Murphy Oil Corp (MUR) 2011 Q1 法說會逐字稿

Ladies and gentlemen, good afternoon. Welcome to the Murphy Oil Corporation first-quarter 2011 earnings conference call. Please note today's conference is being recorded. And now, I'd like to turn the call over to Mr. David Wood, President and Chief Executive Officer. Please go ahead, sir.

Thank you, Operator. Good afternoon, everyone, and thank you for joining us on our call today. With me are Kevin Fitzgerald, Senior Vice President and Chief Financial Officer; John Eckart, Vice President and Controller; Mindy West, Vice President and Treasurer; and Barry Jeffery, Director of Investor Relations. I will now turn the call over to Barry.

Thank you, David. Welcome, everyone, and thank you for joining us. Today's call will follow our usual format. Kevin will begin by providing a review of first-quarter 2011 results; David will then follow with an operational update, after which questions will be taken.

Please keep in mind that some of the comments made during this call will be considered forward-looking statements, as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur, or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2010 annual report on Form 10-K, filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Kevin for his comments.

Thank you, Barry. Net income in the first quarter of 2011 was $268.9 million, or $1.38 per diluted share. This compares to net income in the first quarter of 2010 of $148.9 million, or $0.77 per diluted share. There were no unusual items of significance in either period, but the 2010 quarter did include $41.3 million, or $0.21 per diluted share, of after-tax losses on transactions denominated in foreign currencies, compared to an after-tax loss of $1.1 million on similar transactions in the 2011 quarter. Taking a look at income by segment, in the E&P segment, net income in the first quarter of 2011 was $260.4 million, compared to net income in the first quarter of last year of $247 million. Higher E&P earnings for 2011 were primarily attributable to higher average crude oil sales prices, which were up about 34%; the higher natural gas sales volumes also contributed.

Unfavorable variances in the current quarter included lower crude oil sales volumes, higher exploration expenses, and higher workover costs at the Kikeh field in Malaysia. Crude oil condensate and gas liquids production for the quarter averaged approximately 113,300 barrels per day, compared to approximately 139,000 barrels per day in 2010. The decrease was mostly attributable to a lower gross volume in the Kikeh, due to wells shut in awaiting workovers; and in the Gulf of Mexico, due to delays in permitting.

Natural gas volumes, however, were a quarterly Company record of 413 million cubic feet per day, in the first quarter of 2011, compared to 343 million cubic feet in last year's quarter -- an increase of over 20%. This increase was due to the startup of production at the Tupper West area in British Columbia, and higher volumes at Tupper Main, offshore Malaysia, and at the Mondo NW field in the Gulf of Mexico.

In the downstream segment, first quarter 2011 showed net income of $30.7 million, compared to a net loss in last year's quarter of $29.7 million. In the US, downstream operations recorded income of $39.4 million in 2011, compared to a loss of $14.7 million last year -- mostly the result of much-improved refining margins in the current quarter. Additionally, the 2011 quarter saw quarterly records for US throughputs of over 169,200 barrels per day, compared to reduced throughputs last year, as the Meraux plant was shut down for six weeks for a planned turnaround.

Results in our US marketing operations were slightly improved over the last year, as higher fuel and merchandise margins were partially offset by lower fuel and sales volumes. UK downstream operations recorded a net loss of $8.7 million in the 2011 quarter, compared to a net loss of $15 million last year. As in the US, the improvement was largely due to better refining margins and a quarterly throughput record at the Milford Haven refinery. In the corporate segment, the first quarter of 2011, we had net charges of $22.2 million, compared to net charges in the first quarter of last year of $68.4 million.

As mentioned earlier, this favorable variance was mostly attributable to significantly lower losses in the current quarter, on transactions denominated in foreign currencies. At the end of the first quarter of 2011, our long-term debt amounted to $974.4 million, or 10.3% of total capital employed. Cash, cash equivalents, and short-term investments totaled over $1.1 million at March 31, effectively resulting in net debt of less than zero. And with that, I will turn it over to Dave.

Kevin, thanks a lot. First quarter witnessed strong oil price moves, with benchmark WTI rising from $85 a barrel in January to $105 in late March. Dated Brent trended higher and sustained at least a $10 premium, as WTI remained landlocked and regionalized. Global events such as the discontent in North Africa and the Middle East, as well as tragic events in Japan, all helped support global crude's rise. Most signs point to this being the new acceptable level; and as such, we have raised our price outlook to near $90 for the remainder of the year.

