Murphy Oil Corp (MUR) 2013 Q3 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation third-quarter 2013 earnings conference call. Today's conference is being recorded. At this time I'd like to turn the conference over to Mr. Roger Jenkins, 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 as usual is Kevin Fitzgerald, Executive Vice President and Chief Financial Officer; John Eckart, our Senior Vice President and Controller; Barry Jeffery, VP Investor Relations. And I will turn it over to Barry for his customary comments.

Thanks, Roger. Today's call will follow our usual format. Kevin will begin providing a review of third-quarter 2013 results; Roger 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 exists that may cause actual results to differ. For a 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 will now turn the call over to Kevin.

Well, thanks, Barry. Net income for the third quarter of 2013 was $284.8 million, or $1.51 per diluted share, compared to net income in the third quarter of 2012, $226.7 million or $1.16 per diluted share. For the nine months of 2013 we had net income of $1.05 billion or $5.51 per diluted share and that compares with net income for the first nine month of 2012 of $812.2 million or $4.17 per diluted share.

This year's third quarter included income from discontinued operations of $32.7 million or $0.17 per diluted share compared to income of $15 million or $0.08 per diluted share for the same period last year. For the nine-month period 2013 included income from discontinued operations of $363.1 million or $1.91 per diluted share, compared to income of $93.9 million or $0.48 per diluted share in 2012.

The increases in the 2013 income for discontinued operations included gains on the sales of all E&P properties in the UK plus earnings through August from the US downstream operations which of course was spun off to shareholders at that time.

So looking at income from continuing ops, in the third quarter of 2013 the income of $252.1 million or $1.34 per diluted share compared to income in the third quarter of 2012 of $211.7 million or $1.08 per diluted share. From continuing operations for the first nine months of 2013 net income of $684.9 million or $3.60 per diluted share compared to net income for the first nine months of 2012 of $718.3 million or $3.69 per diluted share. Improved results from continuing operations in the third quarter of 2013 as compared to 2012 is mostly attributable to higher crude oil production levels.

Looking at income by segment, in the E&P segment from continuing operations for the third quarter of 2013 net income of $264.2 million as compared to income from continuing ops from the E&P segment of $221.1 million in the third quarter of last year. Higher E&P earnings for the 2013 quarter were primarily attributable to the higher oil sales volumes, particularly in the Eagle Ford shale area of South Texas, partially offset by higher exploration expenses and higher DD&A and production expenses associated with the higher sales volumes.

Crude oil and gas liquids production for the current quarter was approximately 138,100 barrels per day compared to approximately 105,800 barrels per day in the corresponding 2012 quarter, again with the increase mostly attributable to higher production in the Eagle Ford.

Natural gas sales volumes averaged 415 million cubic feet per day in the third quarter of this year compared to 454 million cubic feet per day in the third quarter of 2012. The decrease was attributable to lower volume in the Tupper area in British Columbia as normal well decline occurred following voluntary deferral of development activity due to depressed natural gas prices, and in the Kikeh field offshore Malaysia which was due to maintenance at the third party onshore receiving facility.

Now UK downstream, in the third quarter of 2013 we had a net charge of $12.9 million compared to net income of $25.5 million in the third quarter of last year. The decrease in the 2013 quarter was mostly attributable to significantly weaker results at the Milford Haven refinery.

In the corporate segment the third quarter of 2013 had net income of $800,000 compared to a net charge in the third quarter of last year of $34.9 million. This favorable variance primarily related to after-tax gains from foreign currency transactions compared to losses on those transactions in the prior year.

As of September 30, 2013 Murphy's long-term debt amounted to just under $2.6 billion or approximately 22.5% of total capital employed. This figure includes approximately $339 million associated with the capital lease and production equipment for the Kakap field offshore Malaysia. Excluding this lease long-term debt to total capital employed at June 30 would be approximately -- by September 30 would be approximately 20.1%. And with that I will turn it over to Roger.

