Murphy Oil Corp (MUR) 2010 Q3 法說會逐字稿

Good afternoon, Ladies and Gentlemen and welcome to the Murphy Oil Corporation's third quarter 2010 earnings announcement. Today's conference is being recorded. I would now 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, Barry Jeffery, Director of Investor Relations, Craig Bonsall, Supervisor 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 third quarter 2010 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 a further discussion of risk factors, see Murphy's 2009 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.

Thanks, Barry. Net income for third quarter 2010 was $202.8 million, or $1.05 per diluted share. That compared to net income of the third quarter '09 of $188.9 million and $0.98 per diluted share. The nine months for 2010 we had net income of $624 million, $3.24 per diluted share, compared to net income for the nine months of '09 of $518.8 million, or $2.70 per diluted share. There were no unusual items of significance in 2010 quarter or for the 2010 nine month period. The 2009 nine month period, did however include $97.8 million, or $0.51 a share of income from discontinued operations. This was mostly related to a gain in the sales operation and Ecuador in March of last year.

Looking at income by segment, the E&P segment, income from continuing operations in third quarter of 2010 was $186.7 million, compared to net income of $184.1 million in the third quarter of last year. Slightly higher earnings for 2010 quarter were primarily due to higher crude oil and natural gas price realizations, higher natural gas sales items, partially offset by lower crude oil sales by volumes and higher expiration on extraction costs. Crude oil and liquids prices averaged $65.45 per barrel in the third quarter of this year, versus $61.13 last year. Both American natural gas prices averaged $4.24 per MCF this year, compared to $3.01 last year, while on Sarawak third quarter 2010 natural gas to realization average $5.71 per MCF, compared to $3.31 per MCF last year, an increase over 72%. Crude oil and gas liquids production from continue operations for the current quarter was just under 120,000 barrels per day, compared to approximate a 131,600 barrels per day in the corresponding 2009 quarter. The decrease was mostly due to lower production from kikeh offshore Malaysia ahead of our planned rig program. Natural gas sales volumes more than doubled to 371 million cubic feet per day in the third quarter of this year, compared to 182 million per day in the third quarter of last year. Increases was primarily due to production of gas fields offshore Sabah, Malaysia and higher production in the Tupper area in western Canada.

In the downstream segment, third quarter of 2010, the net income of $50.6 million compared to net income of third quarter of last year $37.2 million. In North America, an earnings increase of approximately $18 million was primarily due to earnings from our ethanol plant in North Dakota, which was acquired in the fourth quarter of 2009, at the higher merchandising and fuel margins in our retail business. The UK earnings reduction of about $4.7 million was mostly attributable to lower refining margins. In the Corporate segment, we had net charges in the third quarter of 2010 of $34.5 million, compared to net charges in the third quarter of last year of $32.4 million. The increase of these charges was primarily due to higher administrative costs.

As of September 30, 2010 our long-term debt was a little bit over $1 billion, 11.4% of total capital employ. Now I'd like to make a final comment regarding our fourth quarter earnings guidance in the press release. We have a rather wide range of $0.50 to $1.15 per share, as a result of our on-going and very active exploration program. Also keep in mind, that due to the timing of listing our projected sales volumes are approximately 10,000 barrels of oil equivalent per day lower than our projected less load productions, which of course has a direct affect on projected fourth quarter net income. With that, I will turn it back over to Dave.

Thanks, Kevin. In the third quarter benchmark crude prices were range bound fluctuating between $70.00 and $80.00 a barrel, however, recently prices have reached the $80.00 mark on the back of improved demand, a rebound in financial markets, a weaker US dollar, and impact on major strike in France. Global petroleum demand is also trending back towards pre-recession levels. Too early to call this a breakout, but it will bear close scrutiny as we work through the winter seasons.

Natural gas prices here in North America continue to be under pressure and it is hard to see any move away from the current $4.00 fulcrum until supply and demand met are balanced. The recent lifting of the moratorium in the Gulf of Mexico has little impact on restoring business there, as no clear path on approvals, nor a consistent way to conduct business, is apparent. Effectively, we now have a permatorium. This is a directly effecting our Gulf of Mexico business and future plans, and of course, is unfortunate. We are blessed, however, to have the preponderments of our business upstream investments outside the US Gulf of Mexico and here businesses are actively moving forward in helping drive our growth profile.