Natural gas prices in North America continue to languish near $4, and we see this trend continuing through 2011, absent a better supply and demand balance. Business in the Gulf of Mexico remains challenged, with a lack of permits. The level and type of recent issues, while noteworthy, don't highlight a clear and predictable path forward. We have one permit for a re-entry at our Front Runner field, and are hopeful others will come later in the year. Onshore US and globally, our business remains very active. We have one exploration well currently drilling in Indonesia at the [Lenquist] prospect, and expect to be at final target by month-end.

We recently completed our first phase exploration in Suriname, where the Aracari well was plugged and abandoned. The bulk of our exploration work begins midyear, and we look forward to an active program, with significant targets being tested in several countries.

In our upstream business, global production for the first quarter averaged 182,154 barrels equivalent per day, slightly below our first-quarter guidance of 185,000 barrels of oil equivalent per day. This variance of 2,846 barrels oil equivalent per day was mainly attributable to startup and commissioning delays with the new Tupper West gas plant in extremely harsh winter conditions, and unexpected downtime at Schiehallion to repair the export hose.

In US retail, operations were steady with margins coming under pressure in January and February, which is typical for this business in the first quarter. US refining margins were unseasonably strong in the quarter, and both US refineries exhibited steady operations to capture what the market provided. The UK downstream business concentrated on operational performance in a difficult market environment. Our plans to divest the refining business are moving forward, and we expect to announce the sale of one US asset midyear, and the second soon after. The UK assets are following along behind these. Given the number of parties interested in each asset and the decision to sell separately, this timing fits well.

Production guidance for the second quarter is 187,000 barrels of oil equivalent per day. This increase over the first quarter is primarily attributable to ramp-up of production at Tupper West and progress with our ongoing Kikeh workovers. Production for the year should average 200,000 barrels of oil equivalent per day.

For the remainder of the year, we will see production increases from Tupper West, Sarawak Gas, Eagle Ford Shale, and Seal. Kikeh rates will fluctuate through the year, as we work over three wells. We currently have three wells shut in, as the new sand screens placed in wells since late last year have performed below expectation, and we are moving to recomplete using an open-hole gravel pack technique. This work is confined to a single reservoir, one of the field's shallowest and most poorly compacted.

2011 and 2012 will see an active exploration program, testing a dozen prospects this year and close to 20 next. We are off to a slow start in terms of activity levels; and as I mentioned, have a second dry hole in Suriname, where we found the objective water-wet. We still have several unrelated prospects, and we will use this time to re-rank and re-risk that program. Apart from the ongoing Lenquist well, we should have a third-quarter program start up in Brunei and other important drills in Kurdistan, Indonesia, and Congo later in the year.

Underpinning our growth program, we currently have 12 rigs active across our resource plays, and we will see that grow to 17 rigs by year-end. In the Eagle Ford Shale, we are stepping up activity, with four rigs working now and plan to get to seven rigs by year-end. Last December, we sanctioned a project in the Karnes area of the play; two of the four rigs are active there. To date, we have drilled 24 wells, with 15 producing and nine awaiting fracs. Well results continue to be very encouraging, and are trending better than our [type curve] for wells in the play. We have a dedicated frac crew, which completed six wells in the first quarter, and will continue to knock off three to five wells a month, going forward. The region has been hampered by takeaway capacity, and we expect this to improve as infrastructure projects move forward into next year.

In Western Canada, we have eight rigs operating between the Montney acreage at Tupper, our heavy oil operation at Seal, and appraisal drilling in the Southern Alberta Exshaw play, and have plans to add two more rigs this year. Our project at Tupper West came on production in late February, and is currently producing near 100 million cubic feet a day. Production is expected to ramp up throughout the year, and exit 2011 near 150 million cubic feet per day. The Tupper Main production remained stable at 100 million cubic feet per day, as both projects are seeing excellent well performance results. We continued to manage costs and performance closely in the current natural gas price environment.

Heavy oil production at Seal continues to plan, with current production rates over 7,000 barrels a day. The EOR pilot work continues, as we evaluate the effectiveness of both polymer flooding and steam stimulation to unlock the 5 billion-plus barrel resource in play on our acreage. Polymer injection is underway, and early results are encouraging. Applications for a steam pilot and a commercial polymer flood will be submitted this year.

