Murphy Oil's (MUR) CEO Roger Jenkins on Q2 2014 Results - Earnings Call Transcript

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 |  About: Murphy Oil Corporation (MUR)
by: SA Transcripts

Operator

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation Second Quarter 2014 Earnings Call. Today's call is being recorded.

I would now like to turn the call over to Mr. Barry Jeffery, Vice President, Investor Relations. Please go ahead.

Barry F.R. Jeffery

Good afternoon, everyone, and thank you for joining us on our call today. With me are Roger Jenkins, President and Chief Executive Officer; Kevin Fitzgerald, Executive Vice President and Chief Financial Officer; and John Eckart, Senior Vice President and Controller.

We've posted a few informational slides on the Investor Relations section of our website that you can follow along with as part of the webcast today. Today's call will follow our usual format. Kevin will begin by providing a review of second quarter 2014 results. Roger will then follow with an operational update, after which, questions will be taken.

Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2013 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 2014 is $129.4 million or $0.72 per diluted share. This compares to the net income in the second quarter of last year of $402.6 million or $2.12 per diluted share. For the first 6 months of 2014, we had net income of $284.7 million or $1.57 per diluted share. This compares to income -- net income for the first 6 months of last year of $763.2 million or $4 per diluted share.

This year's second quarter included a loss of discontinued operations of $13.3 million or $0.07 per diluted share compared to income of $142.8 million or $0.75 per diluted share for the same period last year. For the 6-month period, 2014 included a loss from discontinued operations of $27.3 million, $0.15 per diluted share compared to income of $320.7 million or $1.69 per diluted share in 2013.

Our income from continuing operations in the second quarter of this year is $142.7 million or $0.79 per diluted share compared to income in the second quarter of last year of $259.9 million, $1.37 per diluted share. Income from continuing ops for the 6 months of 2014 is $312 million or $1.72 per diluted share compared to the 6 months of 2013, $442.6 million or $2.32 per diluted share.

Looking at income by segments. On the E&P segment for the second quarter of 2014, we had net income of $200.8 million compared to $290.2 million for the second quarter of last year. Lower E&P earnings for the 2014 quarter were mostly attributable to higher exploration expenses, higher extraction cost in Malaysia, lower realized sales prices for our production in Sarawak and unfavorable effects from commodity contracts.

Crude oil and gas liquids production for the current quarter was approximately 139,000 barrels per day as compared to approximately 136,000 barrels per day in the 2013 quarter, with the increase mostly attributable to higher production in Eagle Ford Shale, partially offset by reduced volumes in Canada.

Natural gas sales volumes averaged 425 million cubic feet per day in the second quarter of this year compared to 431 million cubic feet per day in the second quarter of 2013. The decrease was attributable to lower volumes at the Tupper area in British Columbia and from fields also -- offshore Sarawak, Malaysia, partially offset by increased productions from the Eagle Ford and from the startup of the Dalmatian field in the Gulf of Mexico.

In the corporate for the second quarter of '14, we had net charges of $58.1 million compared to net charges of $30.3 million in the second quarter last year. These increased costs primarily related to unfavorable effects from foreign exchange transactions and higher financing cost.

During the second quarter of this year, we completed the accelerated share repurchase program we got in the first quarter, and retired an additional 123,380 shares over that previously reported. Additionally, during the second quarter, we initiated the new $125 million accelerated share repurchase program, and received a little over 1,850,000 shares. This current program should be completed in August.

As of June 30, 2014, Murphy's long-term debt amounted to just under $3.8 billion or approximately 31.1% of total capital employed. This long-term debt figure includes approximately $342 million associated with the capital lease production equipment for the Kikeh field offshore Malaysia.

And with that, I'll turn it over to Roger.

Roger W. Jenkins

Thanks a lot, Kevin. Looking at the highlights for the quarter, we set a quarterly production record from continuing ops of over 210,000 barrels equivalent per day. We produced an Eagle Ford Shale quarterly record of just over 52,800 barrel equivalent net, up 6% from the first quarter of this year and 33% from second quarter a year ago.

We achieved first production at our Dalmatian project in the Gulf with both wells performing above expectation. We reduced lease operating expenses per BOE for global oil and gas operations by 8% in the first half of '14 compared to the first half of 2013. We added 100 million barrels of equivalent of proved reserves this year and remain on track for reserve replacement in excess of 150% for the fourth consecutive year.

