage of any opportunities that come up.
So that's the end of my comments. I'll open it up to any questions. Anybody? Sure, Paul.
Paul Sankey - Deutsche Bank AG, Research Division
Paul Sankey, Deutsche Bank. [indiscernible]
Kevin G. Fitzgerald
No, that's just the part that I assume will be financed. The dividend that's higher than that would -- the $1.01 a share which works out right now works out to like $220 million or so. What I just did was simplicity in that slide. We just assumed $200 million -- I just reduced working capital for the difference over the $200 million.
Paul Sankey - Deutsche Bank AG, Research Division
Kevin G. Fitzgerald
Now the real part of the cash flow though is the Brent pricing because the differential is blown out so much as in most of our oil, over 80%. And then of course our Sarawak gas is also based -- priced off of Brent. So we were able to realize a lot more over and above what we did last year and even with dropping that production with that kind of increase in price is really we drop that cash flow, which is all priced revenue.
Paul Sankey - Deutsche Bank AG, Research Division
Kevin G. Fitzgerald
No, when we were back down, we were running them basically in parity, maybe a little bit differential, not the kind of differentials we've seen now with $15 and $20 plus.
Paul Sankey - Deutsche Bank AG, Research Division
Kevin G. Fitzgerald
Yes, that may have been a little bit of the increment there, but it wouldn't have been not like the increments you see in here.
Paul Sankey - Deutsche Bank AG, Research Division
Kevin G. Fitzgerald
Yes, I forgot I meant to repeat the question, but Paul was asking about the capital expenditures in those out-years related to the risk exploration. Yes, we have -- as you go through each project, especially in this exploration drilling, they 20% chance of success, 30%, 50%, whatever that is depending on individual projects. So you take the development and your appraisal dollar going forward, and you're going to, say, if it's a 30% project, all those things will be considered 30% of that spent because that's the chance of success. Rather than saying this project is going to be good. It's a 20% project and ends up being good at 50%. So naturally, if all of those are successful, then the overall capital expenditure is going to be a lot higher than that $4 billion because it has got much more development to do because everything else, at that point, is either a risk 20%, 30%, 50% with some amount. Same thing is about in 2014, 2015, the $700 million to $800 million in each one of those years for that risk exploration. So if I drill all dry holes, those numbers would be $700 million to $800 million less than what they show on that slide. What was happening, Paul, in the out years, the capital expenditures, once you get past that occur at one more year, which was way understated because it didn't assume anything was going to happen, because we've been always including capital expenditures for known project. And so it really wasn't giving you a true picture of say the types of revolver and the amount of liquidity you have to have access to going forward. Because then if you made a big discovery, then there'll be nothing in there at all. And so you'd have to -- fortunately, with the way the financial market and with Murphy's balance sheet, we've always been able to react to that. But we're going ahead and change the way we're showing it going forward just to try to make it a little bit more realistic in those out years.
Paul Sankey - Deutsche Bank AG, Research Division
Kevin G. Fitzgerald
Not for the current -- not for 2012 and '13 because those are more known with your rig schedules and what you're going to do. And there's really until you get to the back end of this year, it even occurs to me that while it's currently drilling, it's going to take the better part of the year to get down all the way. And so you're not going to have that much -- there's a little bit in 2013 but not that much because it's going to take that long to get to 2014, 2015 before that really sits in the capital expenditure.
Kevin G. Fitzgerald
No, the dividend gets looked at every quarter. We typically are -- to repeat the question, was asked if the dividend is going to remain stagnant over the next couple of years with the reduction in cash flow, the lack of cash flow versus the negative free cash flow that we'll show in the next couple of years. The dividend gets looked at all the time. Typically, if you go to sort of the every other year type of increase that we've been doing the last couple of years, this would be that year. So I mean it gets considered every quarter. We have the balance sheet, certainly have access to anything, but our debts are so low that to look at increases over the next couple of years, it's not going to hurt us on anything else we want to do. So it's easy to fund it. So I would think we'd just stay along the same path that we've been going.
Kevin G. Fitzgerald
The question was spending for LNG development in those -- and I don't, Tom, do you have that number in there?
Yes, there is some risk in the net [indiscernible], through '14, 15?
Kevin G. Fitzgerald
Do you have the numbers of how much is in there?
We have like $30 million in '13, $100 million in '14, $115 million in '15.
Kevin G. Fitzgerald
So $30 million up to $115 million in 2015. One thing I did mention going through that, none of those risks exploration projects has any production in this time frame. There's no production from any of that because all of production from those projects will go outside of that time frame.
Anybody else? Okay. Thank you. I'll turn it over to Roger.
Roger W. Jenkins
Thank you, Kevin. It's a pleasure to go through our upstream businesses, my fourth year. You'll find the slides as exciting as the previous years. And in a few minutes Sam, of course, will come up and join me to talk about our global exploration portfolio.
Before we get into agenda, I thought to take your time to kind of go back. Since we last met a year ago, a lot of things happened in this business. It's a very fast-moving business. We had a very strong year in reserve placement at Murphy, 220%. It's a record for us. We've been making big strides because of that in our F&D, lowering F&D 28% of 3-year averages over a 5-year basis, and we're getting a better handle on all of our peaking into the 8% range and happy where that's going.
Of course, we're an old company. Murphy Oil Corp., heavily oil weighted in both production and reserves. Our North American onshore business is really doing well. We'll see today in the Eagle Ford a big move in production, a big move on how that operates and is moving smoothly. Sanctioned 6 offshore oil projects this year. And just like the question a few minutes ago, we've derisk a big project for us way down the road, which is Floating LNG in Block H in Malaysia.
We're back to drilling again in exploration. Last year, we had a very limited number of wells and the reason for that is a real shortage of deepwater rigs around the world and a real backlog and a delay in some of those rigs coming our way. Last year at this meeting, we didn't have the Kikeh completion resolved. We thought we knew the solution. It's a gravel path type solution. We now performed a lot of those and we talked about that in detail today.
Big issue for us, a big change from last year that David spoke to earlier is a big pullback in gas. I don't believe it this time a year ago, people anticipated and we had below $2 a gas. I don't think not only Murphy, but a lot of our competitors didn't anticipate that. So a big move, a big pullback in capital, which caused a lot of change in all of our numbers both production, spend, et cetera, primarily in Canada.
Real important point here on production. I am pretty sick and tired of the production variance issue, and we made a pretty big change in it. When we got down into the second bullet about removing our gas, it gave us a chance to really relook at how we're doing our production. So for this year, typically at this time of the year, we have guidance on our earnings call last week when we go through every project. We know a lot about our rig schedule, a lot about where we're headed. We look that in a normal way and ended up with the guidance we have today.
In the outer years, which I think was a lot of our problem when you have a higher number and striving to get to those numbers. So what we did there is we removed the natural gas growth in Canada, big movements in BOE there. I'll go there within a second. And then look back among all of our quarters and all of our years in the last 4 years and decided on risking every barrel in the world, 7% off the top absent of North American dry gas.
That's a huge thing to do. It's something I didn't want to do for a long time, but now we're doing it that way. And it gives us more freeboard, if you will, to have issues happen to us in our business. And today, as I have in the past, I'll talk about the reasons we have this volatility in our forecast and what we're doing to get out of that volatility with the different type of portfolio. So really an improved rigor in how we're forecasting. There's a big delta of the bottom here, if you will, and we'll talk about that as we go forward.
And here's those numbers here, look back from last year. So this year, we know where we are. It's primarily a recalibration of our different projects. When we look at the 200 million number in 2013, 25,000 BOE of that would be just a stoppage of the drilling of the Montney only for the minimum amount. I'll talk about that in a second. And then the rest of it is just recalibration of how projects are going around the world and will include a 7% pullback right off the top of that haircut.
As we move into '14 and '15, we actually have some oil projects in Malaysia that we're not in that have been successfully approved in field development stage and have moved to the left, if you will, and became part of our portfolio. It just so happens that those growth and those oil projects were counterbalanced by recent reductions that I've added across the top. So when you get in '14 and '15, what you have here is really an all about delta of North American natural gas. Huge numbers, 45,000 BOE per year and type of gas production we were assuming just one year ago in our business.
Then we're going to look at our agenda today after we got that behind us because that's what everyone wants to talk about all the time. Our upstream strategy, we're going to speak about that, couple of slides on what exactly we've done with North American gas. I know we're going to have a long review of several of our major oil projects in the world.
Sam will talk about an oil-focused exploration. You'll see the oil thing here quite often today. And then I'm going to talk in detail about our operations, some reserves and oil-weighted reserve base that we have, and then production one more time just so we can hit it again and then I'll have some concluding remarks and also talk about the value of our business as we grow our business altogether.
In strategy in our company, we are a company who want to maintain an oil-weighted base. We want to be an oil corporation. We want to be in the 60s. When we have this meeting every year, I'm always fighting for more time. While my competitors have had 300 or 400 slides in a day like today, I used to have about 60. So all of our competitors are spending a lot of their day telling you how they can become oily, and telling you what they're going to do to get off gas and become oily.
We're already oily. We don't have to have that time. A lot of competitors talk about how they can fund large amounts of CapEx. We don't need to do that. We've already talked about that today. So I don't need a lot of time, so maybe my 60-something slides will be enough.
We're always conducting, building and wanting to be an impactful exploration company, due to not every well being a 300 million or 400 million barrel deal of an impactful program where the accumulation of that program is impactful. Where Murphy really shines is in development timing. We get things online on time, and then we also reduce cycle time. We see this a big competitive advantage.
This investment discipline, when things are rolling and oil prices are high and gas prices are high, it becomes a lot easier. This year, because of the big pullback in gas, we made an immediate cut, which allowed us to in our flexible portfolio got out of the North American gas, reprioritize some of that CapEx into Eagle Ford and other places and we're able to move forward.
Like any company, a rationalizing portfolio, looking at places where it's not a growth for us or not a focus area for us and getting out of those businesses is something that any ongoing concern would do. What we have now as a result, we hope in value, because we're so oil focused and not just the focus on the 300 million. Last year, a lot of our discussion here in this room was about going to 300 million, and we could do that then because the gas price and the gas project we have supported that, but it's no longer the case.
We're building on a very strong foundation in my business. And quite fortunately, we have 9 projects that are ongoing today. They're all, in our company, they're in execution phase. We have a high level of oil and oil index production. You'll see a lot of new slides about oil index. But that would be the SK gas in Malaysia that's priced on a Japanese crude cocktail that has some very high gas price.
So we're really not a major gas player, and over time, that will be even reduced further. Our production growth, no matter how you size it even with the full year last year, you'll see that Murphy either over a 3-year or 5-year basis on CAGR type returns are 10% to 12%. So industry leading production growth back on the roll for this year.
I'm very pleased with how we do our risking of exploration, our portfolio risk resources in our company, 680 million barrels. We're trying to get that to a factor of 2x our proven. You've seen in our business today, we have 534 million barrels of proven. We're trying to get it go and get that to 1 billion. But right now we set at 680 million, and over the next couple of years we'll be touching that portfolio of around 500 million. So a big foundation of wells to drill.
The flexible North American position 450,000 acres we've built here in the United States and Canada. It allows us to move out of things like the big move we had in the Montney, and put that into Eagle Ford into our steel and we're glad to have that flexibility. As Kevin mentioned, we are heavily advantaged by being a Brent company, and our project in Malaysia is Brent with the toughest premium on top of that and a premium on top of that for the quality. So we're very happy with where our oil prices go. And as we get out in time, you will see only 20% dry gas in our business, and again, remaining very oily.
Here again is that same picture from a few minutes ago, the 193 million, the 200 million, the 250 million going to 260 million. Again, it's a picture of the really strong oil-weighted business that Murphy has, 73% oil now, building up to 80%. This again is the oil index Kikeh gas and on top of that, which is not counted in this number, is risk associated gas and rich gas out of Eagle Ford, which has a premium of course in the held price and I'll talk about that in a little bit. What you end up with is about only 11% of our production is dry gas in the outer edge of what we're looking at today, which is 2015.
What we'll have here is a series of slides as our business grows, where it's growing and where we're spending our money. What we have here is a very visible growth. We do had a lot of project. As I mentioned, we have 9 in execution. We sanctioned 6 more just this year, and we're heavily oil indexed. So we see a growth in this period of time across our business and where it is going, with Malaysia still being a big portion of our business, Kikeh less part of Malaysia over that time.
