Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2013 Earnings Conference Call. Today's conference is being recorded. I would now like to turn the call over to Mr. Roger Jenkins, President and Chief Executive Officer. Please go ahead, sir.

Thank you, operator, and good afternoon, everyone, and thank you for joining us on our call today. With me, as usual, is Kevin Fitzgerald, Executive Vice President and Chief Financial Officer; John Eckart, Senior Vice President and Controller; and Barry Jeffery, Vice President of Investor Relations here at Murphy, and will now make his customary comments.

Thanks, Roger, and welcome, everyone. Today's call will follow our usual format. Kevin will begin by providing a review of fourth quarter 2013 results. Roger will then follow up 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 2012 Annual Report on Form 10-K filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I'll now turn the call over to Kevin.

Thanks, Barry. Beginning in the fourth quarter of 2013, our U.K. refining and marketing operations are presented as discontinued operations. So for the full year of 2013, discontinued operations include our U.K. E&P properties, which were sold earlier in the year; our U.S. retail and related operations that was spun off to shareholders at the end of August; and all of the U.K. downstream operations. Net income from continuing operations, which is basically our remaining E&P property for the fourth quarter of '13 is $180.5 million or $0.96 per diluted share. This compares to net income from continuing ops in the fourth quarter of '12 of $123.9 million or $0.64 per diluted share. For the full year of 2013, net income from continuing ops is $888.1 million or $4.69 per diluted share compared to net income from continuing ops in 2012 of $806.5 million or $4.14 per diluted share. The fourth quarter and full year results from continuing operations for 2013 included $133.5 million of income tax benefits related to foreign oil and gas investments compared to $108.3 million of such benefits for the fourth quarter and full year of 2012. Fourth quarter full year results from continuing operations for 2013 also included charges of $82.5 million associated with abandonment and exit activities with the Azurite field in Republic of the Congo, while the 2012 fourth quarter and full year numbers included impairment charges of $200 million associated with the write-down of the carrying value of the Azurite. There was no income tax effect related to these charges within the year. Looking at total net income for the fourth quarter of '13, a $75.4 million or $0.40 per diluted share compared to net income in the fourth quarter of 2012 of $158.7 million or $0.82 per diluted share. Net income…

Thank you, Kevin. 2013 was a good year for our shareholders here. Spin-off of Murphy USA was completed in the third quarter and was a seamless transition for the 2 entities. We've made good progress in our $1 billion share repurchase program, which has slowed a bit due to the timing of the spin, with $750 million now completed as Kevin mentioned. We exceeded production targets for the year even when adjusting for the delay in the Kikeh shut-in for field development work, downtime at the non-operated Kikeh-associated gas plant and weather delays in Eagle Ford Shale. Our strategy of building a reliable, predictable onshore business that complements our offshore business has greatly improved our ability to meet quarterly and yearly goals. 2013 represented our highest production level in our company's history, breaking the 200,000 barrel oil equivalent per day mark, with our best year ever in reserve replacement, with over 240% on an organic basis. We set the stage for 2014 production growth with the startup of 4 shallow water oilfield developments in Sarawak, Malaysia and we're progressing startup on 2 deepwater fields there as well and 1 in the Gulf of Mexico. We also restructured our exploration business under a new leadership team to position ourselves for future success. From a financial prospective, 2013 was the second most profitable year ever for upstream operations, with only the high oil price year of 2008 taking precedence. We're continuing to progress our U.K. downstream sale effort. We have reported this business as discontinued ops, as Kevin mentioned in his remarks. This will also allow our shareholders to view our E&P business as a whole for 2014 and take a look at our 2013 business as an E&P entity. In the fourth quarter, as prices in major fields, Malaysia oil netbacks…

[Operator Instructions] And we'll go first to Leo Mariani of RBC.

Just a quick question here. In terms of your Montney gas, you guys talked about a couple of rigs. Would you expect Canada gas to grow in 2014?

I'll let Barry give you the guidance here, Leo. Good to hear from you. We're going to be drilling a couple of rigs there. We think we're on to a new completion technique, but we're kind of moving some Eagle Ford completion techniques up there, and as we work that team as to -- under one management system. We're pretty close to cash flow CapEx parity for that individual business, about $180 million spend and about a -- near that in cash coming the other way with the $4 Hub that we have organized back to AECO. So, Barry, why don't you give the guidance?

Yes. So, Leo in '13, Montney gas was within the 170 million cubic feet a day range. And in '14, it's probably going to be just below 145, in that kind of area.