We have drilled the first two appraisal wells of a six-well program in Southern Alberta, to target the Exshaw Bakken formation. Both wells have been completed and are being evaluated. It's very early days for us, but I am pleased that the wells have flowed within our expectations. We will continue to add acreage in this new play, as it fits with our understanding.

Business development is active, and we expect to add a second block in the Kurdistan region of Iraq very soon. We also are close to finalizing a new position in Vietnam, to add to our important Southeast Asia portfolio.

The process to divest our refining and UK marketing assets is at an advanced stage and moving forward, as I mentioned earlier. In the US, the retail chain expansion continues, with 14 stores added year-to-date, bringing the current station count to 1,113. US manufacturing margins were unseasonably strong in the quarter, making $28.7 million of net income. Both refineries operated well during this period, and achieved a record for US throughput. In the UK, the Milford Haven refinery continues to struggle in a difficult Northwest Europe market environment. The retail business continues its solid performance, even in a tough market of rising wholesale prices.

In our renewable fuels business, the ethanol plant in Hankinson, North Dakota is operating well, at 120 million gallons per year level. Crush spreads are under pressure, as corn prices outpace ethanol; and corn supply is expected to remain tight this year, while high ethanol production, coupled with a soft demand for gasoline in the US, has led to high inventories and oversupply of ethanol in the system.

The cattle feed byproduct dry distillers grains and solubles has kept pace with the rising corn prices, and has provided solid revenues for the plant -- effectively offsetting the cost of operations. Plant modifications at the recently acquired Hereford, Texas ethanol plant were completed late in the first quarter. Plant startup and commissioning came in as planned, and the plant is currently ramping up production, with rates near 75 million gallons per year. In summary, a good start to 2011 -- a slight miss on Q1 production, but on track for the year. Better than hoped-for Q1 US refining results, with the first asset sale to be announced shortly. The production of 300,000 barrel equivalent per day target by 2015 will be underscored at our upcoming analyst meeting associated with our AGM. But it too is on track. US retail will also be a feature then, as that business underscores its attractiveness.

Exploration is second half of the year weighted; Lenquist will be down this quarter, but nice prospects in Brunei and Congo give us big upsides as well. New countries being added broaden and lengthen our opportunity profile, and are complemented by our North American resource position, where momentum and drilling activity is building. That concludes my prepared remarks, and I'm now happy to take your questions.

(Operator Instructions) And our first caller is at Raymond James, Pavel Molchanov.

Thanks, guys. Two quick ones, if I may. First, on Suriname, following the two dry holes, just curious kind of what the road map is, going forward -- back to seismic, or if you are giving up on it altogether?

Okay. Suriname, the first two wells both found reservoir where we thought they would find it. We did have oil shows above the reservoir in the first well, which gave us encouragement for the charge story. The second well found a -- quite a limey or carbonate reservoir package, which didn't have shows. So, our questions in our mind today are -- do we have a seal issue, an updip seal issue on these prospects that we have drilled? And the question of trap integrity, so that they had trapped the hydrocarbon.

So, we're -- as I mentioned in my comments, we are going to re-rank and re-risk here, and look to see what our program should be next year. As far as being down on Suriname, it's very difficult when you're in the exploration business to get down and drilling dry holes, because most programs drill more dry holes than successes. And I think you have to look at it as a program. We still see some fundamental support for exploring in Suriname, but we need some time to put these well results into context.

Okay. Great. And then, just to follow up on Kurdistan, of course we've seen a few of your competitors have some nice announcements there recently. Just an update on that would be helpful.

Yes, we're -- the second block, we should be very close to announcing here, it's a non-operated position. The first block that we announced, we are in the process of getting our seismic done this year; and I'm hopeful that we can get on and get a well drilled as soon as possible. The street address is very good, other people and some results, particularly recently, have shown that that area is quite prospective. So, we're pretty excited about that. We see long-term some of the issues in Kurdistan being worked out, in terms of getting export; but we think we are into that play at about the right time.

Thanks very much.

Thank you. Appreciate it.

Let's move on to Howard Weil -- I'm sorry, at Howard Weil, Blake Fernandez.

