Murphy Oil Corp (MUR) 2013 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation second-quarter 2013 earnings conference call. Today's conference is being recorded. I would now like to turn the call over to Mr. Steven Cosse, 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 here are Roger Jenkins, our Executive Vice President and Chief Operating Officer; Kevin Fitzgerald, Executive Vice President and Chief Financial Officer; Andrew Clyde, who is the President and CEO of Murphy USA, Inc.; John Eckart, Senior Vice President and controller; Mindy West, Vice President and Treasurer; Barry Jeffery, director of investor relations; and Tammy Taylor, assistant manager of investor relations.

Barry?

Thanks, Steve, and welcome everyone. Today's call will follow our usual format. Kevin will begin by providing a review of second-quarter 2013 results. Steve and 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 obtained. 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 will now turn the call over to Kevin.

Thanks, Barry. Net income for the second quarter of 2013 was $402.6 million, or $2.12 per diluted share, as compared to net income for the second quarter of 2012, $295.4 million, or $1.52 per diluted share.

For the six months ended June 30th of 2013, we had net income of $763.2 million, or $4 per diluted share, compared to net income for the first six months of last year, $585.5 million, or $3.01 per diluted share.

This year's second quarter included income from discontinued operations of $70.5 million, or $0.37 per diluted share, compared to income of $4.1 million, or $0.02 per diluted share, for the same period last year. For the six-month period, 2013 included income from discontinued operations of $223.1 million, or $1.17 per diluted share, compared to income of $12.8 million, or $0.07 per diluted share, in 2012.

Increases in the 2013 income for discontinued operations resulted primarily from gains on the sales of all E&P properties in the UK.

From continuing operations, we had income in the second quarter of 2013 of $332.1 million, or $1.75 per diluted share, compared to income from continuing ops of second quarter of 2012 of $291.3 million, or $1.50 per diluted share.

For the six months 2013, we had income from continuing operations of $540.1 million, or $2.83 per diluted share, compared to $572.7 million for the six months of 2012, or $2.94 per diluted share.

Improved results from continuing operations in the second quarter of 2013 as compared to 2012 is mostly attributable to growth in oil production in the Eagle Ford Shale area.

Looking at income by segments, in E&P, we had income from continuing operations in the second quarter of $290.2 million compared to income from continuing operations of second quarter of last year of $226 million. Higher E&P earnings for the 2013 quarter were mostly attributable to higher oil sales volumes and natural gas prices in North America, partially offset by lower realized crude oil sales prices in the US and Malaysia, and lower natural gas sales volumes in Canada and Malaysia.

Crude oil and gas liquids production for the current quarter was approximately 136,000 barrels per day compared to approximately 104,000 barrels per day in the corresponding 2012 quarter, with the increase mostly attributable to higher production in the Eagle Ford Shale.

Natural gas sales volumes averaged 431 million cubic feet per day in the second quarter of 2013 compared to 507 million cubic feet per day in the second quarter of last year. The decrease was attributable to lower volumes at the Tupper area in British Columbia and from fields offshore Sarawak, Malaysia.

In R&M segment, from continuing operations we had income in the second quarter of 2013 up $72.2 million compared to $80.5 million in the second quarter of last year. The decrease in the current quarter was mostly attributable to weaker results from operations in the UK.

In the corporate segment, second quarter of 2013, we had a net charge of $30.3 million compared to a net charge in the second quarter of last year of $15.2 million. The increase cost primarily related to higher interest expense and administrative expenses.

During the quarter, we completed the initial accelerated share repurchase program we began last year and retired an additional 196,711 shares over that previously reported. Additionally, during the second quarter, we repurchased just under 4 million shares of our common stock to the completion of a second $250 million accelerated share repurchase program. The total number of shares we repurchased under the authorization approved by our Board last October is 8,044,378 shares, an average price of $62.16 per share. As of June 30th of 2013, Murphy's long-term debt amounted to just over $3 billion, which is approximately 24.9% of total capital employed.