Thanks, Kevin. As Kevin pointed out in his remarks, on August 30, Murphy Oil Corp. completed the spin of Murphy USA as a single stand-alone entity. Murphy USA will report their financial results for the third quarter separately on November 6. The financial results of the US downstream business for the first two months of the third quarter to Murphy Oil Corp. have been reported as discontinued ops in this third-quarter release. The sales process for our UK downstream business continues and we're actively progressing the divestiture of those assets.

The Milford Haven refinery continues with safe reliable operations in a difficult market. The UK marketing business continues to contribute solid results for the quarter and delivered one of its best months on record in September.

Looking at the upstream market, we continued with strong oil pricing for our quarter three with our Malaysia oil net backs averaging just over $91 per barrel for Kikeh and near $100 per barrel for SK oil post all supplemental payments. Are SK gas averaged approximately $6.70 per MCF and Eagle Ford shale oil sold at $105 per barrel for the quarter. In offshore Gulf of Mexico we had a Brent supported price of nearly $1.07 as well as continued firm prices in the East Coast of Canada which is sold at near $114 per barrel. Our Seal crude had a strong net back price of $68 per barrel and Montney gas was priced in at $2.81 per MCF both including impacts of hedges in place.

In the United States NGL volumes were approximately 4,000 barrels per day at an average price in the mid-28 level which is included in our reported and realized US crude prices and volumes.

In exploration, in our global offshore exploration program we continue to maintain focus in four areas -- Australia, Southeast Asia, the Atlantic margin and the Deepwater Gulf. In Australia in the Browse Basin our partnership group is drilling a Dufresne-1 well where we hole a 20% working interest. This is a large closure in the Jurassic with a predrilled mean gross estimate of 2 TCF where our net mean resource would be near 70 million equivalent for Murphy. We anticipate results on this well in the fourth quarter.

We've recently been informed that our work program bid has been accepted for Frontier exploration block, S12-1 in the Ceduna Basin offshore Southern Australia where we will operate and are partnering 50-50 with Santos. This is a large block covering approximately 17,000 square kilometers and is a six-year permit with a commitment for 2-D and 3-D seismic. We feel we are very fortunate to obtain this block in a competitive environment in an underexplored basin.

In Southeast Asia our partnership group in Brunei plans to drill two prospects offsetting the Kelidang discovery we had earlier this year starting in the fourth quarter with results expected in quarter one of next year. Final spud timing will be dependent on rig availability.

In Vietnam we continue to build our acreage position with the addition of a farm-in to block 13-3 at 20% working interest to go along with our previously signed lock 11-2 at 60% working interest both in the shallow water area. The 13-03 block test will be drilled in 2014 and we finished shooting seismic on block 11-2 and continue to review seismic for possible drilling in early 2015. We're in the planning stages for a seismic shoot in the deepwater blocks 144 and 145 for next year.

In the Atlantic margin we plan to drill our second deepwater well in Cameroon in the MPN block in the first quarter of next year when our rig is scheduled to return post a planned shipyard rig inspection. The pre-drill estimate for this well is in the range of 600 million barrels gross.

In offshore Equatorial Guinea in Block W we plan to be shooting 3-D seismic starting late this year with our partnership group.

In Surinam on Block 48 we are concluding our farm-out process at 50% working interest. We've completed the planned seismic shoot and we began processing and evaluating data which will lead to drilling a well in 2015.

In the Gulf of Mexico the Jurassic Norfolk play continues to be a focus for us. Our partner Marathon is currently drilling in Madagascar well in Block De Soto Canyon 757 where we are farmed-in at 30% working interest. We should have results of the well early in the new year. We are planning to spud our Murphy operated [Titan Norfolk] prospect located in De Soto Canyon 178 in quarter one of next year.

The well will be drilled with our new long-term contracted rig, the Transocean Discover Deep Seas, when it completes steel development work at Dalmatian. The rig is expected to begin those development operations in late November. Both Madagascar and Titan have a gross mean resource in the 150 million to 200 million barrel range and are well-positioned in this new, exciting Gulf of Mexico play.