So regarding our production, Leo, in our business, it is oil-weighted, so we are declining in Montney.

Got you. Okay, and that's helpful. I guess on your downstream business, you guys decided to put it in discontinued ops. This quarter you talked about sort of being able to view 2013 more as a standalone E&P. Is there anything else we should be reading into that in terms of -- I'm not an accountant but in terms of accounting rules, does this mean that sales are more certain or anything like that? At this point, given the discontinued ops treatment, can you give us any more color on that?

No, I mean it's been a long time and we do want 2 things. We want to be out of that business, like I said in my remarks, are addressing the sale of it. There are numerous accounting things you could read into that, Leo, if you'd like. But one thing for sure is I'm impatient and want to sell it, I can tell you that. And we're working hard to do that. And I think it's equally important to be able to explain our company as a standalone because that's our ultimate goal.

I guess question on OpEx here. Within your U.S. OpEx, I think it was up about $3.50 this quarter from the third quarter. And also just seeing your Malaysia OpEx, climbed as well the past couple of quarters. Can you kind of give us some more color on that and kind of how we should be thinking about OpEx for 2014?

We had a pretty rough -- one of our first rough quarters in Eagle Ford. Our production didn't grow for the first time, I guess, ever. Had some severe flooding and cold temperatures happening, but other peers were affected by that as well. So naturally with our volumes down, our OpEx have to go up. We did have a good bit of production but very much coming out of the wells, we had very close to the year end. We had a true-up of some ad valorem and severance taxes there, that's about high for that because they would have had normal ad valorem and severance. We still may need to look at how we report things, Leo. Are a old, historic company. We're not breaking out LOE, we have that -- those taxes [ph] in there and have to true that up. I think it doesn't truly reflect the team's work there on LOE. So those are the issues around that, lower production and some catch-up with some taxes. Over in Malaysia, while we're still trying -- we want to be a onshore complementary business with an offshore business, but we're still plagued that we have one of the Kikeh spin on a well that's classified as operating expenses. That's still real money for us and swings our OpEx. So that was a single well. We have a lot of capital in Kikeh to finish the development and work on the field. And on occasion, we have a well that we have to work on that's classified as OpEx. In this particular well, we changed some tubing out with erosion, problems with completion that took extra time. And that becomes an expensive well for us and drives up our OpEx on a kind of a one-off quarterly basis.

Okay, that's helpful. I guess just looking at your oil prices. You talked a little about this, but I guess your Syncrude price was down quite a bit this quarter relative to Brent in 4Q, and also just noticing that your U.S. gas pricing kind of also weakened a little bit relative to Henry Hub. Can you kind of give us any sort of color around that? And what we should expect sort of going forward?

You're right, Syncrude was very low in the fourth quarter. We have around [indiscernible], so we think it'll be higher than that this quarter, as it's -- more of this is Enbridge pullback of prices there -- pullback of available pipeline and infrastructure issues around Canada. We saw that -- it's really tied more to WTI differential lower than it is Brent. Our East Coast Canada will be more Brent based. On the gas side, we're continuing to grow our gas in Eagle Ford Shale. Our Eagle Ford Shale gas though is tied back to a Port of Houston type price. So we don't -- we always have a slight dip below Henry Hub there any way because most of our gas probably in Eagle Ford, a very similar amount to the Gulf. The Eagle Ford is growing. And I think that would be the answer to those couple of questions there.

All right. I guess with respect to the Eagle Ford, do you guys produce significant condensate there? Can you give us any kind of breakdown on sort of oil versus condensate production on Eagle Ford?

I'll let Barry, the one who gives me my standard breakdown. It's not been -- and the reason I'm making these comments, I think, I've made them a couple of quarters in a row, we continue to struggle with write-ups on U.S. oil price realization. And we just, to this point, like I say, we still have some further work or consideration to do as we become a pure E&P company on things like LOE. We just haven't ever broke out the NGLs. I don't want to say they're material because they're growing in the Eagle Ford Shale and they're much below, much below oil prices. So that's what changes our U.S. price realization because we do not fleet a line for NGL. And we are very proud of our API crudes that we have in Eagle Ford where we're not a condensate player. We just have, I didn't say I was smart enough to lease oil acreage or anything like that, but we are an oil player in the Eagle Ford with very little condensate, quite prideful of our API average. And I'll let Barry give you the exact split out there.

Leo, we're about 92% liquids, I'd say roughly 7% NGLs. And as Roger said, condensate is really not an issue. We actually have fairly decent API quality, so we're getting a good oil price.