In our US retail, we had a steady quarter with margins coming under pressure in September as crude and wholesale prices trended upwards. In refining, (inaudible) only started improving in September, although otherwise more of on levels for the quarter. Here our focus is on the safe reliable operations of those assets and then ongoing divestiture process which remains on track.

Looking at our business segments in closer details, our global production for the third quarter average 181,733 barrels of oil equivalent per day, slightly ahead of our third quarter guidance of 108,000 barrels of oil equivalent per day. This increase is attributal to a higher production in Malaysia, and in the US, where Gulf of Mexico production was favorable due to less hurricane downtime than forecasted. This was partly offset by lower volumes in Azurite, Chilean, and in Canada due to maintenance turnaround activities and well scheduled.

Natural gas sales for the quarter average 371 million cubic feet per day. In Malaysia, Sarawak gas production continues at plan with gross production near 250 million cubic feet per day and Kekap gas beat projections with better plant uptime. In Canada, natural gas production was impacted by plant turnaround work, on the Tupper Main plant, as we expanded its capacity.

Production guidance for the fourth quarter is estimated to be 198,000 barrels of oil equivalent per day, up from the third quarter. This will put overall 2010 production just below prior expected levels, due to unforeseen downtime of some of our non-operated fields, and weather delays at our Kikeh rig program. Fourth quarter production rates will be bolstered by the startup of another new well at Azurite, the workable program at Kikeh, [Jahaley] returning from turnaround, and new wells coming on in Eagle Ford Shale. We will continue to see some negative impact in our production from the drilling permatorium, in the deep water Gulf of Mexico, due to delays in rig operations particularly at (inaudible).

Looking forward, I expect to see 2011 production levels to once again show attractive year-on-year growth, however, we will be impacted by slower Gulf of Mexico activity. Maybe, lower by 7,000 to 10,000 barrels equivalent per day from earlier projections, as well as, we focus towards oil in our Eagle Ford Shale program that has already begun. Here we're emphasizing value over volume growth. A range of 210,000 to 220,000 barrels of oil equivalent per day for 2011 is where I think we'll fall. Again, how quickly the Gulf of Mexico returns to work by far being the biggest driver in that range.

We recommenced our expiration program in the latter part of September and should see results coming in over this quarter. In the UK, our non-operated prospect adjacent to the Mongol field, did not encounter commercial quantities, hydrocarbon, and has been expensed as a dry hole. In Congo, we just finished the Titan number one well, in MPN block, and found a small oil high back sized accumulation, which is encouraging for nearby prospects, but clearly not what we were hoping for. That rig has now started up in the MPS block, where we have three remaining high potential prospects left to drill. In Suriname, we are opening up a new play and will spud the first well very shortly. In the fourth quarter, we'll start turning the bit in our Indonesian Somite two block, for a very large target. In the Gulf of Mexico, on non-operated deep (inaudible) prospect, in Green Canyon 723 remains suspended. Work will recommence once permits are in place.

Looking forward into 2011, and also 2012, we have a full and impactful exploration program with attractive prospects being tested, by over a dozen wells, spanning seven countries in 2011 and a similar number and 2012 expanding six countries including some resumption of activity in the US Gulf of Mexico. Our North American resource position provides a nice compliment to our global expiration activity, and in September, we announced entry into a fourth play, this one in Southern Alberta, targeting the oil prone ex-shore formation which is analogous to the backroom play on the US side of the border. We are moving forward with plans for early drilling next year to appraise our position, which we continue to grow, on a now close to 150,000 net acres. In Western Canada we have six rigs operating, between the Montney acreage at Tupper and our heavy oil operation at Seal. Plans are moving forward to bring on the new Tupper West gas plant, with its capacity of 180 million cubic feet per day, and first cap in 2011. The Seal and Handsoil recovery pilots are on-going and we expect to have the results incorporated into our plans in the first quarter of 2011.

Onshore in the US, our operations in the Eagle Ford Shale in South Texas continue to be very encouraging as we focus on the oil rich areas of the play with three rigs running. In (inaudible) county, we have two producing wells, that together, are making over 800 barrels of oil a day. A third well, the Shindale Unit A, was filled to a total depth of 16,395 feet, with a lateral section of 4,500 feet. This well is scheduled for completion early this month and will provide the basis for sanctioned development of this area towards the end of the year.

