Aug 1, 2013
Executives
Steven A. Cossé - Chief Executive Officer, President, Director, Member of Executive Committee and Member of Environmental, Health & Safety Committee Barry Jeffery - Director of Investor Relations Kevin G.
Fitzgerald - Chief Financial Officer, Executive Vice President and Vice President of Murphy Oil Company Ltd Roger W. Jenkins - Chief Operating Officer, Executive Vice President and President of Murphy Exploration & Production Company R.
Andrew Clyde - Chief Executive Officer and President
Analysts
Leo P. Mariani - RBC Capital Markets, LLC, Research Division Guy A.
Baber - Simmons & Company International, Research Division Blake Fernandez - Howard Weil Incorporated, Research Division Raymond J. Deacon - Brean Capital LLC, Research Division Pavel Molchanov - Raymond James & Associates, Inc., Research Division Evan Calio - Morgan Stanley, Research Division
Operator
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 Cossé, President and Chief Executive Officer.
Please go ahead, sir.
Steven A. Cossé
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, our Executive Vice President and Chief Financial Officer; Andrew Clyde, who's a 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, Investor Relations. Barry?
Barry Jeffery
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 attained.
A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2012 Annual Report on Form 10-K filed with the SEC.
Murphy takes no duty to publicly update or revise any forward-looking statements. I'll now turn the call over to Kevin.
Kevin G. Fitzgerald
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 6 months ended June 30, 2013, we had net income of $763.2 million or $4 per diluted share, compared to net income for the first 6 months of last year of $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 6-month period 2013 included an 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. The increases in the 2013 income for discontinued operations resulted primarily from gains on the sales of all E&P properties in the U.K.
From continuing operations, we had income in the second quarter of 2013, $332.1 million or $1.75 per diluted share compared to income from continuing ops the second quarter of 2012 of $291.3 million or $1.50 per diluted share. For the 6 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 6 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 of oil production in the Eagle Ford Shale area. Looking at income by segment.
In E&P, we had income from continuing operations in the second quarter of $290.2 million compared to income from continuing operations, 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 U.S.
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 of Sarawak, Malaysia.
In the R&M segment from continuing operations, we had income in the second quarter of 2013 of $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 U.K.
In the corporate segment, second quarter 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 increased 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 through the completion of a second $250-million accelerated share repurchase program.
The total number of shares we've repurchased under the authorization approved by our board last October is 8,044,378 shares at an average price of $62.16 per share. As of June 30, 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 30 would be 22.9%.
And with that, I'll turn it over to Steve.
Steven A. Cossé
Thanks, Kevin. Benchmark WTI prices has 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 a $3.75 range with an average just over $4 for the quarter.
In U.S. Retail operations, fuel margins rebounded in the second quarter, averaging $0.156 per gallon.
In addition, we saw a strong contribution from the sale of RINs related to the blending of ethanol into gasoline throughout our retail network. In upstream business, we've followed up on a solid first quarter by exceeding our production guidance again in the second quarter, progressing all of our Malaysian oil projects as planned, continuing our growth in the Eagle Ford Shale area.
And we also closed on the sale of our last upstream property in the U.K. After the planned spinoff of our U.S.
downstream business, and as we mentioned in our release yesterday, we've made substantial progress. We've announced the Murphy USA Inc.
Board of Directors, the management team and organization are in place, up and running, we've received a ruling from the IRS confirming a tax-free status of the transaction. We're making good progress on our SEC filing.
And Murphy USA is in the process of finalizing its capital structure. Again, as we noted yesterday, our board was 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 U.K.
downstream business continues and we're actively engaged with several interested parties to divest those assets. Roger, for an E&P update?
Roger W. Jenkins
Thank you, Steve. Hello, everyone.
In our exploration and global offshore business, we continue to focus on 4 areas, the big water Gulf of Mexico, the Atlantic Margin, Southeast Asia and Australia. First, in Australia, in 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 is expensed this quarter as noncommercial with over 20 feet of net gas pay. We're continuing with work to evaluate the large Bassett structure and anticipate results on the Dufresne well early in the fourth quarter.
In Brunei, the partnership group plans to drill 2 prospects, offsetting a recently announced Kelidang discovery in the fourth quarter with results expected in quarter 1 of next year. The spud timing remains uncertain here and in most of our global operating areas, as a shortage of deep water and high-capacity jack-up rigs worldwide is pushing drilling schedules to the right.
We've made progress and added acreage in Vietnam with the official signing of the shallow water Block 11-2 PSC at 60% working interest. We're now shooting seismic on 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 deep water well in Cameroon yesterday.