Our next question will come from Guy Baber of Simmons & Company. Guy A. Baber - Simmons & Company International, Research Division: I wanted to start off back at on the production cost front, and thanks for the color on 4Q. As you're setting the expectations for 1Q and you have some of the guidance out there, is there anything that should be one-time or is there anything that you're looking at that could influence the cost as we think about 1Q? I know you had the fire in Malaysia. I'm not sure if that would have an impact or not. You have some similar activity going on in Malaysia. So just trying to get a sense of, if there's any near-term risk to OpEx and just how we should think about that.

I am hopeful that OpEx will be down in the first quarter. And I do not know of any of those one-off -- we don't have a workover at Kikeh, which is a big deal. And we are growing production in Eagle Ford and a new well in the West [ph]. And I do not see that as -- I just don't see that as an ongoing change in operating cost there, Gary. I mean, Guy. Guy A. Baber - Simmons & Company International, Research Division: Okay, all right. That's helpful. And then I was hoping you could just talk a little bit more about the 2014 capital budget of $3.8 billion. Just can you talk about some of the moving parts? I know you have some major projects that you're winding down. Are you offsetting some of that with more capital getting allocated in Eagle Ford? But can you just talk about some of the moving parts? And then how you're thinking about capital allocation in the Eagle Ford, specifically how that's changed? And how should we think about that going through 2014?

I don't think it's changed a whole lot. I mean, I really think in Eagle Ford, for me you have to be a first-class player and we are still a company with both an onshore and an offshore business, and we want to maintain our deepwater skill sets and our deepwater self mobility [ph]. We think that's a better advantage for us. So we're picking through levels of rigs and all with what we think we can operate very, very well and we're doing a very good job at that. If you look at total Eagle Ford Shale this year, about 1.5 billion to 1.6 billion in all of the U.S. Last year it was 1.6 billion. Eagle Ford Shale this year probably a little bit less, 1.3 versus 1.4 as we build the new [ph] facility this year. So that's really probably not changing. We want to -- we have a strategy of being an exploration-driven company, we're going to remain that. We're going to have a $500 million-plus spend every year on exploration. It's not all for wells, but seismic and acreage, et cetera. So when you take the exploration, material enough to make a difference, and you take your Eagle Ford Shale, and you take your other project that you've sanctioned, we're trying to be pretty close to CapEx cash flow parity in the Montney and in Seal because those are not high net income providers, but companies would have long-term aspirations there. And it ends up what's left is what's needed in Malaysia, and our overall look at cash flow CapEx parities letting that be the driver of our capital allocation, God forbid. That cannot exceed in cash flow and baking that discipline and not getting our debt in par, and continuing with our repurchase if we can afford to do so without breaking debt, et cetera. And that's kind of my thoughts around the budget, if that answers your question. Guy A. Baber - Simmons & Company International, Research Division: Yes, it definitely does. And then I just had one more modeling one, probably for Barry. But you guys had an underlift, pretty sizable underlift scheduled for -- or planned for 1Q I guess within the guidance. Is that in Malaysia or anywhere else? Can you just tell us where that would be?

That will be in Malaysia, Guy.

Our next question will come from Evan Calio of Morgan Stanley.

Yes, you guys have a lot of projects coming online in 2014, and to get your full year 2014 average guidance following the first quarter guided number. Should we expect all 3 of those offshore projects, both Malaysia and Dalmatian, online at full production levels in 2Q? I mean, can you help me with some of the ramp there on the offshore side?

I'll just talk to the color and Barry will help with that a bit, with the ramp here. We're -- in Dalmatian, we have the wells previously drilled and we've completed one, where we'll have gas come on in March. The gas will flow and the oil will flow later, probably at early May. We're very, very happy about how Kikeh is going. Of course, it's been very delayed and not what we wanted it to be because we have to shut in at Kikeh and explain that as to our guidance over and over. So we're doing that now. And so we're in the middle of as we speak and it's no small feat to install these big risers in that Kikeh turf. So we have that behind us. We feel very good about that starting. That's in control. So Siakap North should start as we said in March. Dalmatian will operate in that and the middle of it should start, as I said. Now the 4 fields in Malaysia are doing very well at shallow water, ahead of plan, covering some of these other issues we've had at Kikeh, et cetera. So that's all in pretty good shape. And we have big Kakap, which is nonoperated, big field. But not super material for us but important. We have that starting in March, and we believe we risk the startup of that and how we would like to do that in our system. But it could go from March a couple of months late. That could happen, I believe. I'm certain we'll be able to stay in guidance levels that we provided with that lateness. We've modeled that. That's kind of a rundown of those projects. If you want any more specifics, I'll let Barry get into that for you.