As Kevin just mentioned, we initiated $125 million share repurchase under our new board authorization in May. We have now repurchased 9% of our company's stock since October of 2012.

In the U.K. downstream business, we've signed an agreement to sell the Milford Haven refinery and terminal assets to Klesch Refinery, Limited, pending regulatory approval and subject to other material conditions. This transaction is scheduled to close no later than October 31 of this year. And a separate transaction for the sale of the U.K. retail business is at -- in a very advanced stage, and we'll provide further updates on this in due course. We anticipate repatriating to the U.S. cash in the range of $550 million once these transactions are completed.

As you look at prices in the second quarter, Malaysia realized prices for Block K and Sarawak averaged near $92 and $88, respectively, due to higher supplemental payments under the PSCs. Its overall capital spending was lower in the quarter, especially in shallow water Malaysia, post installation of 4 platforms and an associated pipeline for last year. Based on latest spending estimates, we forecast Block K and Sarawak realized oil prices in the third quarter to be near $90 and $84, respectively. Our oil-indexed SK realized average price cost of $5.30 per MCF for the quarter, and we anticipate pricing to continue in the same range for the second half of the year.

Moving to the United States. Eagle Ford Shale oil prices are just under $96 for the quarter including the impact of WTI hedging. Our realized oil prices in the Gulf averaged near $102, keeping pace with the movement in LLS and Brent. Syncrude was close to $103 per barrel, and Seal, including our hedge position, at a little over $61 per barrel showed strength in the second quarter.

Our portfolio continues to deliver solid cash flow metrics, our oil weighting positioning us well in light of recent falling natural gas prices. Looking at EBITDA for quarter 2 '14, we delivered near $40 per BOE, which compares well to the full year 2013 metric of just over $41 per barrel. EBITDAX in quarter 2 '14 was near $47 per barrel equivalent compared to just under $48 for the full year of 2013.

We also continue to show above-average results in these metrics and compared to our operational peers when using 2013, first quarter of '14 and second quarter of '14 data were available. Our worldwide lease operating expenses, or LOE, for the second quarter '14 with global oil and gas operations remained steady at just under $12 per barrel equivalent, relative to the prior quarter of this year and significantly lower than 2013 annual average of $14.54 per barrel.

Our second quarter production averaged just over 210,000 barrel oil equivalent per day, below our guidance of 217,000 barrel equivalent per day. This 3% shortfall is primarily attributed to the global offshore business in Malaysia with lower oil and gas volumes related to a well operation delay in Kikeh, continued unplanned downtime at a third-party methanol plant that processes Kikeh-associated gas and the jack-up rig mobilization delay at the South Acis platform in Sarawak and various small, downtime events at shallow and deepwater facilities.

Looking ahead to second half of the year, we have our plant production increases supported by the completing of all of the Siakap North-Petai well work, full start-up of Dalmatian, the addition of 97 new Eagle Ford Shale wells through mid-year, we've completed the Syncrude unplanned maintenance, further progress in the start-up efforts of the nonoperated Kakap-Gumusut field and the addition of 7 wells through the first half of the year at Serendah, which will be online for the remainder of the year. Production increases will be further supported by continued well adds at Eagle Ford, Montney and in SK oil for the rest of the year.

In exploration, our global exploration program will remain very active in the Gulf of Mexico as drilling operations continue and the tightened prospect in DeSoto Canyon 178 as a small oil accumulation was encountered in the original wellbore in the planned objectives and costs have been suspended. Based on this well result, we're currently sidetracking the well to test 130 million barrel equivalent gross mean prospect in an adjacent fault block.

We expect to spud our 50% working interest in operated lower Miocene prospect at Urca and Mississippi Canyon 697 in the third quarter. The predrill gross mean resource size of this well is 130 million barrel equivalent. The 2 prospects of wide in Opal: Opal that originally scheduled for late this year has been moved to 2015 as we set rig schedules in line with the timing with our partners who are currently working on 2 international opportunities that could spud later this year.