I will now take a look at our offshore operations around the world. In Malaysia our Deepwater project, Siakap North Petai has a planned December 1 flow date -- first oil date rather. As previously announced the planned shut-in at the Kikeh FPSO to tie in the Siakap North Petai risers is scheduled for late November and early December.

Siakap North Petai consist of eight producers and five water injection wells. Two of the producers and one water injection have been completed. We anticipate that three production wells will be online at first oil. Drilling and completion results to date, both from a subsurface and cost perspective, are ahead of plan.

We have progressed the field tie-in work with all manifolds and water injection pipelines in place and the control umbilical has been installed and connected to the Kikeh FPSO. All that remains is the installation of the dual production flow lines and risers. The vessel to lay this production flow line has loaded the pipe and is in transit to the field with a planned arrival early next week.

The Kakap-Gumusut early production system is producing a plan through the Murphy operated Kikeh FPSO. The non-operated full field development is progressing with the permanent floating production system moored on location and the production riser installation is complete. The operator is now targeting start-up of the main field in the first quarter of next year.

We continue to progress all of our shallow water Sarawak oil developments, Serendah continues to produce above plan since its start-up in late June, South (inaudible) completed final hookup and commissioning and achieved first oil on October 29. Patricia and [Permoss] will be the next two fields to start up in November and December respectively.

All of the wells for first oil in these two remaining fields have been previously drilled and completed. These four fields are major contributors to our 2014 production growth and I'm pleased with our KL teams' execution on these projects.

Sarawak gas production continues to be a steady performer with production averaging near 175 million a day net for quarter three. We continue to ensure security of supply in our long-term Sarawak gas business with the recent start-up of the [Marapu] gas field and tie-in of associated gas from oil developments along with the ongoing installation of additional gas compression equipment at our onshore receiving facility.

We continue progress (inaudible) sanction for block H flowing LNG, the field development plan has been submitted to Petronas and we expect approval of the plan in the fourth quarter. In the Gulf of Mexico our Dalmatian Deepwater tieback project continues to move forward as planned with first production slated for first quarter of 2014.

Now a look at our North American onshore business. In the Eagle Ford shale we are running eight rigs and three frac units at present across the play. We've drilled 348 wells and have 287 on production. Production averaged 45,600 barrel equivalent net in the third quarter, an increase of 5,900 barrel oil equivalent per day net over quarter two with an average oil liquids weighting of 92%.

We see production holding near this level in the fourth quarter as extremely wet weather in the field has hampered production and operations early in the fourth quarter and six well pad drilling and associated completions provided fewer wells coming online in third quarter than in previous quarters. Our total annual production in the Eagle Ford shale will average approximately 40,000 barrel equivalent per day and 91% oil liquids for the year, a real solid performance for our team.

Operating costs continued to show improvement through the year with quarter three costs in the range of $13 per Boe, down from $15 per Boe in quarter two.

We have two 40 acre down spacing projects ongoing, one on the Manka lease on our Karnes field at six wells which actually ended up on a 26 acre spacing normalized on a lateral length of 5,000 feet. So far with three months of production data the wells are performing comparable to neighboring wells which we are pleased to see.

The second down spacing project is on the 100% Tilden acreage where we are testing four down spaced wells. These wells have 6,000 foot laterals and are spaced 275 feet apart effectively testing 32 acre spacing. Initial results are positive with production rates in line with offsetting wells. We have flowed the wells from 12 days and so far the wells are averaging just over 250 barrels oil per day per well on an 864 choke and are still cleaning up.

In addition to down spacing we're seeing upside from recent pilots around lateral orientation and length extension. In the Catarina area two wells with optimized lateral (inaudible) are the top two and three wells respectively out of 25 wells in the field.

In the Pearsall Shale we have zeroed in on 25,000 acre focus area, we spud our first of two wells planned for the fourth quarter to further test the Pearsall. we are finalizing two Buda Lime test well locations to be drilled in quarter one, one will be located in the Catarina area in Dimmick County and the second planned in the Tilden area in Atascosa. We currently have a focus area of 16,500 acres in the Buda.