This long-term debt figure includes approximately $320 million associated with the capital lease of production equipment for the Kakap field offshore Malaysia.

Excluding this lease long-term debt to total capital employed at June 30th would be 22.9%. And with that, I will turn it over to Steve.

Thanks, Kevin. Benchmark WTI prices averaged just over $94 for the second quarter, with dated Brent and LLS each pricing over $102 and $109 per barrel respectively. This quarter, dated Brent and LLS benchmarks served as the markers for more than 80% of our crude oil sales.

North American natural gas prices started the quarter with Henry Hub over $4, but eased off to the $3.75 range, with an average just over $4 for the quarter.

In US retail operations, fuel margins were bounded in the second quarter, averaging $0.156 per gallon. In addition, we saw strong contribution from the sale of RINs related to the blending ethanol into gasoline throughout our retail network.

In upstream business, we followed up on a solid first-quarter while exceeding our production guidance again in the second quarter, progressing all of our Malaysian oil projects as planned, continuing our growth in Eagle Ford Shale area, and we also closed on the sale of our last upstream property in the UK.

As to the planned spinoff of our US downstream business, and as we mentioned in our release yesterday, we have made substantial progress. We have announced the Murphy USA Inc. Board of Directors. The management team and organization are in place, up and running. We have received a ruling from the IRS confirming the tax-free status of the transaction. We're making good progress on our SEC filings. And Murphy USA is in the process of finalizing its capital structure.

Again, as we noted yesterday, our Board will consider this progress at its meeting next Wednesday, and we expect to announce the Board's conclusions shortly thereafter. The sales process for our UK downstream business continues, and we are actively engaged with several interested parties to divest those assets.

Roger, for an E&P update.

Thanks, Steve. Hello, everyone. In our exploration and global offshore business, we continue to focus in four areas -- the Deepwater Gulf of Mexico, the Atlantic margin, Southeast Asia, and Australia.

First, in Australia and the Browse Basin, our partnership group is drilling the Dufresne-1 well, where we hold a 20% working interest. The well is located approximately 35 kilometers west of the Bassett West well, which was expensed this quarter as noncommercial, with over 20 feet of net gas pay. We are continuing with work to evaluate the large Bassett structure. We anticipate results on the Dufresne well early in fourth quarter.

In Brunei, the partnership group plans to drill two prospects offsetting our recently announced Kelidang discovery in the fourth quarter, with results expected in quarter one of next year. The spud timing remains an uncertainty here and in most of our global operating areas, as a shortage of deepwater and high-capacity jackup rigs worldwide is pushing drilling schedules to the right.

We have made progress in adding acreage in Vietnam with the official signing of the shallow water Block 112PSC as 60% working interest. We are now shooting seismic in the block, and we hope this will lead to a well spud in 2014. We continue to work on increasing our footprint in Vietnam.

In the Atlantic margin, we spud our first deepwater well in Cameroon yesterday at Boning's number one well in the Elombo block. It should take approximately 45 to 60 days to drill and is testing both the Tertiary and Cretaceous age fan target, with a pre-drill gross resource estimate in the range of 300 million barrels.

The exploration well in the NTEM block is scheduled to be drilled with the same rig in early 2014 following a planned shipyard rig inspection. The pre-drill estimate for this well is in the range of 600 million barrels on a gross basis.

In offshore Equatorial Guinea and Block W, we plan to start 3D seismic program in quarter four. In Surinam, we finished shooting seismic on our block 48 and have an agreement to take on a partner to join us in this acreage position at 50% working interest.

In the Gulf of Mexico, remain very active in Gulf, especially in the Jurassic Norphlet Play. We have recently signed a foreman agreement with Marathon to participate in their Madagascar well and Block DeSoto Canyon 757 as a 30% working interest. The well is scheduled spud in September or October of this year.