What we're trying to strive to is to deliver a different portfolio of wells or a much higher well count so we can have less volatility and more consistency in our ability to predict production. Most of our growth is in oil. All of our sanctioned projects are doing well. And what you'll see also here is trying to achieve a very consistent level of exploration spend so we can deliver a certain number of wells every year and get ourselves back on to the favorable exploration success story.
Here we're going to look at North America dry gas. It's a very cold day up in Tupper. Unfortunately, it wasn't cold enough in North America in many days, wasn't this cold surely, causing a big pullback in this business.
Tupper is a great project for Murphy on many factors. We're able to do the project on time and deliver all the attributes of the project on time. It has below plan OpEx and DD&A or supply costs. The EUR and the subsurface is where we wanted to be. Big resource base to build on 1 to 3 TCF of gas there. But the problem, as we all know, AECO pricing today below $2. So that's the problem of the day.
So we had to move out of this business for a while. We are curtailing a small amount of production here shown in blue. What you'll see here is to be able to tie this. This is the amount of production we have in the plant. So the 130 million plus to 50 million is 180 million a day of Montney gas that will be in -- buried up in all of these financials.
We can go down to a minimum level of 130 million, 137 million, 123 million. This really gets down to the minimum it takes to run our facilities and our plants, and also we have some space on pipelines that we've committed to years ago. There will be a level of spend because we're drilling. We don't want to lose any of these land. We're hoping for a price signal to kick this back up again. But this is the amount of well drilling here and the amount of flexibility we have. This is coming off probably 40 something wells a year type drilling.
So a big pullback in capital. Almost $1 billion to $1.5 billion of CapEx pulled out of gas compared to a year ago. What we need here, as Dave said, is some $4 to $4.25 AECO to get back in this game with some type of small escalation not really a big forward curve hockey stick there, but we do need that level of work.
So that's the North American gas piece, and now we're going to focus on our ongoing high-value oil projects executing as we move forward all over the world. First, a real green day in Eagle Ford. It wasn't so green there a year ago, so things do change. It's quite green and nice there now. This is in Karnes County, one of our nice places where we drill.
I was at a conference a few weeks ago where one of our competitor's leader is on stage and he said, "This project is so great that I'm just going to move on and not even talk about it." I'm going to go ahead and talk about it. I shouldn't do that, but I'm going to go ahead and waste some time to talk about it.
In North America onshore, this should be all of our onshore business, we are a proven player now. We were an offshore player a few years ago with a little office in Calgary. Now today, we can run 20-something rigs and have done 2. That's a big move for us. We used to have 20-something floating rigs. It's a business of scale. You're going to see production here exceeding 100,000 barrels a day, primarily from the U.S. and Canada. Montney being on top, which is also in Canada of course, a big business. This is becoming half of our production almost in 2015. Big spend, almost the same mirror image of spend for international business.
Seal and Eagle Ford are derisked, good projects for us and good places to invest. One of the key things that's happened in my organization is we reorganized our company to match what we're going to be doing in the splitting of these 2 businesses. Mike McFadyen runs our Calgary Canada office. I put all of the North America land under him. Jim Coleman, very capable like I am, a deepwater person, manages all of our offshore and international business. This allowed us to put a better focus in North America and a better focus on our international. It kind split our company into 2 pieces.
Real advantage that's caused this is to build the moves on Calgary staff easily down to Houston when we saw it back on Montney where we're bringing in the drilling completion and facilities people that we needed and really made a step change in our Eagle Ford business. When you look at the spend and all the capital that Kevin talked about in North America, the big spend there is almost all in Eagle Ford and those are all ongoing projects.
New projects are the examples of EOR type projects up in Seal. Of course, not much exploration in the resource play North American game and some spend on our base. It's primarily spend that we have to pay for our percentage ownership of the same crew.
Looking at the Eagle Ford, a real nice business for us, 130,000 acres of oil land. We have wells, we have facilities, we have rigs. We have 10 rigs today. We said a year ago, we'd have 10. We said a year ago we'd go to 12. We're going to go to 12 in the fourth quarter. Two dedicated frac crews are moving to 3. 42 million barrels, nothing to sneeze at, but a couple of years ago, we had nothing. So you see our 10 rigs across here where they're operating today, and I'll talk about that a little bit more granularity here in a second.
The Eagle Ford Shale is derisked by industry. We wake up one day and there's 250 rigs drilling in Eagle Ford. Some people say even more than that. The production, which I doubt, but everyone guarantees is 800,000. Let's just call it 500,000, and say that's wrong. So this is a dot for every well that's working across the play on various levels of production. And here's our yellow acreage, big patch of acreage here, here, here, here. So heavily derisked around us are successful wells surrounding all of our acreage.
This will be the fourth year in a row I try to show some value in this business. I'm just going to give it one more try. It's a nice business with lots of capital, lot of rigs, lots of focus on Eagle Ford all around Murphy's acreage.
Fivefold increase in production here and here. This represents in blue our go-forward business approaching 50,000 barrels a day in 2015. This will derisk 7% as I talked about in the first part of the presentation. Of course, it's heavily oil. Our guidance now is 15,000 barrels, and I'm going to talk some more about the Eagle Ford and where those barrels are going.
This is Karnes County. This is a place where we have near 14,000 acres. This has been one of our main focus places. This is one of the top acreage positions in Eagle Ford. If you look back a year ago, we have oil EUR of 500 million. What's unique about this is these are 12 rigs. The top 12 wells.
The top row are the same 6 wells from last year. So they continued up for 12 more months that we have in this presentation. We've added some more wells around them. So you can see now we're looking to move our guidance from 500 million to 730 million. But if you look at all the production forecasting we have in this book today and all our financials, we're still using the 500 million. Then another level of hopefully conservatism in our outer year financial and production reporting. But I do believe you can see from the day we have some running room here probably in this portion of the curve in the first few months where there's real high-value, high MTD portion of the curve exists, and we see the same cost as we're going as high as 850 million in this particular set of acreage that we have, a very prolific and one of the top acreage areas in Eagle Ford.
Tilden is an area you see on the inset map here. It's a very, very high growth and important area for us because we have a big acreage footprint there. So it's 69,500 acres. In Karnes, we have 75% working interest. Here, we have near 100%. We have 5 rigs in there today. We're going to drill 80-plus wells in there this year.
So our next big step is this. At this time, the EUR of this is 380 million, not the 500 million that we have in Karnes, but we never had it modeled that way. So we're hopeful that we'll have some better improvement here, and as you can see from the data, unlikely for that EUR to go downwards. So all of the financial and production forecasting would be using a 380 million curve. So a big key marker for us throughout the year is how this EUR curve is developing as we go through the next couple of quarters.
This is something that we've been working on quite a bit. If you circle an area around Karnes and if we look back a few minutes ago, it's heavily, heavily drilled area. A lot of acreage, a lot of our competitors. A lot of our competitors love to talk about a high, high, high rate wells in announcement. I too like high rate wells and how they do production. And my staff has been holding these wells back to almost and 864 choke throughout most of their life. So we have a reduced choke production system.
I was not in favor of this system. I do not like the system. But after a lot of data and looking, we've maintained it because we really see that's where we're having a lot of value. So if you take all the wells in that database and look at how the average production is from the 3-month average, the 6 and then the 12, you'll start to see a lot of loss of value of the reservoir energy, damaging possibly all those well information and that's where we're seeing value by holding back these chokes.
It doesn't give the big Hollywood rate, but it's given us a long period of time. And if you think back a few minutes ago, we had a lot of dots, if you will, flat across early part of our months in our production. So this is something we're doing now all across the Eagle Ford and we think a big plus for us, long haul.
Real, real pleased with what we've been drilling. We finally had a certain mass of drilling there, 10 rigs is going from 0 couple of years ago is no small feat. Really lower the days down 32%. If you look into all the counties, we've set county records in each county where we work and we compared all of our competitors in each one of these analyst presentations in each one of those areas.
We're diverse across the whole play. We typically don't concentrate in just one area. But with that big improvement in frac cost per stage, this adds up almost $1 million a well. So if you're drilling 140 wells a year, it's a serious CapEx.
What we're seeing now, and I think this number will go higher, is with the original 2012 CapEx, we're going to drill 20 more wells this year with the same CapEx. So that again is not in production forecast. I just mentioned that production forecast has been risked. That production forecast doesn't have a higher EUR. That production forecast doesn't have the 20 extra wells. So again, we're trying to build up a conservative foundation in Eagle Ford.
The real savings and the real modeling numbers are down here in the right-hand corner. This is the amount of CapEx that we anticipate saving and how much wells will cost at the end of this business. So this is a huge business, million dollars a year, hundreds of wells a year. So these small improvements are critical and something we really made a step change in Murphy in the last few months.
We're not only in that business. We're in the down spacing as I showed early on. We're great across this entire play. We have acreage in every major part of the oil areas. We have not done a lot of down spacing. We are drilling some down spacing in Karnes. Much of the industry is down spacing around us and they look at our forecast. We do long term assume that Karnes is down space to 80.
We are just looking at down spacing this year in Tilden and Catarina that we've done this year and reported those quarters. That too, again, is not into our long-term forecasting of reserves or total resource here.
Murphy has been a company, we're in the offshore game. We've been a quite innovative company. We've done many projects all over the world where we do many firsts. I think that you'll see as we get up production up to a certain level will be a company that will again be innovative here. We're all working with several frac techniques, most of these primarily after using less water.
Also, for us there's some additional optimization in Packers Plus. It's a common technology used in Canada. That's a trademark system where you pack off the casing and the casing is not cemented. It leads to a lot faster completion work, and we are experimenting in one of those this weekend. We see this to have both upside in cost and in deliverability, and again, it's that issue of bringing technology from Canada into our Texas business quickly.
Zipper frac is an idea where you work on one frac pumping, while adding on the other and doing frac groups, nonstop, 24 hours a day on 2 wells. That will almost cut your time in half and will be a big significant improvement for us as we go forward.
Getting away to oil and gas here, we have gas deals at all of our major fields, most of those are headed eastward toward the eastern type pricing. All of the oil here head south towards corporates or even into the Valero plant here. A lot of oil is struck in the Eagle Ford, oil just for Murphy but for others. We make about 7,000 barrels a day in Karnes as we all pipeline in about 2. We shift all of that in pipelines at the end of the year.
Today, in this whole business, there's about 180,000 barrels a day of pipeline ability. But it's going to 1.3 million barrels a day in the end of '13. So huge amount of infrastructure, many options both trucking, rail and pipeline here. One thing that's important about this project is we do have some Brent influence pricing being near the Gulf Coast. Typically, we're about, as of late, we've been about $8 above WTI.
Before the recent pullback, this is the price for the average month of April. So again, very strong for us. And then the way we do our gas business, is we're selling this gas as a percent of proceeds, delineating gas pipelines that NGLs captured by that company and given back to us in this type of number typically about $3 or more ahead of our gas pricing. So that's how we get our rich gas component across. This will actually grow just for several months, so it was much higher.
Of late, we've been $8 above WTI. Before the recent pullback this is the price for the average month of April, so again very strong for us and then the way we do our gas business, as we're selling this gas, as a of percent of proceeds of gas pipelines that NGL is captured by the company and given back to us and this type of number, typically about $3 or more ahead of gas price. That's how we get our rich gas component across, but this is actually low, this for several months was much higher.
So again in the Eagle Ford, like Dave said, and we're in this game for about $1,800 an acre, we still see deals today of $30,000 an acre. So we're in it for the long-haul and we're in it at a low price, leading for us to have very nice returns. Our EURs are increasing and our main field and for otters, our drilling cost coming down substantially. That'll improve our supply metrics improving our net income. We're drilling the wells, we're supposed to drill, and drilling more actually. I think that there's early days in frac-ing and drilling technology and more to come here. A big resource for us equal to probably larger than the days of our Kikeh net number, and this does not include all the down space -- and the way we do have our down spacing model today is the Karnes area full of 80s. We have the rest of the acreage at 160 and half of it at 80 so like 120 whatever that ratio is.
But we are hearing talk, and a lot of people speaking today of 40s and there's no 40s here, but just going to full down spacing will get us over 400 million barrels of resource. This is no dry gas in this business so it will be all oil and associated gas from that oil.