The Boning [ph] #1 well in the Elombo Block, should take approximately 45 to 60 days to drill, and is testing both the tertiary and Cretaceous age sand target with a predrill 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 predrill estimate for this well's in the range of 600 million barrels on a gross basis. In offshore Equatorial Guinea in block "W", we plan to start 3D seismic program in quarter 4.
In Suriname, 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, we remain very active in the Gulf especially in the Jurassic Norphlet Play.
We have recently signed a formal agreement with Marathon to participate in their Madagascar well in Block DeSoto Canyon 757 at a 30% working interest. The well is scheduled to 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 the Nori [ph] resources. The Titan prospect will be drilled with our new long-term contracted rig, the Transocean Discoverer Deep Seas, is spudding in early quarter 1 next year due to continued rig delays with another operator.
We hope to take possession of the rig in October and will immediately focus on our Dalmatian development prior to the spud of Titan. We're very excited about this 2-well opportunity in the Gulf area that has some recent substantial success.
The 2 wells will bookend the recently 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 to 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 nonoperated 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're currently drilling the third of 8 production wells, with the first of 5 water injection wells also drilled and completed.
Drilling results to date have been to plan. We're also progressing facility work and first oil is expected in early quarter 4 of this year.
The Kakap-Gumusut early production system is producing at planned levels through the Murphy operative Kikeh FPSO. The nonoperated full field development's progressing to plan with the permanent floating production system now moored on location and the production riser installation ongoing, both major milestones towards achieving first oil this year.
We've achieved a successful startup in the 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 a 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 blending in our Bintulu onshore gas facility. We have initially 3 wells online at a rate of 6,500 gross and 4,000 net barrels of 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 4 shallow water oil fields that we plan to bring on this year.
Development work at the 3 remaining projects, South Acis, Patricia and Permas, continued on plan, with a major milestone in South Acis achieved yesterday with the successful installation of the top sides. 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 2. In addition to our 4 oil projects, we have also brought on production from the Merapu [ph] gas field on July 15 as part of our long-term shale light 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 tie-back project is progressing on schedule, with first production slated in quarter 1 next year. Now to our North American onshore business, first in Eagle Ford Shale.
And we're currently running 8 rigs and 2 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 2 over quarter 1.
We've now drilled 308 wells in the play and have 255 wells on production. Production averaged 39,700 barrel of oil equivalent net in quarter 2, an increase of some 10,800 barrel of oil equivalent per day over quarter 1, with an oil waiting of 92%.
Production's expected to continue to ramp-up over the year. Prices continue to be strong in the Eagle Ford Shale production with net back prices in quarter 2 averaging just over $100 per barrel.
We have 2 down spacing projects, one project on the [indiscernible] in our Karnes field has 6 wells on a 40- to 60-acre spacing. We brought 5 wells on production so far and the initial total rate for the pad is 3,280 barrel of oil equivalent today per day at 88% oil, so we're very pleased with this result.
The other down spacing project, the 100% Tilden acreage in Nassau County [ph] at the Y-bar lease [ph] has 40-acre spacing and 5 wells, and we expect results in late August. We're now formulating plans to use longer lateral wells across the play.
One of our recent rigs Karnes Wells has a lateral length of over 6,300 feet and has shown, as expected, a near 10% increase in EOR with 30% improvement in initial rates. We're also working a long-lateral project in Catarina that we hope to drill laterals over 8,000 feet in length that would dramatically lower well count, pad count and will require less infrastructure, driving costs down.
In the Pearsall Shale, we've approximately 45,000 acres in the play with a focus area now of some 25,000. We plan to drill 3 additional delineation wells starting in the third quarter and extending into early next year.
We have hedged approximately 10,000 barrels of oil per day of our Eagle Ford Shale production by forward selling Calgar Monte [ph] WTI at a price level of $101.55 per barrel through the end of this year, and 10,000 barrels of oil per day at an average price of $96.20 in the first half of 2014. Up in Canada, in Seal, we continue to focus primarily on EOR.
Our first cyclic steam stimulation pilot in the Cadotte area continues to go well. We completed the first injection production cycle and saw encouraging results with production increasing fivefolds over 100 barrels of oil per day.
We're now injecting steam in the second cycle. In addition, we're preparing a second well for steam later this summer.
Our commercial polymer project continues on track. We're seeing good pressure response in Phase 1.
And we started injecting the polymer in the second phase wells last December and expect to see 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 2 to near $50 per barrel, up from $28 in quarter 1. We continue to take advantage of market opportunities and forward sell heavy crude due to volatility in the market.