In our Murphy-operated Titan prospect located in DeSoto Canyon 178, we have lowered our working interest from 70% to 50% in a promoted farm-out to Venari Resources.

The Titan prospect will be drilled with our new long-term contracted rig, the Transocean Discoverer Deep Seas, spudding in early quarter one next year due to continued rig delays with another operator.

We hope to take position of the rig in October and will immediately focus on our Dalmation development prior to the spud of Titan.

We are very excited about these -- about this two-well opportunity in the Gulf area that has some recent substantial success. The two wells will bookend the recent announced discoveries in the play. Both Madagascar and Titan have a gross mean resource estimate in the 150 million to 200 million barrel range.

Moving away from exploration into operations offshore. First, in Malaysia. Our deepwater projects offshore Sabah, Kikeh remains at planned production levels on the oil side despite some recent downtime events at the non-operated onshore methanol plant, where we deliver Kikeh-associated gas production.

We are still on schedule with planned shut-in of production during August and September to install production facilities associated with the Siakap North-Petai development, which will be tied to the Kikeh FPSO later this year.

At Siakap North-Petai, we are currently drilling the third of eight production wells, with the first of five water injection wells also drilled and completed. Drilling results to date have been to plan.

We're also progressing the facility work, and first oil is expected in early quarter four of this year. The Kakap-Gumusut early production system is producing at planned levels through the Murphy-operated Kikeh FPSO. The non-operated full field development is progressing to plan, with the permanent floating production system now moored on location and the production riser installation ongoing. Both major milestones toward achieving first oil this year.

We achieved the successful startup in first oil from the Serendah field in June 29 of this year, just 20 months from field development plan and approval. The project was executed on time and budget. The Serendah field and block SK 309 is located 45 kilometers offshore Bintulu, Sarawak, Malaysia, in 112 feet of water. The production facility has design capacity of up to 15,000 barrels of oil per day, with pipelines tied back to our existing oil and gas gathering infrastructure.

Oil is evacuated through the West Patricia FPSO, with associated gas being sold through our shallow water gas infrastructure, landing at our Bintulu onshore gas facility.

We have initially three wells online at a rate of 6500 gross and 4000 net barrel oil per day. We have an 85% working interest in the field, with our partner PETRONAS Carigali holding the remaining 15%.

This is the first of four shallow water oilfields that we plan to bring on this year. Development work at the three remaining projects — South Acis, Patricia, and Permas -- continued on plan, with the major milestone on South Acis achieved yesterday with the successful installation of the topsides.

Production starts for these projects are staggered through the remainder of the year.

Sarawak Gas production continues to be a steady performer, with strong realized prices in the range of $7 per Mcf in quarter two.

In addition to our for oil projects, we have also brought on production from the Mirapu gas field on July 15 as part of a long-term Sarawak gas development program, which will produce with contracted and certified volumes until 2022 and beyond.

In the Gulf of Mexico, development work at the Dalmatian deepwater tieback project is progressing on schedule, with first production slated in quarter one next year.

Now to our North American onshore business. First, in Eagle Ford Shale. We are currently running eight rigs and two frac units. We continue to focus on supply costs and seeing solid improvements in our operating expenses, with these costs showing a 33% improvement in quarter two over quarter one.

We have now drilled 308 wells in the play and have 255 wells on production. Production averaged 39,700 barrel oil equivalent net in quarter two, an increase of some 10,800 barrel oil equivalent per day over quarter one, with an oil weighting of 92%.

Production expected to continue to ramp up over the year.

Prices continue to be strong in the Eagle Ford Shale production with netback prices in quarter two averaging just over $100 per barrel.

We have two down-spacing projects, one project on the [Mankta] lease, and our Karnes field has six wells on a 40- to 60-acre spacing. We have brought five wells on production so far, and the initial total rate for the pad is 3280 barrel oil equivalent today -- per day at 88% oil. So we are very pleased with this result. The other down-spacing project, the 100% Tilden acreage in La Salle County at the Y-BAR lease, has 40-acre spacing, five wells; and we expect results in late August.