We have hedged 10,000 barrel oil a day of our US production by forward selling calendar month WTI at a price level of $101.55 per barrel for quarter four of this year. So far in 2014 we have hedged 20,000 barrel a day for the first half of the year at an average price of $97.48 and 6,000 barrels forward sold in these contracts on average at $95 for quarter three of next year.

In Seal we continue to focus on our EOR projects, our first cyclic stimulation project at the Cadott area continues to go well. We are now completing our third cycle in the first well and are seeing production rates hitting 100 barrels a day which is approximately 4 to 5 times cold primary production rate in this area. We just completed the first steam cycle in the second CSS well in Cadott and are currently producing it back. Results are very positive with oil rates hitting 250 barrels a day on a single well.

Our polymer pilot continues to produce to plan with four producers averaging a total of 450 barrels oil per day this year. We've taken the opportunity to protect cash flow with some strategic hedges and have 4,400 barrel oil per day of Seal heavy crude hedged at an average net back price of just north of $52 in quarter four.

In the Montney current production is near 160 million a day and we continue to generate solid cash flow. We have 75 million forward sold at CAD3.75 for the rest of the year and 50 million cubic feet per day of gas forward sold in 2014 at CAD4.00 per MCF. We continue to focus on managing costs and improving net backs by focusing on liquids rich areas and working on third-party gas processing arrangements through our facilities.

We are currently processing approximately 160 million of proprietary gas and 15 million a day of third-party gas. We expect to sign a long-term gas processing agreement at Tupper West shortly. We're in the midst of negotiating a separate one at Tupper main. In the third-quarter production average slightly over 207,000 barrel oil equivalent per day exceeding our updated guidance level of 198,000 a day primarily attributed to higher production in the Eagle Ford shale, Kikeh, SK Gas and the Gulf of Mexico.

Production guidance from quarter four it set at 199,000 barrel oil equivalent per day. Quarter four guidance reflects the major downtime at Kikeh, for the tie-in work for the Siakap North Petai risers, Terra Nova shut-in for a mooring change repair and lower Montney production offset by higher SK oil and Syncrude production. Overall a very solid year on production, meeting and exceeding targets.

In summary, the spin-off of the US retail business was completed on August 30 to plan. We are now a focused E&P Company with only the sale of our UK downstream business remaining to complete this transition. Eagle Ford shale continues to deliver growth with production targeted at near 40,000 barrel equivalent this year and we continue to improve our operating metrics.

On exploration we are currently drilling impactful prospects offshore Australia and the Gulf. We continue to add acreage to our exploration program long-term. Our development work on all of our offshore oil projects is progressing well. And we continue to deliver on production targets. That is all I have for today and we can open it up for questions.

(Operator Instructions). Leo Mariani, RBC Capital Markets.

Could you give us a little bit more color in terms of it getting from the 207,000 barrels a day of production to the 199 in the fourth quarter? I know you talked about Kikeh oil shut-ins and Terra Nova -- kind of some work over activity there. Could you maybe kind of quantify magnitude of some of those different pieces here as we try to bridge the gap between Q3 and Q4?

Yes, you want to go from 207 to 199, right?

Yes.

Okay, Kikeh oil will be down around 10,000 a day, Terra Nova 3,600, it produced just a little bit in quarter three and it is down for a mooring repair change. Tupper area has declined 3,400 BOE a day. SK gas is down 1,500 per day. That is usually -- we forecast in based on downtime at that facility there.

And those are some of the major ones and we have some positives with the Syncrude having a better situation to the prior quarter and also the new SK Oil coming on. Those are the two uplifts at around 4,000 each and the rest are sort of counterbalancing each other out. Leo, is that good enough for you?

That is great. And I guess additionally you guys talked about sales volumes of [$1.91], so obviously lower than sales. Maybe you can just kind of help us kind of get to that as well.

Yes, the major under lift there is in Malaysia, Leo, basically, that is where it all is.

Okay, no, that is helpful.

Their timing of lifting.

We have a couple right at the end of the year but we don't have them in, Leo, because it's literally on the date.