We sold approximately 3,000 barrels of oil per day of our Seal heavy crude production in July, August and September at an average net back price of $54 per barrel. In the Montney, with AECO prices currently under CAD 3.
We're focused on evaluating liquids-rich area in the play and we are now float testing 2 additional wells in the southeast edge of the play and 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, because 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, with close to 80 million sold at CAD 3.75 for the rest of the year and 50 million a day sold of gas in 2014 at CAD 4 per MCF. We're seeing incremental hedging, focusing on costs, 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 barrel of oil equivalent per day, exceeding our guidance level of 202,000 barrel of oil equivalent per day, primarily attributed to continued strong performance in the Eagle Ford and higher volumes from Sarawak gas. Production guidance for quarter 3 is set at 190,000 barrel of oil equivalent per day to reflect the planned shutdown to our -- at our Kikeh FPSO in August and September at the Siakap North/Petai project I just mentioned.
The fourth quarter will be strong with Kikeh back on line, continuing growth at Eagle Ford and the Malaysia oil projects, both shallow and deepwater, coming onstream. We're now increasing our yearly guidance to 203,000 barrel of oil equivalent per day for the year.
For now, I want to turn it back over to Steve.
Steven A. Cossé
Thanks, Roger. The U.S.
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, U.S. retail margins were $0.156 per gallon for the second quarter, increasing from $0.11 per gallon in the first quarter.
This is 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 7 new retail stations this quarter, bringing our total count to 1,179 with plans to end the year with over 1,220 outlets.
In summary then, the spinoff of our U.S. 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 1 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 on our Malaysian projects is progressing well with the first project at Serendah coming onstream as planned.
And lastly, we continue to deliver on our production targets. With that, we'll now open up for questions.
Operator?
Operator
[Operator Instructions] We'll take our first question from Leo Mariani from RBC.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Just a question on the Eagle Ford. Sounds like it 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?
Roger W. Jenkins
Production today is around 45,000 BOE per day and kind of near 90% oil range.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay. All right.
And I guess, just in terms of your number of wells, what's 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 second quarter of '13?
Roger W. Jenkins
Yes, I happen to have that, just one second. Brought on 49 wells in the first quarter, 48 in the second.
We're going to be probably tailing down our current plan to have 41 in the third and 30 in the fourth because we've so efficient, we've out drilled ourselves, worked ourselves 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. And we kind of frontloaded our CapEx there, Leo.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay. And I guess, obviously, that's a pretty good program.
I mean, I guess, is that potentially to accelerate next year at all? How should we think about that?
Roger W. Jenkins
I think it should maintain it. I mean 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'd see that trying to keep that the same at this point. There's going to be -- I think 160 wells, Leo.
Could be add up a little more than that, but it's around that number.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay. I guess Seal, looks like you guys saw a really nice increase in production at Seal during the quarter.
Should we expect that to kind of continue to trend higher for the rest of the year or that might plateau a little bit?
Roger W. Jenkins
Probably not. We had a fire in February and we've recovered very well from that.
We're probably a little ahead of our plans. I would imagine with the breakup system, breakup being pretty rough in Canada this year, no drilling, we have no rigs today.
And we don't have any rigs, usually dropped. It won't drop a whole lot, but I don't see the growth we had quarter 1 to quarter 2 continuing that out.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
All right. So basically just watching your polymer pilot, and you stick with the steam pilot, and if you get results there, might you accelerate those at all next year?
How are you guys thinking about it?
Roger W. Jenkins
It's probably not. We have this $1.4 billion CapEx, trying to get ourselves into back to cash flow CapEx parity very -- really working that issue in our budget.
When you compare -- while we're excited about the EOR opportunity, we do have a long-range vision of price there, and it's been a very volatile and very good at times. But Eagle Ford's a pretty hot running card to play right now for us in our capital allocation.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay. In terms of retail spin, I guess your board's meeting next week.
I guess, my understanding was that you guys have sort of already approved that formally as a board, so it sounds like maybe you're just making decisions on the exact capital structure and amount of dividend to do, then back to the parent. Is that right?
Am I missing anything?
Steven A. Cossé
Well, we hadn't met. The board has not decided to actually do the spin.
But we're moving in that direction. And I'd like to answer that question the middle of next week.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay, understood. Makes sense.
And I guess in terms of RIN, 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 the year. And I guess could you potentially highlight, roughly, what the cash flow impact is of the RINs?
R. Andrew Clyde
Certainly, this is Andrew Clyde. We've been doing 12 million RINs a month and that's a consistent rate for our proprietary blending.