We are now formulating plans to use longer lateral wells across the play. One of our recent Karnes wells has a lateral length of over 6300 feet and has shown, as expected, a near 10% increase in EUR, with 30% improvement in initial rates. We're also working a long lateral project in Catarina, where we hope to drill laterals over 1000 feet in length that will dramatically lower well count, pad count, and will require less infrastructure, driving cost down.

In Pearsall Shale, we have approximately 45,000 acres in the play, with a focus area now of some 25,000. We plan to drill three additional delineation wells starting in the third quarter and extending into early next year.

We have hedged approximately 10,000 barrel oil per day of our Eagle Ford Shale production by forward selling Calgary [Monk] WTI at a price level of $101.55 per barrel through the end of this year and 10,000 barrels oil per day at average price of [9620] in the first half of 2014.

Up in Canada and Seal, we continue to focus primarily on EOR. Our first cyclic steam stimulation pilot in the [Kidat] area continues to go well. We completed the first injection production cycle, and so encouraging results with production increasing fivefold to over 100 barrels of oil per day. We are now injecting steam in the second cycle. In addition, we are preparing a second well for steam later this summer.

Our commercial polymer project continues on track. We are seeing good pressure response in phase 1. We started injecting polymer in the second-phase wells last December and expect to see a pressure response by year-end.

In the meantime, we're preparing the next group of wells for polymer injection by the end of the year.

Heavy crude netbacks improved in quarter two to near $50 per barrel, up from $28 in quarter one. We are continuing to take advantage of market opportunities in forward-sale heavy crude due to volatility in the market. We sold approximately 3000 barrel oil per day of our Seal heavy crude production July, August, and September at an average netback price of $54 per barrel.

In the Montney with ACO prices currently under CAD3, we are focused on evaluating liquids-rich area in the play, and we are now flow-testing two additional wells in the southeast edge of the play in early days of the well test here.

In addition, we recently received approval to expand the Tupper West Gas Plant from 180 million to 210 million cubic feet a day. Down the road, we hope to bring forward gas processing agreements from nearby competitors to continue to drive our costs down.

We continue to take advantage of gas-forward sales agreements in the Montney. We have close to 80 million sold at CAD3.75 for the rest of the year and 50 million a day sold of gas in 2014 at CAD4 per Mcf.

We see incremental hedging focusing on cost, bringing in liquids-rich areas, and working with nearby operators to process their gas at our facility is the game plan here going forward.

Second-quarter production averaged a little over 207 (Sic) barrel oil equivalent per day, exceeding our guidance level of 202,000 barrel oil equivalent per day, primarily attributed to continued strong performance in the Eagle Ford and higher volumes from Sarawak Gas.

Production guidance for quarter three is set at 190,000 barrel oil equivalent per day to reflect the planned shutdown attributable to our -- at are Kikeh FPSO in August and September, and the Siakap North-Petai project I just mentioned.

The fourth quarter will be strong with Kikeh back online, continuing growth at Eagle Ford and the Malaysia oil projects, both shallow and deepwater, coming on-stream. We are now increasing our yearly guidance to 203,000 barrel oil equivalent per day for the year.

I now want to turn it back over to Steve.

Thanks, Roger. US downstream business reported total net income of $77.9 million. RIN sales contributed $18.4 million of income at an average price of $0.78 per RIN credit. In a period of fluctuating wholesale markets, US retail margins were $0.156 per gallon for the second quarter, increasing from $0.11 per gallon in the first quarter. This was down from $0.197 per gallon in the second quarter last year, where we experienced a sharper fall in wholesale markets.

Merchandise sales totaled $553 million in the second quarter, an increase of $38 million from the first quarter of 2013 and $12 million year on year. Margins were relatively flat at 12.8% this quarter compared to 12.9% last quarter and down 13.4% from a year ago.