Moving into Seal, this is the place we've been concentrating in recently with success and we have many pilots and projects going on. We're going to drill 70 wells there this year. We have increased our production and this is on the operated piece, about 8,500, which should make about 10,000 barrels a day in this business. I'll talk about the polymer flood in a minute, we had that project just go a year ago and today very successful Strat program this year, you see red dots of where we drilled, it's nice Strat wells here is its pay, oil quality, viscosity and what type of development you will need to recover it, so you have good view there. We are starting cyclic steam and vertical steam pilots this year. These are done by our competitors nearby and we're moving on into pilot stage and we'll be doing those projects over the next few months.
Last year at this time, we have just started talking about polymer injection in this business, you can see here in May of last year, this is when we had those fires up in Canada and we were just getting the targeted response within this 300 to 400 this is in the spares of wells, the green producers, 4 wells, ended up going over what we originally targeted and today making 500 barrels a day when we used to make 100, 380-barrel type improvement here, so very big move and that's on this particular game and something we will be working to add on to in phases both this year and later on in this year, our second phase. So again a successful project are going forward there in Seal.
This is the same picture from last year, big resource, over 5 million barrels in place. A lot of work here to go on how to get these barrels out of ground. If you compare it back to last year, our year end '11 on primary had a big move in resource there, probably doubling that number, it's between the early stages of polymer we took this number upwards, and the real total change, the way I like to look at this project is the resource here is 365 million barrels, that's another major project. We have to drive our information and our pilots in order to achieving another 400 million-barrel project. A lot of work we need to do on reserves, we only have 20 million-barrel of proved reserves in Seal and we're looking to probably almost triple that this year and a lot of work going forward in Seal about getting a lot of this resource out of ground and there's plenty of it to get out.
This is what Seal looks like in our long-term business. Again, a big oil in place business. We move some capital out of Montney, put primarily into Eagle Ford. We're trying and working a plan to move this to the left, but these risk barrels you would find here would be in the forecast that we had talked about earlier in the meeting. Big resource movement here, an area of de-risk, an area of successful Strat, an area where nearby competitors are drilling, and I think a lot of running room for us to help add reserves in our business.
Southern Alberta is a new play. We started this play about year ago, another play where we're in 150,000-acre type range, there continue to be lease sales here. We're successful in lease sale here in the last couple weeks, low entry cost again we're trying to duplicate another Eagle Ford where we get in at a low price and build ourselves up organically.
If you look back at where we were a year ago we had some wells that were not very good, mix results down in this portion of our land. There's an abnormal pressure trends in -- somewhere in this area, now we moved in that area. But we didn't see a competitor with some very nice wells here in the Lower Banff and I'll have a geologic Start and talk about that in a second.
So I think this play is in very early days on where to drill and what's going on in the play. This year, we need to concentrate on lowering our cost, we're trying to do Eagle Ford- type slick water fracs here, which we think are successful. We've got to get this technology working better and more cost efficiently in Southern Alberta. This is a geologic section of where we're playing that game. Your Lower Banff reservoir here, your Upper Exshaw and Lower Exshaw look alike of the Bakken. The Bakken has a carrying bed here, a dolomite carrying bed, we thought at that time we would mimic that play and drill in that area, a lot of other competitors too.
On this particular well here in Kainai, we originally drilled out, but we drill down to the Three Forks and during a well test, we found oil production from the Three Forks zone so then we went down to this area of 1521 and drilled a typical horizontal gains, frac-ed it with an Eagle Ford type slick water frac and had a very nice IP of 350 barrels a day. That well -- almost 5 months. Still falling the day. The well is impeded by wax that's forming in the tubing, we'll have to work on how to get rid of that and I'll talk about that more in a minute.
So a nice successful well here and we're flowing back the well here, it flowed about 200 barrels yesterday still with a lot of water making 120 barrels this morning, still with 75% water so the pressure in the oil coming out of that well appears to be almost better than the other well, but this is early days.
You got to remember, when we go into Eagle Ford there's 20 or 30 wells like this, so we're talking now a very few, but so far very happy with the well results we're seeing in this Kainai reservation.
This is kind of a clear look-alike coming down from the Lower Banff into Lower Exshaw and into the upper Three Forks you can see the dark rich organic nature of this upper Three Forks where we're placing these wells and those fracs are probably going up into this upper and middle Exshaw and that's where the oil is flowing from.
Very high quality oil, 42 degree, we have wax that's forming into formation in the tubing but it's not really quality issue. I think the search is still on for the perfect zone here, and I believe we have running room and upside ahead it could be multiple zones in the play. We got to get longer laterals, lower cost, the real price for us even on conservative spacing of 160. That these type of well levels of production and recovery, but still leave a nice rate of return project at 130 million barrels of oil, and I believe this resource could possibly double. If you like the Eagle Ford you ought to like Southern Alberta. So here's the well in Tilden County, many wells like this by Murphy and our competitors and in the middle will be the Kainai well and you can see where well drops and builds back up, drops and builds back up, that's where we treat the well for wax and every time we treat the well it gets better and better, so the other day the well flowed almost 550. And today, the wells flowed for 350 for several days. So we think that we can be onto something here in Southern Alberta.
And then Catarina is a very endemic county where there's much industry work and much known information, so we're kind of riding in between these 2 areas of Eagle Ford that are quite drilled out, so happy with how that's going.
Kind of mixed results in this place and other acreage position we have Muskwa, this would be a Duvernay type formation, again trying to get in at 150,000 160,000 acres at low entry cost. We did so, tested a well there at a pretty low IP and now the well's on pump and evaluating. So then again a year ago in Southern Alberta we drilled 3 or 4 wells where we were unhappy. So again here, we're we need to drill, what pressure regime do we need to be in, where will be the gas oil ratio to deliver our level of production. We do know there are some successful production here. The difference in Canada as opposed to Texas, everyone in Texas abide about everything they do and Canadians tend to keep things tighter and some of some of these wells are not all public records. So it's a little known about a lot of what's going on around us, but a lot of competitor activity, a lot of leasing activity here still and we're early days in this play.
So now we can move into our other part of our business, which is our international and offshore business primarily an offshore business is the Kikeh FPSO. It's my 10th year working on that project. It's been the best 20 years of my life working on. Here we go. Here again, you'll see a big spend similar to the other $1.7 billion a year average, so we're spending about the same between our onshore and offshore business.
Malaysia continues to be a big part of this spend. Malaysia is a very attractive place for us to invest, because of the big infrastructure there in both shallow water and deepwater. There are cost incentives and tax incentives for new shallow water development there and we have lots of platforms, pipelines, FPSOs in that region. We're back to work in the Gulf, 2 projects to talk about today, I'm excited about that and I'm real happy with where we're going with Malaysia, floating LNG, I think floating LNG will be the new technology in Southeast Asia in a few years, and we're very fortunate to work with one of the leaders in LNG value train of the world, which is Petronas and a nice project there.
Looking at the numbers, you could see again a growing production level, slightly more than onshore business, but a big factor, heavily heavily oil indexed here because we have oil and we have the SK gas that's tied to oil. The new projects in this business are all of the new projects in Malaysia that are coming on, I'll be updating those in a minute.
Big exploration spend nationally, internationally because this will have our Gulf of Mexico spending in as well and we are spending money at Kikeh to do new wells and repair wells in that piece of business and I'll talk about that of course here in a few minutes.
Kikeh, a world-class project, we've made a lot of the money there, NOC Petronas also has done well. 140 million barrels, the next 200 something million barrels will be more difficult, but the first 140 million were not so difficult.
We have one issue there we've had that issue now for a little over a year, is it when water is produced -- it's a waterflood project and when planned water comes into the wellbore, sands and fine materials flow into the tubing, that becomes too difficult to handle at the surface safely and we have to either curtail production or shut in wells.
When I stood here a year ago, it's a major problem for us. We thought that the way to resolve the problem was some form of gravel pack. We've now conducted 8 of those, it's been very successful. So from that issue, we're holding back the Sand/Fines. Save it to yourself, if you ask me a question of how many of those wells produce water, 3 of 8 of those wells produce water until recently 3 of 7, we just turned on a new well and we do not have any of the Sand/Fines production.
So that's been a big move for us from a macro level about the total recovery of where we are on both water cuts and where we think the wells are going to go. We have 2 types of reservoirs, we have some deeper reservoirs, that do make some small amount of sand in a normal and the operation, but the shallower reservoirs will make up 60% of production is primarily when this problem has occurred.
We have all types of well types, we have the old tank controlled -- NOC-tank controlled wells, we have 2 wells closed in at present. We have 4 old sand completions today, they are producing about 17,000 barrels a day. Those will be worked over. We do not turn off a nicely producing well to work on, on occasion, these wells have to be curtailed and it it becomes into the rig schedule to repair, which will then becomes difficult sometimes on production estimation and I'll talk more about that in a minute.
We do have -- so primarily equal to all the others is our new completions, so as we build more and more we replace all these wells with successful gravel pack type completions. Kikeh is a very, very robust model and we have state of the art reservoir modeling. We have a big team working on this. When we say well penetrations, it will be up to year end we have about 85 today. When we talk about penetration, go back to the original discovery well, which is in '02, all of the delineation wells, all the sidetracks, all the water injection wells that makes for a very robust, very well drilled out so we've got wells in every sector of this thing. This model millions of sales and layers this model impact of Heineken Peters 14 hours to come out with a result, it's the norm of the reservoir model.
The thing to know about working in Malaysia is Petronas has a very, very stringent -- when you spend their money in a cost recovery PSE, they're very worried about it, so they have super major ability in reviewing your work, your field development plan work, your rig completion work. So this has gone through incredible review about both our partner, which is Petronas Carigali and Petronas. And we have a big team here. 13 people very experienced. This is the asset price at present. Eagle Ford a little overtake it, but today a lot of work and a lot of experience about how much oil we have in the game, how much oil is ultimately going to be recovered it's a matter now of handling the sand/fines issue and hopefully getting all the barrels out of the ground at a certain amount of time that is what the game going to be here going forward. And like Dave said earlier, it's still a big part of our business. It seems to be the focus of a lot of people in our business, but in '15, it will represent 17% of our production.
Here is a picture of what's happened in Kikeh. We were up in the 80s. We started having this problem so red diamonds are wells that are closed in, wells that we have to shut in for the sands/fine problem pretty low a year ago. We have the result have to do it, started gravel packing wells here coming out of the hole, reaching up close to the 80 in January of this year maintaining this level of production -- but also a $1 -- 25% to 27% decline as we're adding the wells, as we have problems with wells, rolling along here pretty good shut in 2 wells suddenly in March, lose about 12,000 barrels a day and here we go. So bring a new well on this week, back up almost 70 again, new wells come onto the year, up and down this thing and right on with this project.
We're all successful in this. The real issues for us are improving, keep in mind that many years of this expandable screen technology, being one of the top innovative users of that technology. Project industry cheapest project ever F&D of this size. So now we're back doing gravel packs, it's much more complicated with fluids, the type of sand that we're using, the carrying fluid to carry that sand so the big learning curve not only for us, but for our service companies to get this back rolling again and we'll get that going and get the wells going better.
As you see really what the issue is over this -- all the angst in this last quarter, is we've taken too long to add another well, cause we've had some problems with the well. So that's really what it boils down to at Kikeh, and we have the total resource there as we always have, and truth is, this year, it's something mechanical that we'll ultimately get around because the overall reservoir model is very secure.
These projects in SK oil are not notional, they are sanction projects. They are a source of major growth for us like any typical shelf type offshore project. They do come off a big decline, but it's big adds in production for us, these are net barrels starting in 13 there's 5 of them shown here in this sheet, these are sanction box, and a few minutes ago I' talked about the rigor of Petronas where they have the incredible rigor of field to obtain approval in shallow water just because it's not Kikeh, they treat every project the same.
So the 5-gate, 5-step gatekeeping process that will allow any super majors actually modeled after super majors so all these projects have a feel about the plans, ongoing approve some surface to get these projects to sanction, not only for Murphy, but also for Petronas, so we're constructing, drilling, welding and doing feed on all these projects. So this is also set up in a way, the way our PSE works when we discovered these resources, we had a certain amount of time to progress them and to flow it all and we're honoring this schedule put out to us by Petronas. So these schedules are very real. We're utilizing infrastructure in place there and something we've rolled with a good well. Now when I go out in a few minutes I'll talk about SK Gas and it has the same sort of feature.