Yes, I mean, Evan, without getting very specific into other quarters that we're not ready to do, second quarters we're showing a pretty big jump, certainly in that 30 to 40 range. At this time, it's back on or starting to come on. And then for the second half of the year, it's kind of getting another jump by roughly 10, maybe another 5-ish getting into the fourth quarter. So you see how I'm keeping slamming [ph] up to there.

Great. And what's -- do you have an exit rate on 2014? The average...

I don't know. But that's going to get you awfully close to that 2 55 range, 2 50-plus range.

Okay. On the -- on Block H FLNG, the sanction. Where is the project in FEED? And when do you expect to -- when would you need FID, I guess, in order to hit that 2018 start-up time frame?

We have all that. We have full FID. We have that mostly here this week. Petronas has a special board meeting. They have -- Petronas is building the ship with a group, Korea. That's their CapEx. We are timing for their ship. Every -- all systems go there fully on to flow in '18.

Okay. So you just had a toll on that. Is that how it works with the...

We're going to sell them gas. We sell gas to Petronas today. Petronas is one of the leading LNG players in the world. We sell them gas every day at SK at a factor of an oil link to Japanese crude cocktail price. We've made that agreement with them and we're going to sell to them that and move forward.

Great. On -- there's a follow-up on the downstream. If there wasn't a buyer for Milford Haven, what's the mark on the release of working capital in the closure? And is there -- are there any charges or how would I think about that down scenario?

I'll let Kevin answer that. I don't believe anything has changed in the bring home scenario there. Let's let Kevin...

What we've talked about all along is we should have -- once the sale gets completed, in the neighborhood of $600 million to bring back. That's what we're still modeling. And when we bring back that money from the U.K, naturally there's some potential tax implications, so we'll look at what our foreign tax credits are and the like and try to maximize tax positions as far as moving some money around in other parts of the world. And hopefully, there's some damage charge that we took in the fourth quarter. Hopefully, that's it, or certainly a majority of it, but until the deal gets closed and we get final numbers, final inventory item, all of that nature, there's always could be some movement in that number, hope we don't get below that number.

Great. Just lastly for me on Cameroon. You mentioned a February spud, days to drill, when should we expect results on that one? Is it a bigger well FEED?

We're on -- it's going to be about a 50- to 70-day well. But it's in our control, we operate, we're picking up the rig from Diamond Offshore and the shipyard with them -- are coming from another operator, rather, I'm sorry. When's the next call? I think it could be close for the next call that we make. So, so pleasurable for me. I can't wait for the next one, really, I don't know the date. It's so great.

We will go on next to Roger Read of Wells Fargo.

Well, I guess the question I'd love to ask is your quarterly production numbers, but I understand you don't want to give those just yet. But maybe another thing to focus on here, as we walk through what needs to happen as you exit Q1 and then enter Q2, what are the particular projects again if you could just where you're the operator or where you're not the operator, so we can kind of know what to look at over the next say 4 to 6 months more closely?

Well, Roger, I mean, it's -- no, we're always into this. When you're the leading growing oil provider in the space, you always have to drill oil all the time. That's what we've been doing for a long time, and we're very, very proud of it. I think first step we always have to grow in Eagle Ford coast. We're a big Eagle Ford player, more heavily pulled back in the fourth quarter. We think we're in good shape for the guidance in this quarter. So to me, one of the things you look at there is we -- how much we're increasing production there. So how much we're increasing production first is how many wells we're adding. If you look at that ratio, we feel we're in good shape, we're in control of that destiny there. So that's a big part of it. Let me get my production sheet here. And then -- so we have always the Eagle Ford Shale growth feed. We then have the projects in Sarawak Oil and that would be almost a full year of those projects producing well and they're all online, which is no small feat, it's 4 platforms we set, we drilled wells, we have had very good results. So the Eagle Ford Shale, we have the Sarawak Oil project starting, we have the Kikeh shut-in now ongoing and not have to be concerned with that anymore. We have the risers picked up for Siakap North-Petai and we operate that, that's a third piece of the growth. The only part we're not operating is the Kakap piece, and which I spoke over a few minutes ago. We have in March. We feel we've risked that appropriately in what we have in our guidance and the lateness of that by 2 months. We should be able to handle in the range we have today. And the full on year of Sarawak and the continued predictable growth year-on-year of Eagle Ford with the number of wells we plan to drill and the CapEx we have for the rigs should get us where we need to go, and plus the promotion from here, forgot about Dalmatian, that's a project that is drilled and we have the technique held up for weather in the Gulf. And handed over very quickly, where we're completing the wells. So it’s a lot of new production coming online now, Roger.