In [Debent] County we have drilled three wells and completed one well, the Briggs number one, which is currently producing 175 barrels of oil per day, as the well is choked back to maintain a stable rate during this evaluation and cleanup period, following its completion. The two other wells, Briggs number two and number three, will be completed later in the fourth quarter. Overall our North American resource acreage is now around 700,000 net acres and strongly weighted towards oil.

Business development remains active for us and we recently signed an agreement with the Kurdistan Regional Government in Iraq to acquire a 50% interest in the central Dahook block where we will operate. The block covers 619 square kilometers and sits within a world-class petroleum province, and on trend with recent exploration drilling, which has shown much promise. We plan to shoot seismic in 2011 with an exploration well to follow. Other opportunities are being worked and we will open an office, in (inaudible) shortly.

Switching to downstream, the process to divest our refining and UK marketing assets is, as I mentioned earlier, moving forward as planned. Operationally US retail continued steady performance in the third quarter, capturing good margins while maintaining strong fuel volumes despite rising wholesale prices late in the quarter. The retail chain expansion continues with year-to-date additions of 38 stores bringing the current station count to 1,086. US refining margins were under pressure for most of the quarter, until cracks spread improved in September.

Superior Asphalt business continues to provide a steady contribution. In September, we reached final agreement with the EPA on it consent decree for both US refineries. This allows those assets to focus on their future safe, compliant, and reliable operations. In the UK as our retail group continued its steady performance, The Milford Haven refinery was struggling in a difficult northwest Europe market environment, until margins showed some improvement in September. We are scheduling a minor crude unit outage in November to complete some further modifications that will increase crude throughputs to 130,000 barrels per day.

In our renewable fuels business, the ethanol plant in Hankinson, North Dakota continues to be a steady performer, with production rates at 120 million gallons per year level. Margins are strong for the quarter as ethanol outpaced the jump in corn prices, quite concerned over yield forecast, and increased export demand. Since acquiring the plant in the fourth quarter 2009, Hankinson has provided a solid financial contribution returning close to $18 million of net income and $28 million in cash flow.

We closed on our purchase of the partially built Hereford, Texas ethanol plant in August. Engineering work is ongoing and plant modifications will be completed with start up schedules near the end of the first quarter of 2011. The plant is expected to achieve production rates of 115 million gallons per year as production ramps up. During this quarter, of course, the EPA announced a wave of (inaudible) 15 for newer model vehicles. This should help extend the blend form for corn based ethanol production.

In summary, we are back actively exploring testing high-end prospects as well as adding new hybrid tension oil opportunities to our portfolio. With this, the addition of acreage in South Alberta for the ex-shore play and the new acreage in Kurdistan. I expect to see this activity continue through the remainder of this year and into 2011 as our budget and plans become finalized. A price hold drilling in the Eagle Ford Shale is encouraging and our EOR Pilot work at sea is forward moving nicely. US retail continues to shine and our divestment of the refining assets continues as planned. That concludes my prepared remarks and I am now happy to take your questions.

Thank you very much. (Operator Instructions) We'll take our first question from Arjun Murti with Goldman Sachs. Your line is open.

Thank you David. Thanks for the Eagle Ford Shale update. I think you mentioned the Karnes County acreage is what could be sanctioned towards your end, just wanted to confirm that. On the Dimmit, where you mentioned the choked back rate, any sense on what unchoked rate might be on that well?

Arjun, thanks. Karnes, once we get the results of this Schendel well we will have a better sense of what area we want to include in our development plan. Overall, we've got six wells to frac between the now and the end of the year throughout the program. Getting more data is always helpful going into a sanction. If you look at the wells that we've had on production, the longest one has produced is about 140,000 barrels so far. Since it came on the Drees well and then the JOG well has produced over 50,000 barrels. Both very nice wells.

And I think the Schendel well will hopefully reinforce that. The Dimmit County well is in a different part of the play. It actually behaved differently but very similar to how the other operators' wells were doing. When it came on production, it actually made 100% water and it wasn't until we covered about 10% of the water load that we actually started making oil. We got the well up to 175 barrels a day on a small choke and we've just been dewatering the well. I think it will do more. I don't know what it will do . We want to do is complete the fracking on two other wells there. And then get a better sense of what we've got. I will say, I am very encouraged by what we

That is great. Any thoughts on the rig count in the Eagle Ford can go next year? I think I see three rigs now presumably a higher number next year?

Yes. I think by the end of the year we will have five running, Arjun.