We can buy more bulk barrels and blend more when the economics support it. But we'd look to continue to do around 12 million conservatively for the rest of the year.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Alright. And so, Andrew, that translates into sort of rough cash flow?
R. Andrew Clyde
Not until I could predict RIN prices. So currently they're around $1, and we're selling ratably on a monthly basis.
So we're blending and generating, capturing RINs of about 12 million a month and we'll be getting the market price on a ratable basis.
Operator
And we'll take our next question from Guy Baber with Simmons & Co.
Guy A. Baber - Simmons & Company International, Research Division
I wanted to talk about production costs and your focus on margin improvement. But your U.S.
production costs seem to hit their lowest per barrel level in about 2 years and the Malaysian production costs this quarter hit their lowest level in 3 years, I believe. So my question is was there anything unique to this quarter that caused the cost 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 U.S. and in Malaysia to the end of this year and into next year?
Roger W. Jenkins
Okay. First, just some general comments on that.
In 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 the building of facilities and more concentrating of the buildout of all of our equipment and less rental equipment.
I would see that drifting down in pennies throughout the year, 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 onetime credit. We sell condensate.
Condensate are NGLs come off with 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 onetime credit for this quarter, bringing that down in that business slightly.
And then in the next quarter in Malaysia, we'll be up. Again we have this Kikeh shut-in.
And when you shut in Kikeh with a leased FPSO, you anticipate operating expenses to go up. So -- and then we'll get kind of back into where we are -- where we were at the first quarter in Malaysia toward the end of the year.
Guy A. Baber - Simmons & Company International, Research Division
Okay. Very helpful.
And then I was hoping you could also just touch on Gulf of Mexico volumes, really, how you see your base performing. But I noticed in some of the charts that you're 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 base is forming now and what type of activity is going on right now for you to mitigate any declines you might see there.
Roger W. Jenkins
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's quite prolific, almost the same size of what we're producing today net.
That's on schedule to come on in the first quarter. And later from there, we have the Medusa subsea development where we -- Medusa's one of our better fields and becoming one of the better margins in the company, a very nice field.
It's still producing it's original wellbores. So we're unable to produce some success.
We have upped the hole, if you will. We need to put in some subsea equivalent, 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 a, hopefully, a discovery guy.
Operator
And we will take our next question from Blake Fernandez with Howard Weil.
Blake Fernandez - Howard Weil Incorporated, Research Division
I had a couple of questions for you. One is on the hedging strategy.
I know historically you've 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'm just curious, if you could talk a little bit about the strategy there?
If this is a 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?
Roger W. Jenkins
No, I don't believe that latter's the case. I think when you look -- I'm a benchmarker, Blake.
I benchmark everything to my competitors' OpEx, DD&A, you name it. Primarily, most of our competitors are probably -- have hedged positions for 25% to 30% of their barrel of oil equivalent, especially on 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 U.S. 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 our forward sale, if you will, about this level of production.
I don't see us going over 25%. And we saw an opportunity when the market 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 it 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 U.S. where we want to run with a $1 billion-plus budget if we can, because it's going very well for us.
Blake Fernandez - Howard Weil Incorporated, Research Division
Okay, fair enough. And then on the Eagle Ford, I guess I had maybe 2 separate questions.
One, Roger, you said you're currently producing around 45,000 barrels a day. Could you remind us what your kind of "peak estimate" is?
And then secondly, on M&A, I mean, it sounds like you're focused on about 25,000 acres. There's obviously some other packages out there being marketed.
I'm 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?
Roger W. Jenkins
First on Eagle Ford. We had a pretty high rate today.
It's a big complicated business, a lot of things running. We do have, running into 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 3,000-something BOE a quarter going forward for the next couple of quarters, Blake. People trick me on the daily question to get at the guidance all the time.
I failed to answer that accurately. On your other question about Pearsall, we have a very good 1 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've strategically picked 2 or 3 spots that we're going to drill between now and the first quarter of '14. I think that would be the time to have that kind of discussion.
Blake Fernandez - Howard Weil Incorporated, Research Division
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 kind of confirm that it's still in that range?
And then secondly, if you had any estimate at all what it may cost to actually just close that facility and walk away?
Steven A. Cossé
Well that $500 million is -- remains still in the range. And, no, I really don't have any estimate what it would take to close it.
Operator
And we'll take our next question from Ray Deacon with Brean Capital.
Raymond J. Deacon - Brean Capital LLC, Research Division
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'?
Roger W. Jenkins
Hold up there, Ray. I'm an upstream guy, but I got a downstream guy right here with me.
Unknown Executive
Well, 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 and day out.