Oh, no, we're well aware it's a lot, just want to make sure it actually -- it gets there.

Roger, I can assure you. I'm worried about it more than you.

All right. I don't doubt that. And then as you look for growth beyond '14, obviously, some of the exploration wells in '13 didn't turn out as good as hoped. There's been talk in the last couple of months -- last couple of quarters, you might be a little more interested in acquisitions. You mentioned earlier, cash flow measuring up or matching up fairly well with CapEx. If you were to start looking at acquisitions, what should we think about maybe in terms of size, scale you'd be comfortable with at this particular point, given the balance sheet and assuming a reasonable resolution to the U.K. downstream?

Well, it's just kind of a misnomer about Murphy that we just fall off the face of the earth after a couple of years because of exploration. I mentioned earlier today, we have very, very high reserve replacement. We have a big running room left in the Eagle Ford. All these Pearsalls and Budas and steam up in Canada. These are all 20 million, 30 million barrels a piece. While we've been very unhappy with the deepwater exploration, we made a lot of changes to personnel. We're still a company that's growing production and you know well out into '16. And I'm not going to ever guide because people will beat me up if I'm still alive in 2018, we're in bad peril here. But now look at this, we're just maintaining production of a very tight band all the way through '18, '19, even if we don't have any exploration success at all in the ocean. And after routing any of these projects that I just mentioned. So with that said, we do look at M&A more than we probably ever have. We have a full set of people looking in the Permian today. I don't ever see us doing a stock deal or a big super major purchase or anything like that. We do have to get our cash flow CapEx parity always maintained. We have to get the Milford Haven U.K. issue behind us, before we looked at doing that. We have been focusing on North America and onshore, but I'm looking at things that could help all of the P, not get me way out of kilter on cash flow CapEx, meaning we could have some level of proven reserves and production. And those things are expensive and regardless of all that, Roger, we need to make return for our shareholders. And if we can do things to help our company, help our metrics and have return, we'll be looking to do it, and we're looking at it now. But it's not that simple to prove yourself and have -- I'm not interested in NPV, [indiscernible] a purchase to be quite honest. So the fact, looking a little bit in offshore globally in the Gulf at the end of '12 and those are really not what I originally wanted because they have a higher decline in the onshore. But that's the story on that, if that answers your question.

And next we'll go to Pavel Molchanov of Raymond James. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Similar question to the last one, but more on the exploration side. So appreciate the color on Bamboo and Titan. And then beyond those 2 prospects, can you help us with the sequencing on maybe what's spudding in kind of Q2 and in the second half?

What's going to happen there is we have our rig at Dalmatian today, completed 1 well and have another 1 to go each [indiscernible] not known significant completion. We're going to take that rig to Titan and operate and drill that well ourselves. We have finished our work in Brunei for the year. And we have 2 pretty high risk but properly partnered, big gas prospects in Brunei and Indonesia. Those start in March. Rig is lined up to go there in March with those 2 wells back-to-back in Indonesia, finished in Brunei. We would like to drill in Perth basin very late this year. It's probably not going to make it. A nice well to drill in Vietnam with our partner, Santos, in the midyear. And we'll definitely have the rig lined up and frac-ed and towed to the NTEM well, Bamboo-1 now, and we -- back in the Gulf we originally started to. So Dalmatian, Titan and then we are looking at about 3 different Gulf of Mexico opportunities now. Would not like to name those specifically at this point but probably finishing off the year at the Gulf. I'm a little short on wells. I always say I'd like to drill 10, but I really want to drill all things happened with rig [indiscernible], around the world. We're probably looking at 7 now. But we have the CapEx and the ability to drill 10. So now would look at some other opportunities, both in the Gulf and globally [indiscernible]. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Okay. Any activity in Kurdistan this year?

No. We have exited those blocks and are no longer playing in Kurdistan. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: No more Kurdistan, okay. I was asking because it's still on the website. So okay, understood. And what percentage are you...

And I will and this is a -- we still have our name on the door there, and we're in the process of exiting and that's probably why it's still on. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Got it, clear enough. What percentage of the total $3.8 billion is allocated to exploration this year?