Okay. David a final point in your opening remarks you alluded to the fact that oil may or may not be breaking out now. If we have $90 to $100 oil next year instead of the date of the $65 to $75 we have been in. How does that change your plan whether it is capex or activity? Does that really change at all or are you just alluding to the fact that oil needs to be doing better here?

I think it really illustrates that oil versus gas being more oil-weighted and making decisions on oil. I don't think gas is going to move, Arjun, so I think you will see us weight more towards oil than gas. Things don't move very fast in our business. Where we can make significant moves, we will try to do that on the oil side.

Any early thoughts on the 2011 budget?

I'll give you a high -- I think it's going to look somewhat similar to what this year looks like. We've got some projects that we want to sanction. Next year we are doing some appraisal drilling in Malaysia. Depending on the results of that I think next year will look somewhat similar to this year in total.

Thank you very much.

Or next question is from Mark Polak from Scotia Capital. Welcome.

Hi guys. First question on Exshaw, wondering how much activity you've got planned next year and wondering -- give us your thoughts are what you think the resource potential is there and what excited you about that play there? And just what exciting at that point?

Yes, Mark. Thanks. We are still trying to grow our position there and so have an active effort. But we want to get to drilling and we'll probably move a rig in and be drilling our first well in January. The first phase, for us, when we get into these places is to do some appraising. We will probably have six wells in that appraisal program that will be drilled consecutively. These will be drilled core and likely test. We're fortunate in on some of our acreage, there's already two old wells that have recovered oil They weren't drilled for this actual horizon but they did recover some oil.

So we have good place to start and I am pretty encouraged. We talk about net acreage being about the actual play. But there really is two other horizons that are equally in our mind today perspective. The Exshaw is the deepest horizon but we see a drastic level called Waddon and a shallow cretaceous level called the Second White Speckled Shale which is a ugly name but that's what it's called, is also being prospective and so our appraisal program is going to target some of those horizons to also see if they have some running room as well. We're pretty excited about the play. It is early days. We want to get after it.

Thanks. And then obviously early days but any update you can provide on the pilots -- your pilots in Seal and what you see there?

I will just say that I am encouraged by the progress that's being made but we don't have any result to be able to base plans on yet. That will come out in the first quarter of March.

Last one for me in terms of Kikeh and I was curious in the drop in production, is that maintenance related or what do we expect to see in the next few quarters until some of the future expansions come on there?

In Kikeh, we have a rig program there that was delayed by weather. Responsible for a lot of things but I cannot control weather. So it's unfortunate that during a heavy lift operation there where we take the safe precautions of shutting production back. It lasted longer than we had thought. That is the real driver there. We should have another well on this month and another well on by the end of the year and get us back to where we were.

Thank you very much.

With more questions in queue, welcome Mark Gilman with Benchmark Company.

David, good afternoon.

Hey Mark.

Did you pay anything upfront for the Kurdistan concession?

We have a bonus that we have yet to pay, Mark. This is a fresh award.

Can you tell me what the amount and timing is on that?

I haven't paid it yet. If you let me pay it then I will tell you.

Okay I will remind you on that one. You characterize the Exshaw as being similar to Bakken. Could we talk a little more technical detail in terms of comparability between the two?

I would be happy to. It is a geological equivalent if you look at the make-up in terms of how it looks in the section. Is about 10% thinner overall than the sweet spots of the Bakken. It does have the same carrier bed in the middle. Given the results of the Bakken, where that is a key contributor of how wells performed -- lateral wells perform. We regard that as being very positive. It has very similar geologic characteristics. The oil that was recovered, from the two wells on acreage we have, is a good quality oil low 30 gravity. The section is over pressured. It is quite analogous. I did not really want us to start calling in Bakken because we don't have enough data yet and geologically things change over these long distances. It does have a lot of very similar characteristics

How does the brittleness, if you know, compare to that which we've seen in the Bakken?

From the data we have which is not complete and I would hold off until we actually core this section ourselves and conduct it, I would say it is comparable, but that is a question in terms of the ability to frac the carrier bed.

Just one more for me. In discussing the 2011 production outlook and the range. If I heard you correctly, the 10,000 barrel equivalent per day range really relates to Gulf of Mexico. That seems like a large number given where you are and what drilling you might have done had the moratorium and promatorium not been in place. Could you clarify what that represents?

I would say the promatorium is what is the responsible for that 10,000 barrels a day.

Development drilling where?