That's where 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 pay -- have a higher cost of goods sold, where we're buying on the spot market and typically buying at a lower cost of goods. So you would have to go through to make those adjustments apples-to-apples, who's got the lower cost of goods sold.
We're typically going to be in that space. But we're also going to have, on average, lower street prices to most of our public comps.
Raymond J. Deacon - Brean Capital LLC, Research Division
Got it. Got it.
Great. And I guess, Roger, one more question, I guess, in terms of your thinking on 2014, a few months past the Analyst Meeting.
I guess, has there been any shifting in your mind in terms of capital based on either seismic in Vietnam or, I guess, anything else or...
Roger W. Jenkins
No, it's [indiscernible] 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, which our presentation didn't include. But a $400-million- to $500-million-a-year type exploration program among all the types of exploration, both seismic and wells, that's our goal.
Quite frankly, it's tougher to deliver. A lot of rigs are late, a lot of 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.
Operator
[Operator Instructions] And we'll take our next question from Pavel Molchanov with Raymond James.
Pavel Molchanov - Raymond James & Associates, Inc., Research Division
First, on the comment you guys made about the board has not yet made a decision on the retail spin off. Is that just a formality at this point, or is there actually some viable course of action that you're contemplating besides a spin-off?
Steven A. Cossé
Well, I don't want to characterize any board decision as sort of pro forma but ask again. Ask that question next week and I think we'll be prepared to answer it for you.
Pavel Molchanov - Raymond James & Associates, Inc., Research Division
Okay, understood. On the Dufresne prospective, if I'm pronouncing that right, in Australia.
Do you have a predrill estimate for that?
Roger W. Jenkins
Yes, it's -- hang on one second. I got it right here in my notes.
We've had it in our AGM. It should be the same, but it's 2 to 2.8 TCF gross, which should be 0.4 to 0.6 TCF for Murphy there.
Pavel Molchanov - Raymond James & Associates, Inc., Research Division
Okay. And who's the operator there?
Roger W. Jenkins
Total.
Pavel Molchanov - Raymond James & Associates, Inc., Research Division
Total, okay.
Operator
And we'll take our next question from Guy Baber with Simmons & Co.
Guy A. Baber - Simmons & Company International, Research Division
I wanted to ask about the Kakap-Gumusut full field development project. Pretty important for you all, for your 2014 target.
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 could put on that will be helpful.
Roger W. Jenkins
Yes, I feel better about it, Guy, because we -- the facility is offshore. And when you're in a deepwater development business, first step is getting them offshore.
It's offshore. It's moored.
The production risers are being installed. There's like 8 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 flowed them now for several months, almost a year. We have good success, some 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's got the guidance for '14 and I'll 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.
Barry Jeffery
And, Guy, just going back to Analyst Day numbers, which I'll balance to here. Next year, we were showing at just a shade under 10,000 barrels a day our share, with '15 taking it up in the '14 range.
So there's still a bit of growth into '15 from '14 as everything comes on.
Operator
And we'll take our next question from Evan Calio with Morgan Stanley.
Evan Calio - Morgan Stanley, Research Division
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.
Roger W. Jenkins
It's supposed to be in August. And that's what we've been told and planning on that cautiously, I'll say.
But that's what we planned. You're right.
Evan Calio - Morgan Stanley, Research Division
Understood. I know you mentioned progress on U.K.
asset sale yet. Any timing expectation, final sale there for 2013?
I know that's been going on for awhile now.
Steven A. Cossé
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, if we have something to disclose, we'll -- you'll hear a great shout of great joy from -- all the way from here to wherever you are.
Evan Calio - Morgan Stanley, Research Division
And I guess, additionally on that asset sale. I mean, do you think about those proceeds as a potential reload for the buyback?
Or exit [ph] as you pull more into free cash flow neutrality?
Kevin G. Fitzgerald
Well, we certainly look at it. This is Kevin.
Once that deal ends, we'll certainly look at what our options are, and all of those would be on the table. We'll just see exactly what the timing is and where we are at that point in time.
You got to remember, I've got to bring that money back from overseas, so I could have some time depending on just how it all works out.
Evan Calio - Morgan Stanley, Research Division
Well, great. 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?
Roger W. Jenkins
I imagine [indiscernible] around 100 million in a rank one-off place like that should work. That's very careful 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'll be that type of size in my mind.
Operator
[Operator Instructions] It appears there are no further questions at this time. Mr.
Steven Cossé, I'd like to turn the conference back to you for any additional or closing remarks.
Steven A. Cossé
Thank you. I'd just thank everyone one more time for participating in our call.
We have 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, I thank everyone for participating.
Operator
And that does conclude today's conference. We thank you for your participation.