Gulf of Mexico, I'm from Louisiana, I'm proud to be from there and, I want to see the Gulf back again and the Gulf is going to come back. We're one of the few people out there to get permits and drill today and I think it's going to take some time, but at least some certainty about coming back in that business.
Dalmatian is a nice project that we discovered, 2 wells, 1 primarily gas, 1 oil. Nice resource for us, a very economic resource for as we tie them back and that's the beauty of the Gulf as we make some more discoveries, you can tie them back to other parties and make a good bit of a return there.
We have a nice project here in Dalmatian. We own 100% of this project today. DSTD is approved, that's acronym to deal with the BOEM, another acronym on gaining approval. The big boys here was the state of Florida had to make an approval of this project, which they just done so 2 weeks ago becoming the first to approve with project subsidy up a persisted of date of approval long time. So this part just rolling forward, we'll be sanctioned this year and first oil in 2015. This brings us to another point, it's not only about added this risk factor, taken this project have 1-year for any type of uncertainty about schedule and again another area of conservatism and trying to have a long range production profile that we can build our confidence in.
Medusa. Medusa is a long-term moneymaking project for Murphy, one of the highest margin businesses that we have probably a supply cost and a gain of less than $10, a very profitable project. It's produced above expectation. Six of the original 8 wells are still producing since 2003 in this project. Because of that and we started studying the nearby game plan years ago is to sidetrack some of these wells into some other resource. But now that the wells are asking so long we are going to need to put in a subsea project so we're going to drill 3 subsea wells here, nice project 16 million to 27 million barrels of course very robust economics because we're tying back very short distance to our platform that we're offering.
Here again in this project, also pushed back 1-year for another added conservatism in our production. Hope you're starting to see that theme today, it's about the 20th time I mentioned it. We also have and are working to get, we're working to get today a long-term deepwater rig to conduct these projects and are at the table with a major contractor for a 3-year Deepwater drillship for business in the Gulf to do these previous projects I talked about plus to get back well in exploration in that business. And Sam will talk about some Gulf of Mexico prospects here in a little while.
Let's talk about some oil index gas. This is primarily always will be in Malaysia. I think ultimately it will come to other places and Australia and Indonesia. SK gas is a very profitable business for Murphy. You can see it makes 250 million a day, we like to make 260 at a sanction for 250, you see the pullbacks on occasion they have a red telephone in our office there and when it rings Petronas shuts the plant.
Now I can talk to people here about how many times I need to anticipate that, but it's not easy. But it's becoming steady, we're getting used to it, they're getting used to us being there and this has been a growing process. Long time production here, out to 2023. We hope to get this number to be higher because we're making some facility upgrades in which we'll have some more compression ability. These are not notional. These projects, some of which all re-sanctioned section by Murphy, Murphy and Petronas in Phase II and all of these projects if you look at the color code have been fully delineated so in order to play at this game, the wells had to be delineated on a certain level of resource proved by third-party and in order for us to be at the game with Petronas at this table so this again is a source of production growth and production maintenance a long period of flat nice high income high-value production in Malaysia.
Another project, I'm very pleased about is Block H. Block H is a place we've been very successful drilling exploration well. We just drilled 2 successful wells this year, Sam is going to talk about that in a few minutes. We see this gross resource the 2 TCF range. We'll have a series of subsea wells flowing back to floating LNG, a boat that will be owned by Petronas, some of that CapEx or rate you mentioned earlier, some of the feed and some of the expense that will be put in forward in this project until it sanctioned it will be in that risk spend, if you will, we feel we've discovered about TCF of 910 BCF here, some of this gas, over 1/3 of it or 2/3 of it is already been third-party certified. We are at the table with Petronas to get an MOU to work within this year, they are about to award feed if you followed publicly, Petronas is building 2 of these vessels, one of which their own property will go first. We will be the second.
We hope to sanction this project next year. We are uncertain of the first gas, it will be '16 and '17, but it wouldn't in the '15 production numbers that you have in your book today. So long term project, there is no way I'll be alive in 2040, I'll be dead until the Kikeh probably, but you guys can dig this up and it will be a project like -- so we have 2, 20-something year plus 150 million a day net to Murphy projects that will go for a long time on the same gas price in Malaysia.
Exploration. Now, Sam is going to come up and take over and talk about some of our exploration business, and I will come back in a few minutes.
Thank you, Roger and good afternoon, everybody. Exploration for Murphy. Over the long-term has most definitely been a vehicle of value creation. This plot I'm showing here is put together by Wood McKinsey, from the period of 2001 to 2010 we rank in the top quartile for companies creating value or value creation for dollar invested.
Over the shorter-term, over the last 3 years, we have drilled 9 discoveries in our well count, drilling that for 39% success rate, which matches up pretty well against most of our competition, I believe. And in our appraisal drilling or delineation drilling most of which has been in Malaysia. We have an 81% success rate so again, very solid.
And that delineation wells have created 4 projects which have sanctioned, those that Roger just mentioned there with significant reserve adds for us. I just want to go through a little bit of history here and this plot here shows you the exploration drilling that Murphy had over the last 12 years and the drilling we're anticipating doing over the next 2 years.
Overall, we have a success rate of around about 1 in 3 for our exploration drilling, which again I think we're quite comfortable with and is quite similar to many other companies. Obviously we're all very much aware of 2011, the lack of success there, but as Roger and Dave mentioned earlier on part of the reason for that is just simply not drilling enough wells, not adding statistics work for us.
The other thing was, some of the wells we drilled there we're at high risk well and we do put a lot of emphasis on risking our portfolio and anticipating what kind of things we're going to find. So going forward, we have spent a lot of time reevaluating our expiration portfolio building up a stronger, deeper portfolio to ensure that what we predict is really going to happen and I'm very pleased obviously with the results in early part of 2012 with 3 discoveries already. In the purple and magenta colors on the right-hand side of graph there, you see that we're hoping to drill at least 10 wells this year, hopefully as many 15 and a similar number in 2013.
So big ramp-up in our exploration drilling and some solid prospects to come. Our exploration portfolio is very global. It's technically grounded, but also commercially grounded and value driven. Of the up to 30 wells we're looking to drill in the next 2012 and '13, very much consistent with our overall mantra -- we are going for oil wells, LNG scale gas and we choose our exploration areas based upon not only solid understanding of geology. But also to leverage our operational expertise we are well renowned in our Deepwater exploration development skill sets and as Roger mentioned, we are addressing our knowledge and experience in FLNG and we saw that to be very important in the Asia Pacific realm, as well as the some of the larger resource prospects, we're also trying balance out our portfolio with some smaller prospects, which have some much lower risk. And so there's balance in the portfolio, which we're constantly seeking to strive to.
The numbers down the bottom of this slide, we spent a lot of time going through the details of these, and we're confident that over the next 2 years, the wells we're drilling will be touching up to 5 billion barrels of oil equivalent gross. We're testing that amount.
And then on risk net basis, we're looking to access up to 500 million barrels of oil equivalent. There's quite a lot more in our portfolio, Roger mentioned the 680 million barrels, actually I think our current portfolio is probably close to 1 billion of barrels risk net, but it's quite a lot of numbers of which haven't yet been included in the 680 million that he mentioned.
So when are we going to drill these wells? This plot shows you 2012 and '13, these are the spud dates or our estimated spud dates. The rig market is quite tight globally, so we have a number of rig contracts in place and most of the stars with the right-hand side and we have contracts lined up for rigs in Malaysia, Iraq, Cameroon, Congo, Australia and the Gulf of Mexico. We're looking to turn up other rigs elsewhere. So what I'm going to do know is take you through each of these different countries and try and give you a little bit of a flavor as to what kind of prospects we're looking at drilling and what size it maybe. Started off this year very well cost in Malaysia, went back to block H, and right now we have now drilled 4 wells in the vicinity of Rotan where 4 have been discovered. The Buluh and Bunga Lili wells came in very close to our previous prediction, and that gives me a lot of confidence that the low risk prospects marked in the orange there are going to be coming in very similar to our pre-drilled predictions for them, and so that is how we can say that we are very comfortable that we've certainly got at least the TCF now and we are very comfortable we are going to get 1.5 and 2 TCF in this realm. All of these prospects are very similar to those 4 we have already drilled. In Brunei we've made our first discovery. I am pleased to say in block CA-1 with the Julong East well. We are in discussions with the operator and the partners to talk about the next step with that well and that discovery and certainly 2013 appraisal is one of the things we are considering. We're currently drilling the Jagus East well and hope to be able to give you some results on that within the coming months. So the dry wells in Brunei, the big issue there is not the lack of hydrocarbons, it's been the lack of sand, lack of reservoir. So we have been doubling down our efforts in interpretation of the seismic data, reprocessing the seismic, integrating it with our well data and I am pleased to say that in CA-2 where we have 30% equity we're getting a lot of more comfortable we're going to see some sands there in the 3 prospects outlined there, the Jagus -- so East Jagus and Semerak and we are in discussions with the partnership from potentially drilling well on one of those prospects later this year or sometime next year.
In Iraq, some great hopes here obviously. Currently drilling our first well in Linnava, we're down at about 900 meters now, I believe, and drilling is going very well, no issues there at all. In the -- Linnava is in the Central Dohuk where we have 50% equity on the operator. As you can see in the map there in the left-hand side, we are surrounded by oil discoveries and these aren't just small oil discoveries these are significant ones, 1.5 billion barrels in the form of Shaikan, Tawke is close to 900 million barrels recoverable, and in the 2 black circles there with a white outlines, those we believe are discoveries, which are currently being tested. So we're certainly in the right neighborhood and we're very excited about this. Hope to be able to give you some results on that in the next 2 to 3 months.
In Congo, we're shifting our emphasis in Congo. As you know before we were exploring in the tertiary channel, very prolific environment certainly down in Angola and what we're shifting to is the Cretaceous Carbonates, the map on the left-hand side shows you a number of green blobs there, those green blobs are field in the Cretaceous carbonates, same Cretaceous carbonate we're looking to explore in the Deepwater of Congo. And the lines that's next to Each of those green blobs represents the recoverable volumes for each of those fields, so I think the proven play, which were are going to be exploring and we shot 3D as you recall in 2010 and processes it very carefully last year, and now I have some very good images of these structures, so we have multiple structures most of them 4-way closures so reducing the risk 4-way closures in the Cretaceous carbonates and the size of these prospects is pretty large between 100 million and 350 million barrels for each of them and has about -- between 4 and 6 in NPN and a similar number in NPS.
And the schematic down the bottom right-hand side there shows you the kind of feature we're seeing and the orange lines, that's the 4-way closure in the in the Cretaceous. Our seismic also image the pre-salt and we do have some pre-salt structures underneath, some of these Cretaceous features and so it maybe possible to drill well, which actually intersect both objectives and test them with a single well. The ocean content will be coming back to us in quarter 3 hopefully in July, so we'll be drilling this well this year, the first well and then hopefully bringing the rig back next year for further exploration and hopefully appraisal.
Last year in this meeting, we discussed another position we are going to leaving into with Africa, and it turns out I can tell you today that it's Cameroon. Very pleased to have found into the Ntem block where we have 50% working interest and operatorship. This block already has 3D seismic over it and we feel very excited about. The kind features we're seeing here are very, very similar to features, which are billion mile fields in Ghana these are stratigraphic plays in the Cretaceous sands really clearly imaged on the seismic, rather adjacent to the quotation source rocks.
Cameroon is an area that's relatively underexplored and so we feel we are going to get a real first test of this and hopefully got to drill well in Cameroon in 2012 and certainly 2013. There is quite a lot of interest in this area. We bid out about 4 other companies to get this acreage. We certainly feel it has a lot of potential and we're continuing to look at expanding our position within this area.
In addition to the Cretaceous sands, we also have some tertiary sands in the same block which are very similar to the complex which is being proven as you can see on the map up there.
Gulf of Mexico, back to action. Finally we're getting back to drilling. In July of this year we should be drilling our Dalmatian South prospect. This is very similar to the Dalmatian North oil discovery we made back in 2010. Amplitude driven Miocene play and that's one of the plays where we're focused on. Focused on 3 plays in the central and eastern Gulf as well as the Miocene Amplitudes, we're also going after the Norphlet where we have a pretty solid position there with Hornet and Titanium prospects being 2 of the key elements of that.