Good afternoon, David. Thanks for taking my question, guys. David, you mentioned Kikeh and the recompletion work. I'm sorry if I missed this, but I'm just trying to get a feel -- do you have a sense of when we may get production back to kind of normalized levels, if you will?

Yes, let me take that and go a couple of ways here, Blake. Let me talk about Kikeh and where we are at and what we're doing. And then let's address the production for where we are today and where we are going to be at the end of the year, and then address this 200,000 number, if I could. So --

Yes, absolutely.

So, if you'll bear with me, I will kind of step you through some things that I think are important to note. Kikeh's produced about 120 million barrels. We have a lot of good information on the reservoirs and on the field, and feel very, very strongly that it's a great field. The issue that we have had over the last six months is really to do with fines migration in our shallowest reservoir. And not all wells in that reservoir. What's happening is, today we have three wells in that shallow reservoir shut in. Two wells are on the Dry Tree Unit, and one is a subsea well, and I will get back to that in a minute, as to why I distinguish those two. Those wells, last year, were producing at pretty nice rates. As they started to make these fines, we choked them back.

One of the wells, we replaced the screen and had some pretty encouraging results. We subsequently did the same with the other two wells. What we found out was that those screens replacement were kind of a temporary fix. And so, when we closed those three wells in, they were collectively making about 17,000 barrels a day; back last year when they didn't have a issue, they were making 37,000 barrels a day. The other interesting thing to note is when the wells were shut in, two of the wells had a water cut very low. One was less than 2%, and one was 4%, and the other one was a little over 40%.

And so, we don't think it's a recovery from the well, we think it's an ability to manage these fines migrating through the screens and into the well bore, and then up into the surface equipment. And, with some investigative work, what we believe is happening is that when we set these screens, in some circumstances, we leave a gap between the screen on the outside and the well bore. And so, that instability or that area is where the fines move, and then they migrate to that area and then in through the screen, because these things are below the size of the screen. So, our proposed remedy here is kind of a bit of a standard one, is to come in and do some open-hole gravel packs. And so, we're set up to do that for these three wells.

Now, I mention Dry Tree Unit and subsea. We have a rig on the Dry Tree Unit now, but it's reached its end of contract. And so, I would have loved to have been able to move straight into this work using that rig, but that rig is going to demobilize here very shortly, and we are going to mobilize a new Dry Tree Unit-based rig in the third quarter. And so, two of the three wells will be worked on by that rig, once it arrives. The third well is a subsea well, so we are bringing in, by middle of the year, a floater rig to work on that and do some other work; and then also do some work on [Siacat]. And so, it'll address that.

So, the work at Kikeh is really about getting those three wells back on production. And today, or kind of here within the near term, we've been about 75,000 barrel gross. And we expect to leave the year right at 90,000 gross, just a little under that. And so, the remedy through these workovers is really where we are trying to get to, and manage this fines production.

So, let me kind of transition from there and talk about what our production profile and how we get from where we are today to where we are going to exit the end of the year, and then how that gets us to the 200,000 barrels. And that all kind of adds together.

So, if I start at the end of March, 188,000 barrels a day -- by the end of the year, we will be producing 230,000 barrels a day. So, that's a 41,700 barrel delta. And so, if I break down where that increased production is going to come from, 13,800 is going to be from Tupper, Tupper and Tupper West; 9,400 barrels is going to be from Eagle Ford; 8,500 barrels is going to be from Kikeh, the workovers that I just talked about; 2,900 barrels is going to come from Azurite, we have another water-injection well to drill there and sidetrack of a producing well. We have about 2,900 barrels in the Gulf. As I mentioned in my remarks, we have approval for one permit. We think we might get two more before the end of the year -- one more at Front Runner and one at Thunder Hawk; 1,400 barrels is workovers at West Patricia; and then, 1,000 barrels is improvement at Schiehallion.

So, that gets you from the 188,000 member to the 230,000. And when you get to 230,000 at the end of the year, then that gets you the average of 200,000. And at the end of the year, just to round out my comments, Kikeh will be at 55,000 net, just about 87,000 gross, maybe a little bit more than that. And Azurite will be at 8,200 net, about 22,000 gross. So, that just kind of rounds out the gross numbers. So, I kind of gave you -- threw a lot of information at you, but I think it's important to kind of -- to get all those facts out there.