Okay, that is helpful. Looking at your US operating costs this quarter, they have been dropping pretty hard the past couple quarters. I think you guys, I had calculated you somewhere kind of just on LOE maybe it is close to $10 a barrel. Maybe just kind of give us some more color, is that just all Eagle Ford that is bringing op costs down that you guys said Eagle Ford was $13 a barrel down to dollars a barrel from the past quarter, where do you guys think that can go in the long-term on the op cost there?

And long-term I mean Karnes, our oldest field is in the $10 level now, I think that would probably be the bottom. We maybe can get it into the $12 range across all the fields. But a real good job by our team there. Also in the Gulf we are still putting all our US together, Leo, probably next year we will change that.

But we have some barrels coming across Front Runner from off lease production, that pulls some OpEx down there almost too nil. But it is a real Eagle Ford player because the Eagle Ford is much more production in the Gulf as we stand, but a great job there. But I don't see us going below $10 to $12 long term there.

Got you and that is definitely helpful. Just looking at Seal, you guys did talk about production sort of kind of hitting lower into the fourth quarter. You kind of talked about some of these pilot projects, your polymer as well as your steam (inaudible). Are you guys doing any kind of regular way conventional drilling? Is that activity all shelved and how do you kind of think about that as we go into next year?

It is pretty much shelved. I mean you're looking at Seal next year being pretty close to the levels that it is now. We are just really focusing in on I would say almost exactly where we are now in production for next year, I was just looking at it. We are really trying to get our EOR lined up for steam which I think is big growth. If you look at our long range plans we really have -- don't have significant growth there like 17, 18.

These are long-term projects to be approved by regulatory and we've got a team in place looking to improve that. But we are real happy about the well we just had, but we want to just work on EOR and really get out of the conventional game. Because on capital allocation business in North America, and that's run by one gentleman. It is difficult to compete with Eagle Ford, of course, there.

But long-term lots of barrels, lots of steam ahead for us there, lots of steam success around us. We haven't been a steam player, we are building up what we need to become one. And I am happy with that transition.

Okay, that is helpful. And I guess just looking at your G&A. If my numbers are right you guys were somewhere around $62 million in the third quarter from your non-E&P, I guess your downstream segment. I guess that number seemed kind of high. Can you give us any color there? Maybe there were some transaction costs or something and where should that go to sort of next quarter and beyond?

Yes, we had one time transition cost with the separation of the sale of business to the US. So we had upwards over $15 million, probably $16 million $17 million of one-time costs related to that in the third quarter, more than that if you look at it on a year to date basis.

Okay, that is helpful for sure. In the Eagle Ford you guys commented that you brought fewer wells online in the fourth quarter and kind of talked about flattish production. I'm sorry -- fewer wells online in the third quarter then flattish production in the fourth quarter sort of due to weather.

I guess it should we anticipate that accelerating as we get into 2014 where you will start to get back on track and start bringing a lot more wells on? And can maybe you just throw some numbers around, how many wells you brought on in third quarter and what you expect in 4Q?

Yes, it is kind of my fault there, I have cut the capital machine back trying to maintain some capital efficiency there. You know you can spend as much money as you want to in the Eagle Ford and I didn't want to change our balance sheet to continue. We put on 90 -- 42 wells in the first quarter, 42 wells in the second. I'm giving you operated wells. We have five to seven -- non-up but it is an operated game business for us.

And then when we went to six well pads and we cut back the CapEx down to two to have our spend maintained for the year, we dropped back to about 35 to 36 wells in the third quarter. We now are getting away from six well pads, that didn't work so well for us there is a water and sand requirements we needed, we had trouble with our equipment fracking that many wells in a row, it just didn't work well across our acreage.

We're going back to four well pads now and we are going to be delivering 42 wells with an upside of 48 wells in the fourth quarter. Getting back into probably frontloading our CapEx again as we did last year. I think we grew production in that play about 24,000 barrels equivalent last year with 182 wells and we are looking at growing at about 17 with 160. So we are probably going to be a 162 operated well player and probably get into 90 or 100 in the first half of the year every year will be typical how we play that, Leo.