And then also the subsalt structures and I'll show you some images of that in a second. As Roger mentioned, we are in the process of securing a long-term rig contract, so that we cannot only explore here, but also follow-up with a development in a timely fashion. And we're aiming to drill on average, 2 wells, 2 exploration wells every year going forward, so that we have a material business in the Gulf of Mexico.
Just a few of our prospects here in fact, on the left-hand side is an existing discovery, the Samurai discovery made in 2009, I believe. It's an oil discovery with 4-way closure and we're looking to come back and appraise that and sum the resources more clearly. In addition, we have shown you here a couple of field prospects we have. These are subsalt prospects, both have been in derisked by nearby discoveries significant 300 million-barrel scale discoveries. And also we've been spending a lot of time in processing the seismic and the clarity of that certainly has also de-risk this prospect considerably. The other thing to note on these prospects obviously we're hoping to be coming in at a higher end of the volume range, but even if they come in lower end of the volume range, they're quite close to our existing facilities, so we can tie them in, that makes cost-effective development often.
Moving around the other side of the world to Australia. We're actually in a very solid position in Australia. Just this last week we picked up our fourth license in Australia in the Canarvan basin, but I'm just showing you a couple of features here, we actually have 2 of the largest undrilled structures in the North West shelf.
First one is the Bonaparte Basin in the NTP/80, that's a 4-way closure and anticlinal trap in Permian reservoirs, which is exactly the same, looks exactly the same as the trail and turn, which are currently undergoing FLNG development as part of Bonaparte FLNG.
So relatively low-risk feature there of significant scale and we hope to drill that well in 2013. And in the Browse Basin, the Browse Basin, there's about 40 TCF that's been discovered there. Most of it in the Jurassic, most of it in the Plover reservoir and tilted fault blocks and that's exactly the feature we have in the 80 feet 36 basket deep prospect multi TCF prospect. And again we are hoping to drill that in this year or spud the well later this year or in 2013, early 2013.
So summing up, I think we have a lot of strength to our portfolio. All those exciting wells coming up, some of them we're drilling now some we'll be spudding later in the year. And we want to be maintaining a solid 10 to 15 well drilling program over the coming years accessing a larger volumes of oil or oil equivalent.
We have a number of impactful prospects -- individual prospects, which really could make some very significant difference to us, obviously Iraq, Congo, Cameroon and Australia so a lot of different alternatives. But also we've are balancing this out with smaller prospects in Malaysia and particular and the Gulf the higher end of the course could be in the impactful prospects the lower end will be on the smaller ones. At the same time we also drilling these prospects and building up our understanding of those we're also building our portfolio trying to build a better portfolio that's got greater depth, greater securities so that we really can continue to drill out 10 to 15 wells in the years to come. So thank you very much. Roger?
Get back on here and try to get finished up. A little briefing on operations and some resources and then our conclusions. There's no question Murphy is a proven operator you can't go into a discussion like that without HSE component, I think it's no small just luck that we're the first ever flowing capture permit ever given in the Gulf of Mexico, and that's out of Thunder Hawk, were if you would have some type of blowout incident, you would close your production to a nearby manifolded and into your equipment, which is the first ever type permit given by the Gulf.
We've actually had 2 firsts given to Murphy by BOEM, very strong safety performance in Congo and and this year Malaysia is just industry leading safety performance where we have a huge exposure there of all types of personnel and equipment. We have always been the leader in uptime in our facilities, both the Gulf of Mexico, we're running 99% uptime in our Canada projects such are very critical when you're under these type of price pressure and in a benchmarking studyin the world, the Kikeh FPSO is the #1 uptime FPSO in the world. It just raising how production upset last, the week first time since June of last year. So this is one of the top performing facilities.
We pride ourselves with cycle time in project development being on time and another example of that is going into Iraq in 18 months after signature we're drilling the fastest ever company to sign and drill in Iraq so when there's rigs and there's ability and there's plays to go, we can go there and deliver work very efficiently and very quickly. This is something I've tried to explain in the past. This is a picture of why our production forecasts, our production guidance is a problem for Murphy and what we're trying to do to change it.
If you look at the well count we had in our company delivering with severe production growth only 200 something wells you can see almost of our production is coming from offshore, which is in orange. So we are doubling that amount of well and into '12, we're going to post 700 wells, what you know is that the offshore well count stays the same.
Down here in the bottom right, you see the -- just continually the worry of Kikeh wells and how the Kikeh per well production is a key issue for us. Eagle Ford shale, not so much, but we're drilling hundreds and hundred on these onshore wells in an effort to balance out like a lot of our competitors who may have 4,000 wells in the Permian.
So -- and then over in the left-hand corner is the amount of production running through this Kikeh FPSO. We're quite fortunate it has very high uptime. But then we're flowing LNG and gas into methanol and the magenta and the brown, they're totally out of our control, so a lot a lot of high BOE per day flowing into the facilities that we do not operate. What we're trying to do is grow the gray which is the amount of facilities in operations that we are in control of and get more and more production, more and more wells, less reliant on one singular asset in order to make our production streamlined and more predictable. I believe this is the uniqueness of Murphy here, and is something that all these wells that we're drilling and turning ourselves into more of a North American player will help turn that around.
This is our guidance, we've talked a lot about it, this is the 193, these type of numbers -- we have always in the summer turnaround, have a big turnaround season in Syncrude. Syncrude while something we don't talk about is a project that when it's rolling we make about 15,000 barrels net.
Medusa is going to have over a month of shut in for pipeline work downstream with Murphy so as front runner and Terra Nova has been pushing off a long-term project to take the facility off-line and put it back on. Then in the fall, we have a buildup production there. What's different this year is today we have a rig that's drilling successful wells at Kikeh that are subsea. Those wells have pay and are being completed on time and we just have to make the subsea connection of all those wells and big increase in production in the fourth quarter, a build in Kikeh production from those wells and also hundreds of wells in Eagle Ford where today we have probably 30 wells that need to be fraced there and drilling 140 something wells in the Eagle Ford and also in Seal and in Terra Nova will come back as we've turned around, that's the uplift in the last part of the year.
In our resources we continue to grow our proved, our proved now is up to 534, very oily becoming more North American-based. I think if you look at us compared to other folks, you'll find a high percentage of our reserves are developed, big replacement number for us and a nice spread in 1 of these are located from risking we know that there's a big move towards reserve booking in Eagle Ford so the resource play type numbers and of course Syncrude is pretty solid reserve number there as well. Something I think is very important and very unique about Murphy is our non-proved. Our non-proved is a big number, 2.9 billion heavily oil weighted. If you look at the where we're drilling and where were spending all of our money, it's in these plays Eagle Ford, Seal, Malaysia, Cerelac, SK Gas and we're not of course spending in Syncrude, but not working. So enormous amount of all the capital and all the projects that here today are in the areas to migrate and move this non-proved into proved in some very secure nice -- these are not notional, wild T-3 type numbers, these are things that we have in our site that we have been working on today.
This again to recap this production again, the gray numbers, the guidance, all the numbers that tie up the 200, 250, 260, how we are looking at it before, the capacity with downtime and if we were to execute, it would be the black line. So the cause of this reliance on the senior wells, our senior facility and how we performed in the past we've taken this factor across, move some projects to the right, not including the EUR advancements in Eagle Ford, not including the advancements in drilling and we get to this type of delta performance here. I can promise you that my folks are going to be trying to get to the black line that I can tell us nothing going on. I want to try to make the black line. So that is what we will be working to do.
The close of this year talks a lot about of all the spend, we talked about where we're spending and will end up a little bit on the value of Murphy, quite a valuable company of course and Malaysia Oil is not just Kikeh, Malaysia Oil is West Patricia Oil which is one of our top long-term running projects, all the SK oil, the Kikeh oil, the Kakap oil, the Siakap North Oil, all in development, Malaysia Gas very valuable for Murphy. Syncrude a big solid piece that's quite knowing the value of outside. East Coast of Canada still a nice project for us with high rates of return and our onshore Seal business, and some without very little Southern Alberta here in this number and we have a Gulf business and rolling for a long time, of course the Eagle Ford and the upside in Eagle Ford would be on top of all these down spacing in the EU or help there.
Of course Sam's portfolio is worth money we spend a lot of money on seismic wells and information and prospects around the world and this will be the risked portion of those or in tying back to the risk capital that Kevin talked about earlier and that kind of gives a spread of how Murphy is valuing ourselves on a 2P basis. Now if we get into 3P, we would see this number go up in multitudes there and then the pricing will be the same price deck that Kevin had converging on a Brent price of 95 in the outer years and then escalating. It has a 10% discount factor.
Concluding the day of course we're a strong oil weighted company, we said this repeatedly today. A lot of growth ahead, not just in Eagle Ford in Kikeh but in Siakap Kakap, SK Oil and et cetera there down the road. North America gas on hold any type of title we can get that back on very quickly. All with flexibility there, we talked with links about how to change how we're doing production forecasting, North America onshore oil is a real source of growth for Murphy 12 rigs in the play it into the third quarter, so we continue to see this almost impossible not to grow production. That are growing again in exploration we need to get back to drilling revenue of 15 wells a year, we're trying to do that, we are. I believe that the highest level that Kikeh issues behind us a year ago was not, it is today, that's a matter of execution in getting the barrels that we've fully have organized out off the ground. A lot of value for index gas for us, SK gas in this blockage, long-term valuable solid production curves without a lot of decline there. In our resource game I am very proud of this non-proved, because we're working in those non-prove areas and I think the source of a lot of value for Murphy. So that's all I have today.
Sure we can take questions.
I have a couple of points about the [indiscernible]
What are you going to ask me about again?
We never take a big hunk factor off of all our production, no. We were looking at individual fields all the downtime, all the norm things and we kept having a fire in Canada or a pipeline go off, hydrate form and those issues continue to hamper, because of the uniqueness of our portfolio that I've talked about here a few minutes ago. I believe a lot of barrels are going to places that were not in total control of.
In terms of the Eagle Ford area, you summarized [indiscernible], will essentially give you upside?
We have down spacing, but that's more in the outer years, the down spacing to an 80-acre would probably not occur in this time period, because it takes a long time to drill the thousands of locations we have at 160. The real issue for us is to experiment to 80, tie that technology to our competitors of doing nearby at the 80, and use that to book the reserves to improve our metrics there.
[indiscernible] Is there anything else that you would like to add on the wells?
No I don't think so. I think the additional wells -- I'm sorry, I can't remember that question, the question is about the Eagle Ford and the upside is in the Eagle Ford for that would be in the faster drilling, different EUR going forward and down space.
Question is about current stand -- our ability to commercially turn that over later. We have a PSE there of course. It is a government take that will be similar to those type arrangements throughout the Middle East, and it's very favorable economically to us even though the government take is quite large, because the fields are quite large. What makes the government take different in that is that it's CapEx much lower than we used to in the deepwater where the amount of cost barrels is different because the amount of money you spend to get those barrels out is less. What we see there is a long-term situation. We know that they're are building a major pipeline across Iraq and northern Iraq, Kurdistan going into Turkey. We deal with the oil ministry there, we feel that one day they will develop that. So it's a matter of having a discovery drilling another block, another amplitude or another structure that we have, and not over delineating or over developing an area without the terms to flood oil, so I think the issue will be there long-term.
It's my understanding that currently operators there can almost build and get cost recovery, so if you make recovery, [indiscernible].
I would say if you describe near-term over 2 or 3 years, yes. But over time if they continue to build the infrastructure to take their own oil out of that environment then that will be easier for us to go. I think we're almost, by the time we have a well here, delineate limited amount there, look at what is going on around. The pipeline should be built near us, so we're in a different timeframe than some of the other folks we are well on production sooner than the ability for that country to handle their own export production is the way I see it.
What happens in Kikeh with the 4 wells that are produced there using the same screen technology?
What we typically have in Kikeh is a progression of the well -- sorry repeat the question. The question is around the 4 wells that produce at Kikeh with old same screen technology. What happens typically in Kikeh is that the wells go to some well of water and when the water hits, they have this amount of sand that we handle with physical mechanical desanding machines and they progress over a long period of time. It's quite rare for the well suddenly go off production as we had the one in March. So throughout this year, of those wells only 2 of them are making any type of sand today and they're very small so some of them are not going to water and the water predictionability is kind of where the sand began so we have that all into our model.