No, that's perfect. Thank you. Thank you very much for the comprehensive answer. The second one -- and I'll just keep a quick one here, did the Southern Alberta well, do you have any details you'd like to share on the IP rates or EORs you're seeing?

You know, Blake, not really, because we are still trying to lease. But I will tell you the -- and I've said this before, if we can get wells that are better than 200 barrels a day to start, then I would regard that as being good; and I would say that the first two wells would get into that -- get into that bucket.

What we need to do, we see some performance from those wells, from initial flow, and then put a pump on and see how they produce. But kind of the keys for me, looking at the play are, do we have water? Which we don't. And the second thing, to see what kind of pressure is in the play. And I think where water is, is going to be patchy. So, some parts of the geography's going to have water, and some not.

I think that's one risk factor. And the second one is, is some areas are going to have more overpressure than others. And so, you would expect better rates in some areas than others. So, I would say at this early stage, from what we've seen, it's encouraging. But it's not an Eagle Ford. I will say that.

Okay. Perfect, I will leave it there. Thank you.

Blake, thank you.

Let's go on to Evan Calio with Morgan Stanley.

Hey David, just to follow up on your Kikeh comments -- and thank you for those comments, I think you mentioned three wells shut in you currently. And I just wondered, was that incremental from last quarter? There was one well. And just further, all the data that you have collected in the process here, has that changed in any way, shape, or form your view on the productive capacity of Kikeh? And I have a follow-on.

Yes, let me kind of weave that and bring it all together. The shallow reservoir section is clearly not as compacted as the deeper reservoirs, which are performing well. And we drill these wells at quite a steep angle through them. And so, what we have experienced, and I think what we see here, is the fines material within that reservoir section does migrate if you don't stop it from getting into the well bore. Initially with our expandable screens, probably because they were packed off against that formation, they worked quite well. And we did not get any fines into the wells until later in life. One of the questions that we had was the encroachment of water, part and parcel of this fines migration, because in lots of cases, it is.

But as I mentioned in my comments, we have a couple of wells where we are getting fines where the water cuts are 2% and 4%. And so, we think it's more to do with the stability of the interface between the formation and the screen; and that's really where we are focused on.

And so, that takes us into, do we think that the wells and the reserves and the et cetera are going to be less than we thought. And the simple answer is, no, we don't. We have enough productive history here, and enough people looking at it both internally and externally, to feel very comfortable about the field.

In order to be more comfortable as to where the rate is going to go, we have to get this gravel pack technique working here in this particular reservoir. And then, coming back, we'll be able to tell you, hey, it's worked, and this is how it's worked, and better be able to judge what rates we are looking at. But exiting the year, close to 90,000 barrels a day, we feel pretty good about that, of course. And we think the techniques that we are going to apply will work, based on what we've seen so far.

Got it. Thank you, thanks for the answer. Can you also give us an update on your acreage position? Any update in the Eagle Ford or Alberta Bakken? I know you mentioned that you are looking to accumulate position, more acreage there. And kind of when you may be in a position on the Exshaw to share data with the street -- when do you expect that?

Yes, I think we need to run -- other than in answer to Blake's question, I'd rather not go any further there. I'd like to add some more acreage, but I would say I'm not so sure that I would add the acreage in the places that I was going to want to add the acreage prior to the well results. And really, that's the whole purpose of drilling these six wells, is to get comfortable as to what the risk factors are and where the trends are going. So, we have north of 150,000 acres now in that play, and I see us being able to add some more. But in light of well information that we have now and other wells that we are going to drill, it may change a little bit the direction of where we would pick up acreage.

In terms of the Eagle Ford, it's another one of these resource plays for us, where I like to add acreage all the time, produce all the time, and drill all the time, and keep getting smarter and smarter. The well results in Karnes are very good, and I'm very happy where we are. If I added up, just before this call, how much we can produce in Karnes, it's over 4,000 barrels a day net, but we're not producing that yet; and the issue there is takeaway capacity. And we, like lots of other people in the play, don't have the piping yet in place to be able to do that. But the well results, pretty nice. And so, I feel very bullish about that, and I think we are getting a better and better understanding.

We do have dedicated takeaway capacity lined up now. We do have 1.5 -- basically 1.5 frac crews dedicated to us. As I mentioned, we are ramping up our rig count this year, and I think that's very important for us to do that. And so, I think we'll get past this bottleneck, if you will, on the Eagle Ford and do pretty nice. And by the end of the year, producing 9,000 to 11,000 barrels, I think, is very, very doable. I think the well stock will be there; it will really be the issue of offtake, and we're working that hard.