I think I had it in my remarks, it's $595 million of exploration and $295 million of the $595 million is for wells, and the rest would be at least [indiscernible] in the Gulf and seismic. Exploration expenditure is around the floor.

And at this time, we have one question in queue [Operator Instructions] We'll go next to Rakesh Advani of Credit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: It's Ed Westlake. I guess just on the -- keeping on the exploration theme, I mean, in terms of getting access to acreage, I mean, obviously, you're drilling at a substantial chunk of the CapEx this year, which is good. But can you talk through the general thought process about increasing the pipeline of acreage that you can then drill down the road so that you can hit those kind of 8 to 10 wells year-over-year that you'd like to do?

Well I don't think it's really insignificant to drill 7, if it's 7 good ones. I think if you take Murphy and benchmark Murphy on an acreage basis per BOE, per reserves, per production, almost any metric we would be the leader in an acreage basis. So we have enormous acreage position per basin with just new 3D seismic in, very excited about being able to drill there. Nice acquisition in Vietnam, I mentioned earlier that we have many multiple wells to drill and a very, very nice acreage position in Southern Australia where we're surrounded by BP and Statoil, and Chevron now, and puts us in a very good situation. Gulf of Mexico, we have 7 to 8 of these prospects in the Norphlet left to go, plus all of our Miocene older acreage there. We feel we have a nice set of prospects there. In Cameroon, we have many prospects here but really depends on the success here and building a nice position Equatorial Guinea with seismic. So we probably are in pretty good shape for '14 and '15, but it's an ever running business to keep that going. That's why you have the $500-plus million CapEx and over half of it for drilling and the other half has to be for seismic and continuation of that effort. And if you are inconsistent on that spend, [indiscernible] the year where you have 3 or 4 wells, which is a lot different than 7 to 10, and that's where the problems arise and that's what we're trying to avoid. Edward Westlake - Crédit Suisse AG, Research Division: Yes, in the Australian acreage, I mean, obviously, a frontier but potentially interesting as you say with the majors there. When do you reckon you'll have done enough -- I mean how long -- will it be 2 years of seismic and...

Well, in the first basin, we're definitely going to drill the wells. We're going to drill 3 wells there and we have a rig contract in San Juan do so and it's going to be right at the end of '14. So we're going to do that and we're very pleased with what we're seeing in the seismic there. And this is not superexpensive frontier from a weather perspective. The Southern rate bite or the offshore Southern Australia severe weather will be very similar to what the Chevron would be in the U.K. That will be something where we're fortunate and happy about our commitment to the Block of seismic only. And we have other people that will be drilling, as it says in my remarks, who will be drilling ahead of us. And we'll be able to have the seismic follow-up their drilling and de-risk there. And I think puts us in a real good position for a company of our size. We also have a partner there. So that's the comments on the Australian side. Edward Westlake - Crédit Suisse AG, Research Division: Thanks for bringing me back to the U.K. Just final question just switching back to the North American Shale, the Eagle Ford. I mean, just run through if you had to look at the year, what were the major excitements? Was it Pearsall, Buda, down spacing some very lower acreages, was it just improvements and recoveries or busts or...

All of those. Everything you said. Plus, if I look back at our team this year in Eagle Ford, look at Eagle Ford Shale OpEx of startup quarter 1 at $22.62 and everybody's screaming about it, but we ended up to fourth quarter at 17, actually had a 13 in the third quarter. So increasing OpEx there and improving OpEx metrics is big, putting in the facilities there, getting a real fine-tuned machine that's drilling some great rigs and has gone very, very well for us. Has a very large reserve booking there, about 85 million barrels, which took care of our entire company. We have 2 feeds there probably in the 275 million range, and we think that could go to 600 million now versus becoming a real go-to legacy field, the biggest field in the company's history and proving drilling, significant reserve booking, improving the OpEx, cost improving continues there. Like the other players, I'm proud of the fact that while we're not a shale scale, a big player some would say, we are able to drill, produce and improve like our peers around us. And just overall pleased with that whole effort. Edward Westlake - Crédit Suisse AG, Research Division: And just a final reminder on that 600 million barrels, what spacing would you assume for that?

There's a slide in our decks that talks about walking your way up from the different spacings. And I think I'd rather refer you to that.

And at this time, it appears we have no further questions in queue. I'd like to turn the conference back over to our speakers for any additional or closing comments.

That's all we have today. We appreciate everyone's time dialing in for our call, and we'll look forward to seeing you next time. Thank you.

And with that, ladies and gentlemen, that does conclude today's conference call. We'd like to thank you again for your participation.