We added seven new retail stations this quarter, bringing our total count to 1179, with plans to end the year with over 1220 outlets.

In summary, then, the spinoff of our US retail business continues to move forward with key milestones achieved, and our Board of Directors will be meeting next week. In exploration, we only drilled one well in the second quarter, but have an active program for the rest of the year, with impactful prospects to drill offshore Cameroon, Australia, and the Gulf of Mexico.

Development work in our Malaysian projects is progressing well, with the first project at Serendah coming on-stream as planned.

And, lastly, we continue to deliver on our production targets.

With that we will now open up for questions. Operator.

(Operator Instructions). Leo Mariani, RBC.

Yes, just a question on the Eagle Ford. Sounds like you had a really big ramp-up in the second quarter. I guess, talked about 39,000 barrels a day and change. Where is that production currently?

Production today is around 45,000 Boe per day and probably in the near 90% oil range. Net to (multiple speakers).

Okay, all right. And I guess just in terms of number of wells, what is the plan for total number of wells in 2013? And would you happen to have the number of wells you brought on in both the first and the second quarter of '13?

Yes, I happen to have that. Just one second. We brought on 49 wells in the first quarter, 48 in the second. We're going to be probably tailing down in our current plan to have 41 in the third and 30 in the fourth because we have so efficient we have out-drilled our self -- worked ourself out of a job a little bit here. And we're trying to keep our capital in check, and we have less wells coming on end of the year.

Kind of front-loaded our CapEx there, Leo.

Okay. And I guess, obviously, that's a pretty good program. I guess, is that potentially to accelerate next year at all? How should we think about that?

I think it should maintain it. We have a strategy of being an E&P Explorer and offshore and complementary onshore business that we said many times. We're running about a $1.4 billion CapEx business here. I could say that -- trying to keep that the same at this point.

It is going to be (multiple speakers). I think it is 160 wells, Leo. It could be added up a little more than that, but that's around the number.

Okay. I guess, Seal, it looks like you guys saw a really nice increase in production at Seal during the quarter. Should we expect that to continue to trend higher for the rest of the year, or will that might plateau little bit?

Probably not. We had a fire in February, and we have recovered very well from that. We are probably a little ahead of our plans. I would imagine with the breakup system -- break up being pretty rough in Canada this year, no drilling -- we have no rigs today, and we don't have any rigs usually drop. It won't drop a whole lot, but I don't see the growth we had quarter one to quarter two continuing that out.

All right. So basically you're just watching your polymer pilot and your cyclic steam pilot. And if you get results there, might you accelerate those it all next year? How are you guys thinking about it?

Probably not. We have this $1.4 billion CapEx trying to get our self back to cash flow CapEx parity very -- really working that issue in our budget.

When you compare -- while we are excited about the EOR opportunity, we do have a long-range vision of price there. And it has been very volatile and very good at times. But the Eagle Ford is a pretty hot running card to play right now for us in our capital allocation.

Okay. In terms of the retail spend, I guess your Board's meeting next week. I guess my understanding was that you guys had already approved that. One way is the Board, so it sounds like maybe you are just making decisions on exact capital structure and amount of dividends -- dividend back to the parent, is that right? Am I missing anything?

Well, we hadn't -- the Board has not decided to actually do the spin, but we're moving in that direction. And I would like to answer that question the middle of next week.

Okay, understood. Makes sense. And I guess in terms of RINs, you talked about $18 million of income benefit this quarter. I guess prices are still strong. I guess we should expect to see continued incremental income from that for the rest of year. And I guess could you potentially highlight roughly what the cash flow impact is of the RINs?

Sure, Leo. This is Andrew Clyde. We have been doing 12 million RINs a month, and that is a consistent rate for our proprietary blending. We can buy more bulk barrels and blend more when the economics support it. But we look to continue to do around 12 million, conservatively, for the rest of the year.