And do you have any acreage update from the quarter?

We are in -- approaching 250,000-acre figure for Eagle Ford, I would kind of put it that way.

Great. Thank you. Thanks for taking my questions.

You bet. Thanks.

Moving on, let's go to Ray Deacon, Pritchard Capital Partners.

Hey, Ray.

Hey, David. I was just curious, where do you think you can get your -- I know it's very early in the Alberta Bakken, but is 3 million to 4 million a reasonable level for wells there, do you think?

For well cost? You know, the ones that we have been drilling now, we've had a lot of science, and we talked about this before. In cutting cores, drilling them straight and vertical, and then turning with a [heel tie]. That's not the most efficient way, but our guys have done a great job with the first couple of wells, and they've gone really, really well. So, I think if we lined this out, so we just drilled the well horizontal, straight into the [Bakken], I think well costs here should be quite attractive. So, yes, I see a good way forward there.

Okay. Great, great. And just curious -- so you have -- in the Eagle Ford, you have a dedicated frac crew. Is that going to cover kind of all your activity, or just Karnes, I guess? I was just curious about what kind of cost inflation you're seeing too.

Yes, I should say -- golly, I wish costs were lower, so I will say that now. But, yes, it's one dedicated crew and then, effectively, half of another crew. And we clearly need to get our production up, and we are having such good results there in the Karnes area, that having the crew stay there as long as we can and work off the backlog of wells -- I think we have nine left to frac in that area, is what we want to do. And we're active in the Tilden area and we're active in the Dimmit area. So, as we move these crews, it's less efficient; so I'd like to keep them in the same place, if possible.

Got it, got it. Great, thanks. And, I guess, just any big-picture thoughts on Canadian gas exports from the West Coast to Asia? Does that feel like it's getting to be more of a near-term thing?

You know, I've still struggled with the idea that we have $100 plus oil and $4 gas, just on a BTU basis, and then we see what prices for gas are going, indexed to oil on the Pacific market. So, I think export of gas from the US and Canada is -- makes a lot of sense. I think the issue up on the West Coast of Canada, as best that I can tell, is all about the permitting and regulatory part, and pipelining and all that stuff. But I think probably the business case is pretty solid. I think that there is probably a good case to be made for export of gas from the US side, particularly in the Gulf Coast. And I think another business case, a solid case, can be made there too. I think that if I was to look at where we are today, at $4 gas, we are probably going to move up; but I don't know when the time to move up. But I think export of gas is going to be a big part of that.

Great. Thank you.

Thanks.

(Operator Instructions) Let's move on to Kate Minyard with JPMorgan.

Hi, good afternoon.

Hi, Kate.

Hey, just a couple of quick questions. On the Eagle Ford, you have got 15 producing wells. Can you update us with either a total cost or an average cost per well across those 15?

Well, it varies quite a lot, because some of the wells were drilled differently. So, they were drilled with a science in mind, and some were drilled straight as kind of, let's see what we can drill them for and produce. But we're in the $3.5 million, $4 million drill, and $4 million, $5 million of frac complete number, Kate. I think those are probably pretty fair numbers.

Okay. And does the frac and complete include tie-in costs, or are those minimal?

Yes, those are minimal, but they're in that number.

Okay, great. And then, on the outlook to 2015, of the 300,000 barrels per day of production by 2015, how much of that is already sanctioned? And then, what portion of the non-sanctioned part might be dependent on exploration success?

Yes, we have through next week actually, in our analyst meeting here, ahead of our AGM, really going to focus in on that. Because, I think it's important for people to appreciate the resource and reserve base that we have. Of the 300,000 number, a very small percent -- so, 10% or less, is requiring any exploration success. The bulk of it is on projects we already have, we've have already discovered or are getting ready to sanction, or have acreage in resource plays here in the US and Canada that we feel very comfortable about.

So, the whole goal, in my view, and what I want people to come away from after next week, without stealing Roger Jenkins' thunder who runs that business, is pretty comfortable from going where we are to that number in 2015 -- and not relying on exploration to get us there, but have the option of exploration to add to that. And so, that's kind of where we are at.