Sure. The question was, why do not talk about Surinam. And then on the pre-salts Congo with data seismic so on Surinam, that wasn't included simply because we were only talking about which wells we're going to drill in 2012 and '13. The drill timing for Surinam would be 2014, the earliest, and so we're intending to shoot some 2D seismic in that area this year, and then we'll report back our valuation at that point. I would say that we had a lot of interest from super majors and a lot of other companies about coming into the block, but we got to have -- stay at where we are at the moment with 100%. And the question regards the NPN pre-salt, those structures there they're much more difficult to image precisely and there's much greater uncertainty as we go out and deep water it to exactly what the -- are going to be when there's going to be a carbonate buildup like we've seen in so successful in Angola to the south whether it's going to be sands as is more prevalent onshore. So the current numbers we're looking at is potentially in the 100 millions of barrels. But we're not really trying to tie it all down too certainly on that. Particularly if we already have a well in the carbonates above it. I would say about 100 million barrels is a reasonable number. Keilin could be a lot higher than.
My understanding is still in very early days but can you quantify [indiscernible] Southern Alberta [indiscernible]
Roger W. Jenkins
Okay. The question is around Southern Alberta resource in Ardn, and when we went through this exploration capital spend, the scenario that we talked about. The only place we had production today in exploration was in Southern Alberta. So we do a small slivered production in 2015 associated with those 2 plays of less than 3,000 barrels a day. So the other 260 number, not very -- is almost a nuisance to manage it. And we didn't have any other exploration success of any other type in the 260 number. As far as the Cushing type, or the other question about investing in oil in North of Cushing. The biggest investment we have there now would be Seal. We see a Seal netback there usually around $60. It does it on occasion due to plan up set, north of Cushing go to 40. So I think what will happen in Seal, if we have a big investment in polymer, we have to look at some hedging, which we haven't done there in a long time and protect some of that $60 and get our sales into a $30 OpEx DD&A number and protect that $30 upside, and that's kind of how we roll there, but when you see a project like Syncrude, which will hurt when it goes down, it makes the Cushing differential go back up in that part of that land. And we will see ourselves at a higher level even though north of Cushing in Southern Alberta is quite high quality, so we don't really have all that mapped out yet, but I believe that could be a positive in that land to have some level of higher quality crude in that region. Yes, sir?
What is your compensation based on the risk guidance? [indiscernible]
Roger W. Jenkins
Well, our compensation numbers by our compensation committee but in typical, we have production settled in on a budget and it will be in the lower number which is what we typically do in our company. And that will be how our compensation of certain managers and others are related to that. But that will be approved by compensation committee, our board as we go forward with that process.
I think we need to get on our break here soon, I have one question for you, Roger, Julong East well appears to be very close to Kakap, are there any drainage or unitization issues you can comment on that?
Roger W. Jenkins
No, what we see from the data, primarily should discuss that with the operator, but we do not see anything from the data today that would say the production from that resource in paging of the Kikeh or Kikeh fault block production that we have.
David M. Wood
Roger W. Jenkins
That will probably be as part of the a there at some point in time. The well is not drilled yet, that is a fairly large homogenous structure there across that border. I would anticipate there would be issue there. We, from our high-level map, do not see that impacting. We see that being a smaller part of the bigger pie and is not impactful on anything we would have in this forecast here.
David M. Wood
Okay, thanks, everyone. Let's try to keep the break to about 10 minutes, so we can go back on schedule.
15 is good.
Okay, good afternoon, everyone. Welcome to the investor part of the presentation of the today. I'll just fix up the microphone and let's see if we could get hold of Kevin. Kevin?
My name is Tom McKinlay, and I'm [indiscernible]. Today, I'd like to provide you an update just enough to understand, but still we're starting to get...
Let us say, my goal today is to give you some insight into advanced stage business. Dave already described repositioning efforts in refining and where we are in that the process. And also an evaluation of a standalone retail business. That's currently underway, and as Dave said, something that will pick up later this year. So my goal today is not really to focus on those particular aspects, but we need to give you some insight and to just what that business looks like.
Today's agenda is very straightforward. First of all, I will give you a brief update on the remaining refining asset in Milford Haven, that's on Wales in the U.K. followed by the ethanol plants in North Dakota and in Texas, and then our U.K. market operation. Then finally, I'll get to the main focus of today's presentation, which is our U.S. Retail business.
So first, to Milford Haven refinery, and I'll think you'll agree with it's one of the nicest locations for a refinery office [indiscernible] in such a beautiful setting and near the natural parks of West Wales. Our focus in Milford Haven over the past year -- 2 years, has been on safe, reliable and environmentally secure operation and as you can see we have had 0 disruption [ph] over the past 12 months. For those of you not familiar with that definition of trivia which is total [indiscernible], that's roughly equivalent to 200 people working for a year on a full-time basis. So that's the sort of the level of denominator you have on that number, so we'll go through that time period, and that's how our performance really reflects tremendous well on Arcania [ph]. So once we have the foundation laid of safe, reliable operations, we will then able to target margin improvement in that business. We estimate we'll be able to add around $1 about our margin capture over the past year, if you look at 2012 versus 2011. You can bring that with a net pickup in the overall market, and you can see, our EBITDA has turn from negative $15 million last year to positive $20 million year-to-date 2012, that's to the end of April. Despite all of this has been achieved against the backdrop of huge uncertainty for our UK team without sales on process ongoing, makes that success even more remarkable.
Looking now on to ethanol plants in Hankinson North Dakota and Hereford, Texas. Our first plant in Hankinson, North Dakota, is a nameplate, 110 million gallons a year ITM plant, it's now running at 120 million gallons a year plus reliably, excellent yields, excellent reliability, and this year we're looking to extend our production to around 135 million gallons a year plus with the project we have company sanction. In tandem with that, we are looking -- exploring opportunities for further product developments in support of the business there. Last year, we started up the ethanol plant, which has been in construction for almost years. So originally, our [indiscernible] design we, essentially, accommodated that to post the ITM technology, very similar to the technology that we operate in Hankinson. The operation here is supported by the sales of [indiscernible]. That's the principal byproduct from ethanol production. Our own business plan in Hereford, 3 million ahead of capital within 15 mile of radius. So we don't really have to go too far to find a customer with that product. Residential [ph] business, primarily as a natural support for our Retail business. In the U.S., almost all the gasoline blended was up to 10% ethanol. There's no potential for that to increase towards 15% and being in this business keeps us close to both stage of that market, and keeps us close to our major component of our gasoline tool in retail.
I'll now get to cover our UK-based operation, we operate under the Murphy brand in the U.K. Just facts about the business, as you can see, we have 450 stores in the U.K. 253 of those are company-operated, we have a similar number of branded store. We sell approximately 185 million gallons of fuel per year, and this means around this fuel sales in the stores is around 50,000 U.S. gallon per month, so it gives direct experience of a low volume of retail operation with the focus is on convenience store as much as fuel. This is a very -- and it has been and will be a very stable business, as well as the economic downturn exactly well. I don't know if that translates to EBITDA, you can see here that consistent -- extremely consistent financial performance. These are much fully diluted numbers, including both G&A and I think that number was higher in 2011. We had a number of actual extra cost associated with the sales process. You can see here this is a very stable, very consistent business.
Now in case you don't notice, main focus and deliveries to the U.S. retail and U.S marketing. I'll begin first with -- particularly a step back looking at overall U.S. gasoline a month. This chart shows from Pyra [ph] shows the vehicle miles traveled in blue and the implied gasoline demand in red. First, I think that red decline in 2012, it's somewhat exaggerated as the EIA numbers is based on the [indiscernible] export to arrive on that number. But whether the EIA report on year-over-year decline of 4.5% or mass account spending for most survey, suggesting it's 5.5% to 7.5% over the first quarter performance. It's clear that the high-absolute cost in that steady rise through the first quarter hasn't impacted gasoline demand nationwide over the course of this year. So now I'll take you through hoe Murphy U.S.A. is operating in that environment.
We begin with an overview of network and help set us in context. First of all, some general background for those of you not so familiar with our operation, we opened our first retail store in Chattanooga, Tennessee, 15 years ago now and since then we've grown organically to the point where we operate 1,157 stores in 26 states nationwide. As you can see, these are predominantly in front of Walmart with over 1,000 stores there, and we've also grown our network every year. The other thing we said, we provided about 3% of total U.S. retail gasoline in our market area, 5% in our market share, and we've said, approximately 1.6 million customers every single day. We have historically strong growth model 91% of it's fuel in real estate and 100% of our store are company-operated.
This is probably [indiscernible] Because it looks very good, whereas the safety record really, and we have [indiscernible] safety performance here, something in retail as [indiscernible] as we are in refining. With over 7,000 team members now working with the public day in, day out to achieve the levels that you can see in your book that's not on the screen. Trysler achieved the level of total recordables around the level of industries, total lost times is a remarkable achievement and something, again, that points us much to the commitment and that the ownership of the team that we have on the ground of anything that we do in terms of our safety practices.
Moving now through our market, you can see here we have hotline this, if you look at the green space, those are the space where we have the highest concentration, the highest market share, 7% to 14%. The blue space between 3% and 6% and those red space are the ones where we have opportunity to grow and sell further. You can see that our hotline is in the bond stretching from the Texas in the West to Tennessee and Alabama in the East. And our goal is also to turn the rest of that map as green as possible. For example, take a state like Virginia, day after day we only have 3 stores. Part of the reason further is that Virginia is one of the states that has refinery regulation if you operate on all refineries, you can't build gas stations close to other competition. With a sale of our U.S. refineries at the end of last year, that incumbents has been removed. So the state has national progression for us when you see our infrastructure.
This is what our model looks like. I'll show not against in some of the peers in the marketplace. With the sale of our refineries, we now occupy a unique space in retail landscape with excellent customer leverage at a refining gate, and well-matched midstream infrastructure to allow it to be the low-cost supplier on the pump. Including our wholesale business, we have effectively a shot of over 5 billion gallons of fuel every single year and that's amended, where you can efficiently deliver that fuel to the market as well we can. [indiscernible] you can see some of our retail peers, the majors of the bond from the well all the way to the pump and kind [indiscernible] fixed are in that [indiscernible] from refineries to the customer. So we do know what occupy our wealthy unique space.
This is how we describe our model. We are the low price high-volume fuel seller. To be that low price high-volume seller, you have to be the low-cost supplier of the fuel into those stores. You also have to take control over your operating cost and how you manage that business. In addition, we're also a destination for niche merchandising, in our case, that tends to be predominant in the tobacco sales. We also look at the relationship we have with the world's #1 retailer, we've align ourselves to the world's price philosophy, which has been very successful for us. In my view, that makes us a compelling attractive business.
Just to put in context it's also a higher revenue business. Many of you I'm sure have followed Murphy, mostly because of upstream performance or EMP business. You may not appreciate the size of our Retail business. You can see here again some more well-known household names. This is a major revenue business. As I said we have the high-volume retailer, as you can peer -- our publicly-traded peers to compare performance with our publicly-traded peers, we are the high-volume retailer. You can see here compared to some of the -- again, this does not bear in your books, but those -- are not particular slide there. We also have a very efficient and supportive mid-stream operation. I made the point earlier to be the low-cost seller of fuel, you need to be lower cost to supplier of fuel. We have business scale and access to infrastructure that helps to reduce cost, we have no middlemen in our business. The pipeline has straight [ph] and a system that is often oversubscribed after the x number of opportunities to take advantage of market dislocations of over price potential between the golf and markets to the north. You combine that with a product supply group and a wholesale group that makes our inventory even harder for us in that region we're extremely well-positioned. We also have developed a proprietary Best Buy system, this is a distribution system for our trucking network, which ensures that we always get the cheapest product to our stores every single day.
I'll talk about product distribution network, that's how it looks. You can see here the green screen showing a proprietary tunnels, in blue where we operate in proprietary channels and hold inventory, and the pipeline network we are connected to it. Actually think back to the market this year, you can see that, that infrastructure leads over that extremely well. So once you have that low-cost fuel and you've got our product into your stores, how do we sell it efficiently? Based on the data we have from the National Association of Convenience Stores, NACs, Murphy U.S.A. operates around 35% of the industry average monthly operating cost. That's 35%. If you look at this chart here, this shows our the performance against the top quartile convenience stores against our competition. And I think you can see very clearly that the advantage this brings to our predominantly kiosk-based network, we do sell extremely efficiently compared to our peers.