All right, that is really helpful color. Thanks, guys.

Evan Calio, Morgan Stanley.

First question on Siakap North. I think I understood your color on the project. But could you -- I mean do you expect all that tie-back work to be completed in the fourth quarter before the monsoon season? Or is there -- will the project be completed now in two phases, one in November and then one in late 1Q? I think that was per the EPIC contractor's recent update. What is the --?

Yes I mean we have some real disconnect between you and me on that. We have contractual agreements with them to do this work. We have recently signed a contract to agree with that party. They're out there doing the work today, we broke the work up into several vessels and all that stuff I rattled off is a lot of significant work. This work is not difficult to do. You are down to it, the issue is weather risk, we have a contractual agreement around whether to risk with that party that I'm happy with.

You're talking to a guy that lived there for six years and knows all about monsoon weather in Malaysia and built a bunch of stuff there. We are probably one of the more successful developers in that region. And we have a contract with a guy to do it, the guy is doing the work, we have one significant step left to go. If you ask me about my guidance I plan on these wells flowing on December 15, I will be very disappointed with my staff if they don't. But I don't have any barrels in the fourth quarter for it.

Okay.

We do not have -- do not have with McDermott a split campaign to do this work. We have one campaign and they come and they loaded the pipe and they're coming to do the work, and they're on the water to do the work today.

Okay, that is good news for you. On -- shift gears on to exploration. I'm just curious what you learned from that ebony one well in Cameroon and how different the TEM prospective and if that is -- is that the Ocean Confidence rig that comes back to drill that prospect in 2014?

First on DO matter, we are using that Ocean Rover now, the confidence is still off with another party there. We are kind of working off some of our commitment with DO with the rover. The rover went off the shipyard and coming back. Yes, it's disappointing that well, a Longbow dry hole naturally, and we are still not concerned about that related to this. They are two totally separate projects.

On the positive side we established sand presence there that we tied to seismic and very nice sand now and very large structure we are drilling in Ntem. We did take a kick on this well in [Elombow] and had some heavy gas in our mud log there, which de-risked the petroleum system in the region. The Elombow well was a stratigraphic trap feature up against a fault and that fault had leaked Seal risk and obviously leaked off.

The feature that we are drilling in Ntem does not have that effect, it is a stratigraphic feature not bound by that same fault, it is not connected up to the Elombow, the main feature we are drilling. So learn something, I would say back two years ago if we would've had the data for Elombow it would have lowered the risk a little bit on Ntem, but it is still a Frank frontier well. And but it does not disappoint me to have to drill that well today.

Okay, that's good. And lastly if I could, the new acreage that you mentioned in your opening comments in Australia, can you talk at all about what you think there in terms of prospectivity, is that --?

Well, there have been some announcements by other parties, you can look that up. There has been a lot of leasing and a lot of award of late, BP and Statoil are in the region with four blocks and Chevron recently had the other two and we were able to come out with one.

This is rank Frontier exploration, there was one dry hole drilled in this entire mass region. I mean this block we have is almost as big as Mississippi Canyon or half as big as Mississippi Canyon (technical difficulty). Performance area as big as the entire Gulf probably. One well drilled and it was a dry hole and one of the blocks another party leased, very nice sand there.

There was dredging done to the east -- I mean, to the west of our block that was some oil sourcing material dredged out of the basin. This was announced prior to all the leasing. Our team worked this out. We can't they present there for a long time in Australia and we were in a competitive bid environment with some others who came out with a block.

And for a Company like us it is old-fashioned Murphy rank Frontier exploration, we are proud of it and the advantage we have is there will be a lot of drilling around us by other parties while we are in our seismic phase. So it is very positive for our exploration group.

Got it. Thanks for taking my comments.

Blake Fernandez, Howard Weil.

Roger, you will have to forgive me, I'm going to go straight to probably your least favorite topic here. But on the UK I was wondering if you guys could maybe provide a split on the $12.9 million loss between the refinery and the retail?