All right. So any idea what that translates into in rough cash flow?

Not until I could predict RIN prices. So currently they're around $1, and we are selling ratably on a monthly basis. So we are blending and generating, capturing RINs of about 12 million a month, and we will be getting the market price on a ratable basis.

Okay. Thanks, guys.

Guy Baber, Simmons & Company.

Thanks for taking my question. I wanted to talk about production costs and your focus on margin improvement, but your US production costs seem to hit their lowest per-barrel level in about two years. And the Malaysian production costs this quarter hit their lowest level in three years, I believe.

So my question is, was there anything unique to this quarter that caused the costs to be abnormally low? And then also could you maybe just elaborate on efforts to continue to reduce OpEx, and what the per-barrel trajectory might be for some of your key assets in the US and in Malaysia to the end of this year and into next year?

Okay. First, just some general comments on that. On the offshore, probably up a little bit this quarter to the first, and that number will probably be fairly consistent throughout the year. Big improvement in our Eagle Ford Shale. We're in the $15 range per Boe, which is a big improvement. That was due to the big ramp-up and building of facilities and more concentrating of the build-out of all of our equipment and less rental equipment.

I would see that drifting down in [tennings] throughout the year on down into the $14 level in the fourth quarter. I don't see it making these continued giant improvements.

Over in Malaysia, we did have a one-time credit. We sell condensate -- condensate, or NGLs, come off of the gas project in Malaysia at the Sarawak Gas. And we've had been accruing a certain level of operating expenses in the long-term negotiation with our partner there, PETRONAS, and received a credit -- a one-time credit for this quarter, bringing that down in that business slightly.

In the next quarter in Malaysia, we'll be up again we have this Kikeh shut in. And we shut in Kikeh with a leased FPSO; you anticipate operating expenses to go up.

And then we get back into where we are -- where we were at the first quarter in Malaysia toward the end of the year.

Okay, very helpful. And then I was hoping you could also just touch on Gulf of Mexico volumes. Really how you see your basin's performing. But I noticed in some of the charts that you are not really building in any decline to the base in the Gulf of Mexico over the next couple of years. So just looking for some detail on how that basin is performing now and what type of activity is going on right now for you to mitigate any declines you might see there.

Well, we have around a 15,000 barrel-a-day business; not having a very good year in the Gulf, quite frankly. Had some operational problems and rig delays here and there. About a 15,000 barrel-a-day business would be declining on base, but we have the Dalmatian project coming on next year. It is quite prolific; almost the same size of what we are producing to date net. That is on schedule to come on in the first quarter.

And later, from there, we have the Medusa subsea development where we -- Medusa is one of our better fields in the Company, one of the better margins in the Company; very nice field. It is still producing its original wellbores, so we're unable to produce some success. We have up the hole, if you will. We need to put in some subsea equipment working with our partners to gain that approval. And that should work into '15, kind of maintaining that Gulf of Mexico and that toward-the-20s kind of a business until we have hopefully a discovery, Guy.

Okay, great. Thanks for the comments, guys, and congrats on the quarter.

Blake Fernandez, Howard Weil.

I had a couple questions for you. One is on the hedging strategy. I know historically you have had some gas hedges in place. But if I'm not mistaken, this is a bit new to have the oil hedges in place. I am just curious if you could talk a little bit about the strategy there, if this is kind of a one-off call on commodity prices being elevated or if this is a function of the potential retail spin, and the idea that you're going to have more volatile earnings stream going forward?

No, I don't believe that latter is the case. I think when you look -- I am a benchmarker, Blake; I benchmark everything to my competitors -- OpEx, DD&A, you name it. Primarily, most of our competitors are probably -- have hedge positions for 25% to 30% of their barrel oil equivalent, especially in the oil side.