Looking across the board, whether it's Medusa, Front Runner, Thunder Hawk, Habanero -- all places we cannot get activity and permits is where we're having issue, and it's solely the Gulf of Mexico.

Okay, thanks, David.

You bet, Mark. Thank you.

With three questions in queue, let's welcome Blake Fernandez with Howard Weil. Your line is open.

Thanks. Good afternoon, guys. Question for you on Titan, if I understand correctly, the pre-drill was a 100 million barrels to 500 million barrels, if my memory serves, and I'm just trying to frame up when you say small oil, should we thinking toward the lower end or even below that?

Blake, let me put it in context for you. Ten million barrels in my mind is a small oil accumulation tie-backs, so I would cast the net in that direction. The reason -- well, so this is early days yet, but we think what's happened is that there is likely to have been a seal leak here because we have a very well defined structure that has some faulting through it. The channel system that Titan found stretches basically east-west, and runs into the northern part of the MPS Block. So when I make the comment about encouraging for me and my prospects, the prospect that I think it upgrades is the RR prospect, which has always been in favor to allow us in the Northeast part of MPS because those same channels run across that.

Now that prospect is different because it's a low relief four-way dip feature, very large, couple of 100 million barrels per channel, two channels that clearly won't have this faulting issue and potential leakage issue. So the results of Titan, I think, upgrade RR and RR is about 15 to 20 kilometers away, maybe a bit less depending on where you drill the well. So encouraging for that part of the acreage and you really have now got to go back and incorporate the results of this well, take another look at RR, and see when we want to drill it. We did about three years ago conduct a CSEM program, one of these electromagnetic programs on some high grade prospects. One of the prospects that we saw was RR, and it does have a very attractive looking CSEM anomaly and so the combination of Titan's results and the CSEM I think allow us to be a little more optimistic about RR, so that's where we are today.

That is great. I appreciate the comprehensive answer, David. The only other one I had for you not sure how much color we can get on this, but it is on Brunei, in your recent entry, I guess, reentry, if you will, can you talk about what is going on out there and if you do have exposure to the previous Lepu discovery that was in that block?

What I'd say today is I'll be better able to say more at the next call because we haven't finalized the second block, Blake, and I'd like to do that before we get into what the plans, et cetera. But that's where I'd like to say. We're happy to be in Brunei. We think the acreage is prospective, and so we're going down that path.

Okay, well thanks, I appreciate it.

Let's welcome next, Evan Calio with Morgan Stanley. Your line is open sir.

Hi, good afternoon, guys. The fourth quarter looks like clearly an exciting quarter on exploration. How should we think about disclosure? Are you guys still going to hold results until you have both Suriname wells down, and do you expect to group the three Congo wells into one release? How should we think about the news flow from Murphy here?

Yes, if you look at what we're doing in this remainder of the year, it's a lot of exploration expense, about $140 million, but let me give you some granularity on that. Of that $140 million, $46.5 million is basically appraisal wells in Malaysia. We're drilling a appraisal well on the Kerisi discovery, so Kerisi #2, that's in Block K, that will be a subsea tieback to Kikeh. We're drilling two wells at Sabah batches in Sarawak blocks.

We think that maybe an oil plus gas development and we're trying to get comfortable to be able to sanction that next year. And we're appraising a potential Phase III gas discovery that we made at a prospect called Tura. And so, really we're spending a little less than $100 million as true exploration exposure, and so that's the way it will run. Now, as far as timing goes, sometimes you're not in control of your own destiny and some of our partners, particularly, national oil companies like to announce good news.

So, my preference is to not talk about the Congo program until we're finished, but we just announced about Titan because I thought that was important and so I think we'll at those as we go along and make the calls as we go. I will tell you on Congo, we're drilling two wells at Turquoise 3 and Turquoise 4 and Cobalt and the rig is currently batch setting the Turquoise 3 and Turquoise 4 shallower section. It's actually on Turquoise 4 now and then it goes to drill Cobalt and then it comes back to finish the wells through their objective section at Turquoise Marine-3 and Marine-4. We have added a deepening to Turquoise Marine-4 as we've been working reprocess data. We've seen the deepening potential become quite attractive under the Turquoise feature.

As you recall, we have oil in the Miocene section. We now believe that there is some deeper Paleocene and Albian or cretaceous section that could potentially be quite large. I'm talking about couple of 100 million barrel type potential in addition to what we were drilling before. So that may well impact the overall timing here, Evan but we're excited about it. We want to drill that well. We think it's a good time to do it and so that will also be a mix.