And I guess where I'm going with that is assuming the refining is really what is weighing on the results, is there an opportunity maybe if this sales process continues to drag on to maybe split off the retail and see if that could be marketed as a standalone?

You know, this thing, Blake, I don't mind you asking about it at all and you should ask. When you're trying to sell something like that for a long time. First thing, you got to operate wells so you can keep it running to try to sell it. And our team over there is doing a very good job of doing that. And very, very bad net backs in refining. You are right, the refining is a big part of that.

We haven't split that out before and while I'm in the middle of trying to sell something probably not going to split it out today. As long as we are in a data room, we are putting work in the data room and people are progressing and talking and working toward LOIs and trying to get to buy the thing, we are going to keep going forward with the process until that dries up.

And that hasn't dried up and we are working on it. And really I'm interested in selling it, but I'm not interested in just walking away from it at this point. We do have the opportunity to split it, like you say. But today as long as I have interested parties and do not have to split it into two I'm going to stay with it.

Okay, got it. This may be for Barry or Kevin, but the exploration expense was a little bit above what maybe we would've thought considering that Australia is spilling into fourth quarter. Are there any other moving pieces in there besides Cameroon that we should be aware of?

Well, we have got the range we gave you of $100 million, right, from $50 million to $150 million. So that is basically made up of we are partnering in the Madagascar well in the Gulf, that is sort of in that -- sorry you are talking about third quarter?

I'm sorry, Barry, I'm talking about third quarter.

(Inaudible) on that, Blake. I'm disappointed in my team's drilling of that well. And it was supposed to cost about $56 million and it cost $70-million-something. So I mentioned in my comments to a previous color we took a kick on the well. So we didn't do a good job of executing the well. So the well is a little more expensive than we thought. And Barry can give you the spend of the other things (inaudible). That is the situation at Cameroon. Go ahead, Barry, with the other spend.

So, back to third quarter, Blake. I mean was there any other specifics you needed there?

No, no, no, that was the main issue I was worried about was 3Q, because I think Roger basically covered it. So I think we are squared away there. The final one for you, Roger, this is probably back to you. But just any thoughts on M&A specifically in unconventional? And now that you have got the team up and running in Eagle Ford it seems like you guys are delivering there and you've got a team in place. Any appetite added to the portfolio?

Well, you know we are up and running well and we have built that team -- it's a significant team and a great accomplishment. There was a previous caller asking about OpEx and we have low drilling costs and it is going very well. We built that off of our success we had long-term in Calgary led by the same person, Mike McFadyen.

We do have a group of people looking at M&A as any company of our market cap would have. And we do have the ability now to execute that would lead you to where we could pay I suppose and I know we can do the execution, but we are not interested in doing M&A for the sense of just growing or worrying about exploration or anything like that. We need something that has return.

If we have something to make return and it fits into something we can execute on we look at those. We probably look at that more than people think, but we are interested in working real hard on making a return for our shareholders. So looking at it probably harder than we were two years ago and going forward as a normal course of our business to date would be the best way to describe it.

Okay, thanks, guys. I will leave it there. Thank you.

Guy Baber, Simmons & Co. International.

Roger, I was just wondering if you had any early thoughts on 2014 capital spending. I believe the prior guidance was $3.6 billion for E&P which would imply a slowdown in spending versus the current run rate. Just trying to get a sense of whether or not that $3.6 billion is still a good number and where that slow down might come from in the portfolio?

We don't have our budget approved until December, we usually talk about that in the February call. But we're not going to have a major surprise in that in my view. There will be a major pullback in spending because they are putting all these shallow water Malaysia projects on line. The Siakap North, the Kakap, the four projects in Sarawak and we're doing a lot of the execution of Dalmatian. Eagle Ford would be about the same, exploration a little bigger probably. But we are in the middle of all that with our budget but you are not going to be surprised with a blowout of the number that you mentioned.