We, of course, have been a very low-debt player compared to our competitors in that type situation. But we have taken on some debt on a net debt basis, still very low. We do have some US debt. We have a very good business in the Eagle Ford that we want to maintain, our certain level of capital.

We are working a strategy to hedge or forward-sell, if you will, about this level of production. I don't see us going over 25%, and we saw an opportunity when the market had shot up ahead of what we have in our budget. And I took a small position there.

I don't think of us as increasing at a whole lot. I don't think of us as becoming a big hedge player. I thought it was remiss to not have any hedge position at all in our business, protecting cash flow in the US, where we want to run with $1 billion-plus budget if we can because it is going very well for us.

Okay, fair enough. And then on the Eagle Ford, I guess I had maybe two separate questions. One, Roger, you said you are currently producing around 45,000 barrels a day. Could remind us what your quote unquote peak estimate is? And then, secondly, on M&A, it sounds like you're focused on about 25,000 acres. There is obviously some other packages out there being marketed. I am just curious if you see an opportunity to maybe core up a bit. Obviously, prices are well above what you originally paid, but it seems like maybe you could build out some additional running room.

First, on the Eagle Ford, we had a pretty high rate today. You know, it's a big, complicated business. A lot of things running. We do have running in through some pad shut-ins, where we shut in production to frac nearby wells, et cetera. So we're probably going to be in the low 40s and probably an increase in my mind of around 3000 something Boe a quarter going forward for the next couple of quarters at play. People have tricked me on the daily question to get at the guidance all the time. I failed to answer that accurately.

On your other question about Piersall, we have a very good one well and a very mediocre second well. We're fitting in some wells. I think for us to do a deal or to look to do that, we need a little more information. And so we have strategically picked two or three spots. We're going to drill between now and the first quarter of '14. I think that would be the time to have kind of discussion.

Okay. The last question I had -- I'm not sure if this would be Steve or someone else, but can you -- if I recall the working capital on Milford Haven was about $500 million. I was hoping if you could confirm that it is still in that range. And then, secondly, if you had any estimate at all on what it may cost to actually just close that facility and walk away.

Well, that $500 million is -- remains still in the range. And, no, I really don't have any estimate it would take to close it.

Okay. Thanks, guys.

Ray Deacon, Brean Capital.

Roger, I had a benchmarking question about the marketing side. I guess if you look at the retail margin and the gasoline margin in the quarter, where do you think that would stack up relative to your peers?

Hold up there, Ray. I am an upstream guy, but I got a downstream guy right here with me.

So our margin on fuel for the quarter just ended was $0.156 per gallon. Most of our peers -- I would say we are taking a lower price position on the street day in, day out. That is why we target our customers in front of Walmart. So we would expect to have, on average, lower margins. That said, some of our competitors buy branded fuel and they have a higher cost of goods sold, where we are buying on the spot market and typically buying at a lower cost of goods. So you would have to go through and make those adjustments apples to apples, who has got the lowest cost of goods sold.

We are typically going to be in that space, but we're also going to have, on average, lower street prices than most of our public comps.

Got it, got it. Great. And I guess, Roger, one more question. I guess in terms of your thinking on 2014, few months past the analyst meeting, I guess has there been any shifting in your mind in terms of capital based on either seismic and Vietnam, or I guess anything else?

Our seismic is lumpy like any global explorer. Our CapEx that we had, just for the upstream business, should be the same as AGM, pretty close. We have to add on, of course, the corporate part of us being alone at that time, with that presentation didn't include.

But you know, a $400 million to $500 million a year type exploration program among all the types of exploration both seismic and wells -- that is our goal. Quite frankly, it is tougher to deliver. A lot of the rigs are late. A lot of the rigs are going to the right. Rigs we're waiting to receive from others. But, in general, that's the goal, and I see us headed in that same direction now.

Got it, great. Thank you.

(Operator Instructions). Pavel Molchanov, Raymond James.