Merchandising, I'll touch later, the fact that we are very dominantly a fuel business we sell fuel -- I mean make our money doing so. And in doing so you tend to think that we are not really heavily involved in merchandising. But just because we sell a lot of fuel, it doesn't mean we don't sell a whole lot of merchandise. Last year, we sold more than $2.2 billion worth of non-fuel goods, capturing $270 million of the market. In December, we have a onetime inventory adjustments that are just not figured by 8.4 million from 278 million. When we first started, we had high-volume [indiscernible], that draw a lot of traffic to our stores. We also reached agreement that we would sell merchandise in key offering for Walmart. What that meant was we were a one-stop shop for fuel and merchandising. It's attractive to the Walmart customer. However, the offer or world [ph] pricing, I think, fuel and niche products in close proximity to Walmart has turned out to be an extremely powerful model. That light doesn't stand still.
We are also making great stories in our margin capture across our range. We know that cigarettes are declining quite a bit. And indeed last year, the market fell by around 4% in the industry. However, we saw it actually grow by 5%. Beverages as we move into sort of a slightly larger store, making more efficient use of the space we have. Huge [ph] industry grew by 4% and Murphy U.S.A. grew by 16%. And then beer, a big surprise it was flat across the industry, we saw, again, tremendous lift in that sort of high-margin product, 22% in 2011. And what that means when you look at some of our publicly traded peers, our merchandising sales overall business where we stack up. Our performance maybe skewed towards fuel, but that does not mean that we are not a significant player in the merchandising front, achieving a total efficiency and turnover from our small footprint stores. I mentioned that we were advantaged by that majority of our store being in front of Walmart. Last year, we look to reinvigorate that relationship and this specialty was evidenced by the discount fuels that we run for the half of last year. Offering $0.10 a gallon discount for the use of Walmart gift card or Walmart credit card in our stores. As I said before, [indiscernible] still more and more, and the consumers are looking for value. Sometimes that need to be more than just price and co-promotion that best translate this. Something we believe bring great benefits to both companies, both Walmart and Murphy U.S.A., and it's something we'd like to do more often.
And again, this is more for both of you who are well informed. Looking at retail. This was actually up covered in penetration within Walmart supercenters. You can see it here when you look where we were strong all in -- we have a great penetration. Arkansas we're 76% of the stores. We have Murphy U.S.A. in front of the Walmart, all the way down to Oklahoma there. We have more than 50% of the Walmart supercenters have a Murphy U.S.A. sitting right out front. Again, touching back on the comment on Virginia, you can see down here was still had real good potential, geographically, as well a percent [indiscernible]. So my view, we have a great model. What really makes that model tick is our people. This photograph here was taken in the National Managers Meeting that's held every year in Orlando in Florida. And here we bring every single one of our store managers, our district managers and division managers, and as well as the suppliers in one place, all in all, there was about 1,600 people there. It really appreciate the energy and the culture that's evidently would have to be there. But it has a tremendously outlasting experience where we set and communicate our goals for the coming year, and you can just tangibly taste the buy-end our team has to the operation that we operate. It's also disconsenting to see so many people dressed exactly the same post getting at new, but not quite as I'm happy today. But those managers, enough cashiers really obviously Murphy U.S.A. Not only that, there were front-line customer service, front-line IT support, front-line maintenance, truly these go people above and beyond to contribute more so than I would say, other change in our footprint and doing a great job of making a model that works so well.
Expanding on that, I just like to tell you a little bit more about some of the aspects of our culture there, I think, differentiate Murphy U.S.A. First of all, there's a incentive program that we called Circle of Stars. Here we launched the top 10% of the store managers, district managers, division managers with an all expenses trip to some exotic locations in the Caribbean. This year [indiscernible] we do [indiscernible] the hurricane season. So there's no risk in the operation. But it's an extremely effective program, where success is judged by year-on-year improvements. And it's also tremendous in what bidding. You can see the buy end from our managers all the way through the year. And I think by the time you get to November, probably 80% on those involved still had a chance of reaching that top 10%. So that incredibly affect the program, really it does demonstrate -- our managers, our sales force as opposed to just someone who swipes credit card in the store. In terms of our overall cost efficiency, our future views on effective online recruitment process, if you join Murphy U.S.A., you will probably just have touching a piece of paper. However, the recruitment is done online, given to the point of using online video interviews as a little cost filter than on an equipment chain. Everyday, we also communicate the rent with our stores. We keep it a simple key messages that resonate to people like to read. They might be a reminder of the [indiscernible] Circle of Stars promotion, and maybe an explanation to share with our customers as to why gasoline prices are rising. That was obviously fewer in the front-line and price that risen so high in the first quarter. Your customers aren't to happy. Being able to support our staff with information and advice as to why the market is right in the way it was, was helpful to those in the frontline. So we do have an exceptional team. A little bit overwhelming sense of ownership within Murphy U.S.A. that makes the business special. And any of you, who took the opportunity in previous years to visit our home office, national support center will sense the energy, sense by an ownership of the people have. I think it's done a unique atmosphere in energy that will drive this business forward. Again, standstill, we're very active in social media. We have our own Murphy U.S.A. mobile app. We encourage everyone here to download it, especially when you're driving around the country. What that does, they'll tell you the current cost of fuel in the nearest Murphy U.S.A. to you, but not only that, it will give you realtime cost of our competitors fuel, because we believe that we will be achieving some time, and we're quite happy to share that information with our customers. It is also a way to get great feedback if or not because of that, we can react extremely quickly.
In addition to this, we are active on Facebook and on Twitter, on Foursquare and blog, any way that we can connect with our customers in today's online environment. That makes sure that we are delivering exactly what the customer wants. It's our job to sell to customers what they want. It's not for us to find a way to get them buy what we have, we really have to be completely customer focused in that way. You can see we're looking some over quite a million of those outstanding by the end of the year. So now looking forward on how we intend to keep this business modeled. To put in context, I'll begin by looking back. This slide here shows a retail financial performance since 2006. You can see in this snapshot that we've consistently profitable during that time. About a year in 2008 was held by that sharp decline in wholesale prices that took place in the final quarter of that year. Also, if you look at 2011, we had an extremely successful year coming close to those levels. So I think over the year, surely, this business has grown, has matured and is very much a substantial independent entity within the Murphy Oil Corporation.
On the last week's earnings call, much has made about our disappointing first quarter and believe me, I was disappointed too. But again, let's look at those results in context for Murphy U.S.A. What I'm showing here in this chart is the blue bars really reflects our first quarter EBITDA going back all the way to 2002. You can see that absence outliers in 2008, and 2011, really was walk between that negative $6 million to $14 million EBITDA through the period. The red line, which is the fuel national seismic gallon margin here that [indiscernible] reached $0.09 a gallon and has been as low as $3.7 a gallon. So [indiscernible] welcome, this is not [indiscernible] and I know investment will come back strongly from it, already it's rebounding. The $4 million EBITDA that you see there, for me, it's not material range from previous year. We're stepping on the successful years. If you look at 2009 which was, I guess, similar performance, down to the last quarter we saw persistent arising wholesale prices through it in the first quarter. So looking against this year, you can see here how the 2 contrasts. In 2012, which are the 2 top charts, we lost around 6% volume in that year against the market backdrop I mentioned earlier, the overall market is down between 4% and 7%, depending on your source of analysis. But our margins within striking distance it appears here. I think that the latter number is a little bit discounted, I think they include credit card fees which we raised up overall gross margin up, close to where we are. But it's not an even distribution across our network I would like to think we lost 6% everywhere.
In space like Arkansas, we gained volume. If you look at the Midwest in Indiana, in Michigan, Ohio as a whole, we gained volume. we know the states where we were successful, we know pretty much why we weren't success. We are able to address it effectively during that period. But know that the market has rebounded somewhat and has given us more flexibility. We were looking to improve on that as we go forward in the coming quarters. In terms of -- the point that I was going to make was on the wall chart here, you can see in 2009 and here we held on to volume pretty well. We lost a lot on the margin compared to our competition. So we recognized the importance of both maintaining our market share. We recognized the importance of financial contribution from a strong margin. We are introducing more and more analysis and more sophisticated pricing technique that will allow others to truly understand our network on a store-by-store basis so that we will effectively how that 1,137 individual markets that we would be able to manage.
So in terms of those competitive comps, I'd like to make clear, this is by no means a comprehensive amount of competition. This is really just pure retail peers, a public, and we have the data to show you here. And this is drawn from the latest public reports that we had up till yesterday. Much of the competition we face naturally come from very effective [indiscernible] pipe companies, companies such as racetrack [ph], or quick [indiscernible], who do what they do extremely well. So we do have a broad spectrum of competition in all the areas we operate. But what I would like to sort of address in this table is against the moving along the top tier [indiscernible], notable 5.4 all the way up to 10.8. And if you look at some of the key metrics from last year, I think we faired fairly well. For example, we sold more fuels that has been cushed up for like 20% from the number of stores. Our EBITDA per store of $326,000, pretty much led the pack, and our average return on invested capital are extremely healthy. Again, we also a 91% so simple -- excuse me simple one. So looking now at the potential we have to grow this business. I'm going to touch on some of the main avenues where we believe we will be successful, where we have genuine opportunity to be so. You also noticed it's a little light on detail and specific on that growth, I am afraid that is deliberate. Much of what you see here reflects ongoing conversation, some will also be influenced by the outcome of the evaluation of those Murphy U.S.A. become a standalone business. The shape and format of the balance sheet we go over to make that decision allows us to influence the pace and ability to grow the business. Either way, my role in this position is simple, is to position our company to be in the strongest possible footing, whichever route we choose.
So first of all, on Walmart. This partnership has allowed us to generate industry-leading returns and as one way of achieving to develop still further. The store on the photo on the top shows part of the evolution of our kiosk. We started out with a very small 208 square foot kiosk, the one you can see here is the 508 size, bringing the merchandising inside, away from the -- some of the biggest in the weather. And if you look now, default going forward, it's really a 1,200 square-foot kind of super kiosk, if you like. This can be built, of course, of the same cost as a smaller building. They can fit under the same canopy on the same footprint, on a Walmart parking lot. It offers great opportunity in terms of the higher GP, products that we can sell from within that box, all on the same cost-efficient model. We're also looking at how we can diversify our business. We have been tremendously successful with our partnership with Walmart with relative capital margin from tobacco sale, but obviously we recognized when you're so good at one thing like at divesting growth that will continue progress on that. You can see here in the background their lowest, just behind is market express. This is a standalone market express build on strong sites in front of [indiscernible]. It doesn't mean the sector are the same traffic pattern of Walmart, they have a very different traffic pattern. But what we do have is great geographic coverage, very much complimenting the footprint that we have already. And probably that hit some great real estate. So there are other incentive there to look at some of those other partnerships.
I'm about to lift the standalone growth outside the Walmart plan. You can see here in the bottom photographs that's 2,756 stores in Aurora, Colorado. Standalone really built on merit, and the challenge there as we move away from, let's say, some of the cost benefits, we have been in front of the Walmart is how do we make these operations at these stores as efficient, not effective as small kiosks. So we're always maintaining that sound financial discipline we've always had, and we are again to the point where these stores are comparable to the returns we would get on a kiosk. So, again, showing our ability to build up from where we stand today and to conclude the business to an even greater platform.
So in summary, I'm wrapping up, we are a low-cost model that takes the product from the refinery direct to the customer and thus so extremely efficiently we are a high-volume retailer. We have very strong relationship with the world's #1 retailer, with an established and strong history of cost promotion. We have great access to growing in high-traffic locations and I describe, albeit somewhat elliptically, we have an enviable platform for future growth. We're able to fund the growth in our own cash flow. We have to grow into new markets that can achieve good returns both in rural lands and urban setting. We are actively evaluating further growth strategies. This is a business time extremely potent. I'm proud to be part of it. And I believe we're well-positioned to create tremendous future success through our company, through our team. [indiscernible] Are tremendously successful with our good company. So cover all of it up to the end.