Okay, great. And then I apologize, this is a detailed modeling one. But I believe you all are scheduled for a lifting in Congo during 4Q. And presumably there will be some costs that you will need to book associated with that. So can you provide any guidance on the level of cost there that might accompany that lifting just order of magnitude? And could we look back to 1Q the last time you had a lifting there and use that as a baseline? Just any information you could provide there would be helpful, just don't want to be surprised 4Q on the cost side.

In terms of the lifting, we do have a lifting scheduled in Q4 and because of those low amount of production being produced there the cost will virtually offset -- the production on the lift itself will virtually offset the value of the oil assuming there is no major change in the oil price. So there is not a lot of P&L impact from that lift at all.

Okay, great. Just wanted to clarify. Thank you.

Ed Westlake, Credit Suisse.

Good morning, Roger, this is Scott Willis on for Ed. I just wanted to quickly focus on the CapEx. It looks like based on your current run rate you would be coming in a little below your current guidance. So should we expect that the CapEx is going to be more kind of 4Q weighted to get to that amount or do you think it will come in a little lower?

I think we are pretty in lined with CapEx, maybe slightly lower. And we talked about various shortages of CapEx, I guess we will be about $400 million short this year, cash flow CapEx. And when you add on our dividends and if we are able to do some additional repurchase we feel that if that can be counterbalanced up the year by the dividend we received from Murphy USA and if we are able to close on the Milford Haven. But today we have no pullout of our revolver and all on our long-term debt outside of the Kakap lease and, Kevin, do you want to provide any (inaudible)?

I was going to say there shouldn't be -- we should be pretty close in the number, there shouldn't be a major amount that flops over into 2014. Of course you know if you ended up with some weather delays or something like that you could always have those sorts of issues. But -- and for our internal numbers we are still using the same guidance we have given to you all.

Okay, great. And just one last one. Would you be able to give me the contribution in the quarter from any of the newly tied in assets in Malaysia?

In which quarter are you talking about, sir?

In 3Q if there was any contribution.

Very little in the third quarter.

Okay.

We were just putting these assets on when the -- Serendah has only been on since October 29, and South [Axis] is already in from the prior quarter. And the others are staged to come on more throughout the rest of the year.

Okay. All right, great, thank you.

(Operator Instructions). Pavel Molchanov, Raymond James.

I know that exploration expense guidance is always a bit of a black box. But from the low end of 50 million to the high end of 150 can you just walk us through the major variables there?

Will have her expert, Barry Jeffery, to walk you through that.

Sure, Pavel, I tried to get off on the wrong foot there with Blake. So here we go. We have got a 100 million variance there that we are talking about, we are in the Madagascar well in the Gulf of Mexico, our share there is say and the 45 range, got the Dufresne well in Australia, that is about 30 and then we got a Brunei well scheduled to kick off and that is about 25. So there is your 100.

Okay, got it. And then sorry if you mentioned this already, but Cameron obviously disappointment, does that condemn the rest of the program in that country or are you rethinking it in another way sort of Surinam worked out in the past or are you still committed to it?

Well, we are still very much committed to it. As I said to an earlier caller, we took a kick on the well that proved hydrocarbon migration through that area, which is a great derisk for us. We found nice sand development there and it has a different trapping feature or a different risk to trap. We didn't do well drilling the well, I think we can learn from that and drilled this will cheaper possibly.

And, no, I'm very glad to drill the well and it's up-and-down that coast, the margin of Equatorial Guinea that would have nothing to do with that. And Surinam has both a fan feature surrounded lots of least acreage in data and also a very big four-way closure Cretaceous opportunity there. I see nothing from that well that would preclude me from wanting to do any of the rest of my program, it is just another well and a long list of wells we have.

Okay. Planning to drill in Cameroon next year?

Planning to, yes, sir.

Okay, appreciate it.

And it appears there are no further questions. (Operator Instructions). And it appears there are no further questions. So I will turn the conference back over to our presenters for any additional or closing remarks.

Well that's all we have today and thank everyone for calling in and we will see you at our next call, and appreciate it. Thank you.

This concludes today's presentation. Thank you for your participation.