Okay, great. And then, if I could just sneak a final one in. On the 14 stores that you've added year-to-date in the retail business, what was the cost to add those? And then, what's the kind of breakout between kiosks and more of the kind of full-fledged convenience stores? And I will leave it there, thanks.

It's a good question. I think the number is about $1.8 million on average. And if I'm shooting off the top of my head, which is dangerous here -- but the bulk of those were express sites or not kiosk sites. I think two or three were kiosks, and the rest were -- the rest were full-size.

Great.

Plus real estate on top of that, Kate, as well. That's the cost for the stores, and then, whatever the real estate is, it's on top of that.

Okay, great. Thanks very much.

Thank you.

A question now from The Benchmark Company, Mark Gilman.

A couple things. You have achieved some improved fiscal terms in the Congo, I wonder if you could give me some idea what that entails?

Well, Mark, looking at our fiscal terms, first of all, our threshold price changed dramatically. It was $26.50, was our index price. That has now gone to $48, so you should see a reduction of supplemental payments there, especially as we get into more of the profit phase versus the cost phase there. Also, our cost recovery threshold did change, as well. So, it should move our entitlement, which was for a 50% working interest in the low [30s], it will now move it up towards [40], with the new terms.

No change in profit splits, Mindy?

No, just a change in the cost recovery threshold. No change in the profit split.

Okay. And David, could you repeat what the exit rates are in Azurite, that you talked about? You were going a little too fast for me at that point.

Okay, Mark. Sorry, I didn't mean to speed, I figured you were writing it down as fast as I was saying it. Gross will be 22,000. We're currently at 14,500 today.

And the net?

Net, when we leave the year, it will be about 8,200 net.

Okay. David, let me go back to the Kikeh thing for just a second. It sounds to me, and forgive my lay interpretation and assessment, is that what we have here is unexpected, unconsolidated sands, which, I guess, from prior experience, does tend to lead to lower recovery factors. And so, I guess I'm a bit puzzled that in this instance, you don't believe that's true?

Mark, I don't know what your frame of reference there is. What I'm saying is that, well, this particular shallow reservoir, the migration of the fines into the well bore is causing us to choke them back -- not because we can't make high rates, and not because we don't think we can ultimately recover what we've got, it's the mechanical dealing with fine material up in our production equipment.

As I mentioned in my comments, two of these wells have water cuts, one less than 2% one 4%. So, it's very difficult for me to see that we are going to have a reduced ultimate recovery here. And what we first need to do is stop fines migration into the well bore, so that we can allow these wells to continue producing -- and they have been producing very well in the past. So, that's really the issue for us. I think it's -- in my mind, I wouldn't make the jump that you've made into reduced recovery at all.

Okay. David, is there a location yet established for the CA1 well in Brunei?

We are working with our partners there for CA1 and for CA2. And I don't think the final location has been approved by all partners for CA1 or CA2. We are talking on CA2 about bringing that well into this year, which I regard as being very positive; but they're kind of a work in progress for both, Mark.

Do you have any idea what relationship that CA1 well might bear to the Lepu discovery?

Mark, I don't know what the final location is, so I can't make any comment about geography on it.

Okay. Just one final one for me. I was just looking at the Sarawak Gas price realizations, and had been under the impression, David, that the fiscal arrangement on the gas there was something akin to a net back. Yet, in spite of rising prices, for the Japan crude cocktail better part of the last year and a half, the price -- your realization seems to have peaked out in the [$550], [$570] kind of range. Can you help me understand that?

The way that the formula works, without going into great details here, is that based on what is realized from the LNG export, we receive a factor of that realized price. And so, a lot of it will depend on the types of contracts, the types of prices received, some of which include [spot] cargoes. But it is tied to what is actually received. Multiplied by a factor, that's what we --

So, there were no changes whatsoever in the formula or the mechanism?

No, sir.

Okay, folks. Thanks very much.

Mark, thank you.

With no further questions in the queue, I would like to turn the conference back over to the Company for any additional or closing remarks.

Operator, thanks a lot. I appreciate everybody being on the call today. Those of you that are coming to El Dorado here next week, we look forward to receiving you. And if you don't come, we look forward to talking to you again with next quarter's results. Thanks a lot, and have a good day. Thank you, Operator.

Thank you, this does conclude our audio conference for today. We appreciate your participation. Have a great day.