If you look to where we've been going 2011, that's 2010 which started in February, before we expect in January to be a little lower anyway, we knew that was coming? But what then happened is the Walmart discount program ended at the end of December? That obviously impacted on the floor. We would look to regain that volume using pricing. At the same time, pricing just rolls consistently all the way through the first quarter. With no respite really where you can actually choose to capture through management. We could have chosen to load at least more evident and get some volume, by that way. But also in some of those states, we are restricted by the low cost. So we would like to have cut some of our prices the regulations prevent us from doing so. So using price alone to bring that customer back was very difficult in the market. They're always deadly through the first 3 quarters. I would now come back to a point where we have, how would I describe as healthy margin today. We see not recovered by 1 point, 1.5 point. So I think the -- we have the ability and we have the tools to choose where we capture the margin or market share. And then we're looking that through this quarter next quarter. Know that we're back in a more traditional monsoon environment.
I hope not. Again, I'll touch on that is something that Walmart are -- operate a various individual system working with them is something we have done successfully over the years. We like it to grow strongly within the future because others have tried to operate in front of a Walmart and haven't been so successful. We embrace that every detail of price philosophy. We can do well, we have infrastructure to make it successful and profitable and operate in that philosophy. And I think we are looking at the best ways to grow that both geographically and within our core area. That's one of the avenues. Certainly, I would never discount such a successful model that's worked so for us well over the years.
In the small subset, talking how would [indiscernible] Yes, I think people looking at fuel as a weakness sometimes, but no industry does well as we do. That's why, I believe, it's a strength.
[indiscernible] A little bit more growth [indiscernible]
I think if you look at different Murphy express. They are more expensive so we have to make those signs work harder. Very often the building [indiscernible] so you're working with the local states to get those sort of -- so let's repeat the question, which was where would growth come from and how would that be with Walmart? If you look at our standalone, lot of Walmart stores, we've introduced a whole U.S. in terms of extracting the higher-margin products that we limit much so previously. We sell a lot of tobacco products, we sell a lot of lottery tickets and those are in the low range of the GP with the margin scale. We are now improving our beverages, improving our offerings with those higher margin products available to us. We are seeing returns now comparable in the last Walmart stores, we were seeing with kiosks. So we are showing that we can do that. We can generate the funds to build those stores, free cash flow and if we choose that to be more successful then will do that. If we got higher return, even in Walmart, then we'll secure investments in that direction.
Now listen, this will be a market that consolidates. If you look at the European experience and if you look at the chart in your book you'll see that from probably a 1/3 of the stores accepting 17% of the stores, slightly 21% of the fuel, and they're gradually capturing more and more market share. Our experience in U.K. has been overall fuel has been somewhat based but based on the [indiscernible] to comp more share. Then the [indiscernible] 50% overall in fuel, down also in diesel, and down heavily on gasoline is the utilization if this continues. We haven't seen that same trend in the U.S., but we are seeing a trend, of course, is becoming more and more grocers becoming friendly towards selling fuel. I think when you're part of [indiscernible] fund of the #1 retail in world. That's a great place to be. The top model is embraced in the U.S. You're seeing [indiscernible] and others.
Probably one of those 3.
I think you see baseline up to this point. Sorry, can you repeat the question, I didn't catch it. I'm sorry.
David M. Wood
Yes, I think it's a great question. The question sits around how well proceeds or value come back to the corporation from a potential spin of separation of the business? And all of that is being worked. Clearly, we've engaged bankers and our own staff to be able to analyze all of that. So we started off pretty simple thing, what is the best thing to do for our shareholders, so we started at number one. The second thing was, was it the right thing to do for that kind of business. And so where we are today is kind of very close, I would say in my view, as what we should do. What we have done before in our corporation is create a new company that we can deal with, I think a spin has a lot of benefit to our shareholders and allow that business to continue in its current form, which is a trajectory of growth and improvement performance. So that's kind of my favorite as I kind of look at it so the value for the shareholders become a piece of paper at the end of in addition to the stab company piece of paper that they have. One of the questions that falls of that, so why haven't you done it so far? Which is a great question. I feel as, though, you don't have to rush with the right answer, you just have to get the right answer. And so I think we're working along the path of addressing all of the issues both from the stab company that I mentioned at the outset. And also from the company that Tom runs very, very well, making sure the organization is right, making sure that we have the right relationships with partners that we currently have and partners that we want to have, making sure that we have the right capitalization for that type of business. So you when you bring all those things together, I think, we're kind of in the go window for us to take to our board and say, hey, this is the answer for those particular question. So I don't feel rushed, but I think we are about the right time window. I wanted to see how this first quarter was going follow in the second quarter. I think the questions that were asked by Bob or Paul were good questions. We try to address them and say, hey, we're used to this. This is nothing unusual and now I think we're seeing in the second quarter results where we are also see us perform. Second quarter, third quarter here expect us to do pretty well in the business. So I think our shareholders will do pretty well from this business. That's how I kind of address that. Got any more questions in the room, if not, I'm prepared to wrap up. Barry, do you have any coming in from the web? God, I got lucky, thank you.
Let me -- in essence of good timekeeping, kind of wrap us out here about on time, and give you some of my thoughts as we kind of close this. Kevin talked about our forecast here and what we've tried to do is include cost assuming expirations success. We are in the exploration business, we have smart capable people, I think doing smart, good things. It is a program over time. There is capital in our business that we assume we are going to spend, because we assume we are going to be successful. I don't buy the subscription that Kevin said, well, gee, if you don't find anything you get all that money back. I actually don't want that money back. I want to spend the money, and I want to spend it on successful project that help up company grow. So I think we're situated that way. As I look at Rogers business, I think gas will come back. We have a great asset in copper below ground and above ground. But I think it's going to take something north of $4. When we get to $4, I'm not quite sure, our projections show something in the 14x and 15x swap, it if it gets above that even for a period of time, we have something we've never had before, which is tremendous flexibility in that gain. So I regard that as being a very nice plus for us. He talked about some of the prices that we have, which I think have been somewhat understated in the past. Even further is a 400 million barrel to us price. Seal is a 400 million barrel to us price and Southern Alberta while it's still early days 100 million barrel plus price. These are all things right ahead of us for a company that's only got 530 something million barrels booked, it's a pretty nice position to be in. We are in Floating LNG and hope to be in that -- that gives us an advantage, I believe, being one of the world's largest and most successful gas players to go to places like Australia and if we are successful finding some liquids-rich gas to be able to move forward and monetize that, we will understand that business.
Malaysia is very important to us, Canada and the U.S., they are today in 2015 and beyond will be the bulk of our business. Kikeh is a great field, but we are doing great things in other places. That Kikeh will play a less and less role in what we do.
Having said that, the issues that we've had with the screens and sand migration, we have a technical solution, we have rigs in the field and we have capital being spent to remedy that. And as Roger said, I think we are in pretty good shape going forward. I think you mentioned one something about production forecasting. I have a note here. We spent an awful lot of time wanting to get it right. I mean we are a bunch of people that wants to get things right. We have been personally disappointed in our ability to predict. We believe that by resetting the clock, re-putting new people, smart people in what we're doing, learning from the lessons in the past that we have a more appropriate way of going forward. And so I feel, personally, very good about the talent, very good about the process, and very good about the trajectory that we now have established for where we want to take our production. Sam is a very talented exploration leader. I think the quality of our prospects now are exceptionally good. We have some very impactful, very well-defined opportunities, we are drilling them now. We're going to drill them next year. You didn't see much of what's going to be drilled in 2014 and 2015, it was a question about Suriname. Suriname, for some strange reason, is the pretty darn hot block, and we've got a lot of people knocking at the door, and we haven't even got the full data done yet. So that goes to, I think Sam's and his team's capability in spotting things early, all of which bodes very well for us down the road. So the upstream business I feel really good about. I wouldn't feel bad at all about separating our businesses having a standalone retail business in a standalone independent E&P business.
On the retail side, the reason we've been a little bit coy about exactly what that business looks like, is clearly from the message that we've given it as a very good business today, and we see trajectories continuing in the future. We have some things that we have to do, in order to be able to go through the normal gate, which is get a board approval and then talk about it specifically. I think it would be a good business, it would be a strong standalone business. And in a world of gas prices, gasoline prices, that are going to be moving up rather than down, being the advantage low-price seller in a place where people want to buy is going to give you advantage and that's the advantage that we are seeing, getting that organization right, getting that balance sheet right, getting all of those other deals right is really what the focus of our company is today.
The other thing that, that company has, it has a great culture. And I speak at the conference that Tom referred to every year. And when you are in a organization and you visit an organization, you can tell when you are in the presence of winners because you can see a unity of purpose, a unity of culture and a unity of results people want to achieve and that organization has that. And it's not everybody in the blue shirts and khakis. It's in what they believe and most of those stores are in small towns were being part of a bigger company with a global, if you will, and their world relationship is very, very important. That's very, very empowering because I can't tell you how many times I've been to a non-Murphy gas station and have been worried about the type of location I'm in and the type of service I get and the cleanliness of all these other issues. And part of that is because it's not addressing the customer service, it's addressing just the cost space. So I think we have the advantage in that particular business. And so I think it's going to happen. I think we're doing it at the right time with the right consideration of our board, and I think the company that you will see as Murphy Oil Corporation, a stub company will be in a bucket of pretty strong independent E&P businesses and I like our chances. We're pretty darn good at exploration over the years as Sam showed. I think we're pretty good at developing things, we operate things, we have a great reputation, we are a national oil companies, [indiscernible] who is our ideal partner, is a national oil company. We make lousy key partners for super majors because we have individual accountability in our business. And I think we have the balance sheet and the flexibility to be able to execute on some projects that can be really meaningful for us. So that's kind of how I see it. I'd be happy to take any questions. I recognize that by saying that I'm spending [indiscernible] getting out of here, having cocktails. So with that, I will open the floor to any and all, if not you can get hold of me at dinner tonight, and I'd be happy to address it. Paul?
David M. Wood
The question really is about M&A and how we like our opportunity. And I think it's a good question. I've said in the past that I would like to make acquisitions to grow that asset base of our corporation. Because I think the broader base that you have, the more choices you have, the better able you are to respond to things that change our business. I wish I had 4 million acres of land in North America rather than in 1 million acres, for instance, I think we have tremendous flexibility until and we've seen some companies here, all of a sudden open their book and say, wow, we've got something in the Permian Basin that we never gave any value for, now it's the hot play. So always looking for that. I do wrestle with the idea that this is the low point in the gas tank. When I look at energy prices, oil and gas and FLNG and LNG and all of the components, it really bothers me that there is such disparity between North American gas and world gas, and gas and oil. And so I wrestle with the idea, and I've told my board this, that one of these days I'm going to get an airplane. I'm going to come here, and I'm going to ask you to approve the purchase of an acquisition of some gas resource for a very reasonable price because long-term, and this is a long-term business, I think it will put us in good step. So that will be one example. The other example is as we work overseas, we can see in some places opportunities where we can bring technical operating skills which is distinguishing capability to places that have discovered resources. And we have got close on a couple of those. And if we could get closer, then it's great -- and so that would kind of be the 2 types of end members. I thought we would have to buy to get in the resource game, but we found that getting an Eagle Ford real early, getting Southern Alberta real early, getting in Muskwa real early , I don't have to write a big check. And I like that, because I'm thinking those particular gains, that gives us a competitive advantage. So Roger starting off with a deck having less than $2,000 an acre in his Eagle Ford position, and a couple of hundred bucks in Canada and gives us a tremendous advantage. So we didn't have to write a check. But I'm always looking for M&A, we have a group that looks at those, sometime will pull the trigger. Any other questions. Yes?
David M. Wood
The other is an Eagle Ford question about a specific part of the acreage footprint in Tilden versus Karnes. And the simple answer, I love it all. If you look at what people have paid for acreage in both areas, that kind of gives you a sense, there's not much difference between where the market is. I think Roger's comments about drainage and down spacing are really going to be the issue. The big advantage for us, Tilden versus Karnes and so we are higher working interest in Tilden by a lot. And it's a little bit shallower, so maybe the costs will be a little bit less. So I think overall when we kind of level it all out, we should get them pretty close. And Karnes is a nice sweet spot, but I think Tilden has got a lot of good potential. The other technical thing I would just add, is maybe a little bit more energy in the Tilden even though shallower a little bit more, so we'll see what happens. But nice. Barry, do you got anybody hanging on the line, none of course. Okay, good.
I appreciate everybody coming. It's been a long day, I want to thank you, all and look forward to seeing you tonight. Please feel free to come and ask questions with me or any of my staff. They are way smarter than me, and we'd be happy to address them all. Thanks a lot.
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