So your figures are 100 million barrels higher, is that fair?

Couple of hundred million barrels higher, for that intersection. Now, it's a different risk profile as you drill down deeper because the Paleocene [ph] has not worked on the block. We've seen that section, have very good reservoir and has a right, but that didn't have any oil in it and we've never gone down to the Albian on this block. Now on trend, the Albian works but it's a much poor quality overall reservoir section but the structure looks very attractive and is a very nice size feature. So we think for a relatively small incremental amount of money here, $8 million gross, we can go and test something with some significant upside. So we've added that to the program from what we've from what we previously communicated.

Sure. The Titan well is this your current infrastructure in that facility for tieback or is that predicated on future development as well?

That is predicated on the future discoveries. That's predicated on future discoveries. As we work around this block and get a little more comfortable about how their risking then we can better judge where a Titan could or could not ultimately fit.

The last question if I could on the Eagle Ford I mean there has been a lot of encouraging well data from various E&Ps, they also have been highlighting cost and completion availability issues, challenging growth projections. Are you guys, do you think you're tracking to sanction Karnes County by year end and as your development timelines change at all -- tampered in the current service environment, any thoughts or comments there?

We're working it hard and I expect to see a complete document here first but I will tell you that if I look at our first eight wells and our last seven wells, for instance, we have been bringing our time and costs down in the face of increasing service cost. So we have been gaining efficiency and we have taken some steps to secure some frac equipment for the programs through the end of this year and also some equipment into next year. So I think once we start a dedicated program, we will work our costs down. Right now, we're in little over $9 million drilling complete these wells and I expect that to come down once we set some very specific targets. So, I think that will happen through the course of next year.

Great that's it for me, thanks.

Evan thank you.

And we'll take our last question in queue from Pavel Molchanov with Raymond James. Welcome. Your line is open. Welcome your line is open.

Thanks very much. First, just a quick point on Kurdistan. Realizing that it's very early in the game, but if you ultimately move into development mode, any terms of the infrastructure needs you would need on your acreage?

I believe we would need a great big pipeline, that's the simple answer. So we like the prospectivity in this area where near, it's in the northern part of Kurdistan, and adjacent to a couple of other discoveries. They're surface anti-climbs that we're drilling, but people tend to make large discoveries there. So I think the overall development from Kurdistan is going to take some very serious thought and some dedication of new infrastructure and we recognize getting in at this time as early.

I don't have a problem getting in early, and that's why we're opening an office in Arbil and looking to secure more opportunities. So, I would love to be in the position of making a big discovery here and then having worry about how much pipeline capacity I'll need. But I think it's not going to be unique to out-block, I think that part of the world is highly perspective and I think those infrastructure issues are being addressed and they're going to be addressed in the future.

Okay great and back on downstream, you made some comments at the beginning that were reasonably bullish on petroleum demand. Is it fair to say that you're maybe reevaluating whether you want to sell all three of your refining assets, or is that still the firm intention?

I won't make any comments as to our intent because I think our intent is pretty clear here. What we have seen, since we've made the announcement as the refining business continues to move up from the low of fourth quarter of last year. So, as I said we're on track and we've made a strategic decision here in moving forward.

Okay, thanks very much.

Mr. Wood, we do have one last question in queue. Welcome Gene Gillespie with Gillespie Consulting Group. Your line is open.

David, just from an accounting standpoint, how is the Titan going to be handled? Is that going to be a suspended well or you're going to take dry hole cost?

No, we're suspending that, Gene. It's got 16.5 meters of high quality oil paying it on water and so based on our knowledge of how zones like that look, we think it will flow at commercial rates. The real issue is how will it fit into any subsequent development and we are actively exploring in and around there. So that's the rationale.

What was the cost of the well?

Right at $30 million.

$30 million?

Yes.

I'm sorry, is that gross?

Gross number, yes.

Okay, thank you.

Thank you, sir. Thank you sir. Mr. Wood, at this time, with no other questions in queue, I'll turn it back over to you sir for final comments and closing remarks.

Operator, thank you. Thanks, everyone for dialing in. We look forward to the next conference call and talking about some results and hopefully have some good results. Thanks a lot.

Ladies and gentlemen, that does conclude the Murphy Oil Corporation third quarter 2010 earnings announcement. Thank you for your participation.