Thanks for squeezing me in. First, on the comment you guys made about the Board has not yet made a decision on the retail spinoff. Is that just a formality at this point, or is there actually some viable course of action that you're contemplating besides a spinoff?

Well, you know, I don't want to characterize any Board decision as pro forma. But again, ask that question next week, and I think we will be prepared to answer it for you.

Okay, understood.

Okay?

On the Dufresne prospect, if I am pronouncing that right in Australia, do you have a pre-drill estimate for that?

Yes it is -- hang on one second, I got it right here in my notes. We have had it in our AGM. It should be the same, but it's 2 to 2.8 TCF gross, which would be 0.4 to 0.6 Tcf for Murphy there.

Okay, and who is the operator there?

Total.

Total. Okay. Thanks very much.

Guy Baber, Simmons & Company.

Thanks for taking the follow-up. I wanted to ask about the Kakap-Gumusut field development project. Pretty important for you all for your 2014 targets. Can you just provide a little bit more detail around confidence levels around start-up timing? And then also is that expected to ramp to peak capacity through the course of 2014? Any more color you can put on that would be helpful.

Yes, I feel better about it, Guy, because we -- the facility is offshore. And when you're in the deepwater development business, first step is getting offshore. It is offshore; it is moored. The production risers are being installed. There is eight to 10 -- I forget the count -- producing wells in the field. Two of which are flowing to our facility now. The wells are a common type completion technology. We have flowed them now for several months, almost a year. We have good success and very high rates from the wells. The wells are very prolific. So, to me, the start-up before the end of the year is very much there. And Barry has got the guidance for '14, and I will let him speak to that. But I feel good about the project coming forward. You can look on the horizon and see it today from our facility which is good.

And, Guy, just going back to analyst day numbers, which I will balance to here. Next year, we were showing at just a shade under 10,000 barrels a day our share, with '15 picking it up in the 14,000 range. So there is a still a little bit of growth into '15 from '14 as everything comes on.

Thanks, guys.

Evan Calio, Morgan Stanley.

Just a couple of quick ones for me. Any update on the potential return of the Syncrude upgrader from unplanned maintenance? I thought that should be back in early August.

It's supposed to be in August, and that's what we have been told and planning on that cautiously, I say. But that is what (multiple speakers). You're right.

Understood. And I know you mentioned progress on UK and [R&M] sale. Yet, any timing expectation -- final sale there for 2013? I know that has been going on for a while now.

It's been going on for a great long time. And for that reason, I think I'm going to decline to give you an estimate. I think when we have something to disclose. We will -- you'll hear a good shout of great joy from all the way from wherever you are.

We will hear it in New York, right? And I guess additionally on that asset sale, do you think about those proceeds as potential reload for the buyback? Or, as you pull more into free cash flow neutrality?

Well, we will certainly look at -- this is Kevin -- once that deal -- and we will certainly look at what our options are, and all of those would be on the table. We will just see exactly what the timing is and where we are at that point in time. You got to remember, I got to bring that money back from overseas, so I could have some time depending on just how it all works out.

Right, understood, understood. And lastly, on Cameroon, what is the -- what do you estimate the commercial threshold for that prospect is? I know -- I think you mentioned the P50 was 300 million barrels.

I would imagine that anything around 100 million in a range of one-off place like that should work. We have to be very careful at the delineation and not over-delineate at that size to get your F&D too high. But it would be -- these wells are not expensive to drill like a Gulf well, so hopefully it would be that type of size in my mind.

Good. Appreciate it, guys. Thanks.

(Operator Instructions). It appears there are no further questions at this time. Mr. Steven Cosse, I would like to turn the conference back to you for any additional or closing remarks.

Thanks. I would just to thank everyone one more time for participating in our call. We particularly enjoyed this conference call, as we would with any good quarter as we recently reported. But stay tuned. We expect to have some announcements probably as early as next week. So, again, thank everyone for participating.

And that does conclude today's conference. We thank you for your participation.