In other exploration drilling, the nonoperated Hon Khoai prospect in Vietnam and the operated Serai-1 well and associated sidetrack testing the Bawang Putih prospect in Indonesia were all plugged and abandoned as dry holes with $16.5 million expensed in the quarter. The Indonesia drilling will lead to an expense of approximately $8 million in the third quarter.

To the first half of the year, we completed our seismic programs in Equatorial Guinea, Vietnam, Namibia and then moving forward to process and analyzes data. In the third quarter, we will continue with the data processing and finalizing our plans to conduct the seismic program across Block EPP43 in the Ceduna basin offshore Southern Australia starting in the fourth quarter.

Looking ahead, you'll see us participating in 2 wells in the Gulf, along with the drilling in the Perth Basin offshore Australia starting in the first quarter of 2015. We're also considering 3 wells in Malaysia in addition to some other international opportunities.

In our new offshore fields, in both shallow and deepwater, have demonstrated excellent delivery building at or above planned rates. The subservice performance of these fields, along with the Eagle Ford, has greatly enhanced our ability to achieve continued production growth. In Malaysia, we've been hurt by the timely execution of our Kikeh field development plans by our previously announced rig fire earlier this year and a single well operational delay. The operational challenges are now resolved, and well work continues to plan, we have our first well now in line since the rig returned to service, and is performing well of near 4,000 barrels per day. We expect to place 2 new wells online to the end of the year at Kikeh.

At Siakap North-Petai where we hope 30% working interest, we've completed the final 2 production wells with the field achieving a deliverability target of approximately 35 barrel -- 35,000 barrels per day gross. We just finished up the last water injection well, so all well work is complete at Siakap North-Petai.

The Kakap-Gumusut main project where we have 14% working interest made significant progress this quarter in final commissioning, and we now see this field starting up in the late third quarter.

The shallow water offshore Sarawak, we added 7 new wells in our SK oil project at Serendah, in the first half of the year, following jack-up rig mobilization, we've since drilled and brought on 3 new wells at South Acis above plan this month. The rig will remain here for the rest of the year. We expect to add 9 total wells at South Acis this year. We have also completed the planned shut-in of the Perves fields and install the permanent topsides when the planned shut-in and time work complete.

In the Gulf of Mexico, we started up both high rate Dalmatian wells this quarter with better-than-planned results. The gas well started flowing on April 21, and the oil well started flowing on June 14. These 2 wells where we hold a 70% working interest, have the capability to deliver combined rate in excess of 20,000 barrel equivalent per day with approximately 50% liquids; well above the planned rates. A third well is planned to be added to the project in Dalmatian South and DeSoto Canyon Block 134 in early 2016. We're also planning a fourth development well for Dalmatian located in DC Block 4. At Medusa in Mississippi Canyon Blocks 538 and 582, we're moving forward with an accelerated subsea development where we operate with 60% working interest. The field requires additional wells and so we're still producing original completions much longer than planned. We'll be drilling 2 wells later this year with a subsea tieback to the Medusa facility and first production in 2015.

To the Montney and the Tupper area in Western Canada, we are moving forward with our plan to "drill to fill" of our existing plant capacity of 320 million [indiscernible] per day with 3 rigs in operations. We expect to put approximately 20 wells online this year. We've completed 7 new wells using our new completion and choke management strategies in the early stages of flowing back the first wells. Initial results are positive with rates as high or higher than previous wells but at higher pressures with the most recent well hitting over 11 million cubic feet per day. The larger 100-ton fracs is increasing the well productivity and along with the choke management, will provide upside to EUR. Depending on the results, we see upside with up to 500 potential locations in the core area. We're currently processing approximately 60 million in third-party gas through our facilities and up to 80 million of our plant capacity contracted. We have 110 million cubic feet per day of gas hedged at near CAD 4 AECO for the remainder of '14 at 65 million of gas hedged at near CAD 4.10 AECO for 2015.

In the Eagle Ford Shale, the second quarter production averaged 52,815 barrel oil equivalent per day net, 90% liquids as we brought on 53 new wells. We currently operate 8 drilling rigs and 4 completion spreads across the play and expect to bring on a total of 200 wells this year. Downspacing across the play continues to deliver expected results and we're testing upside potential at the Upper Eagle Ford Shale zone. We have tremendous running room in the Eagle Ford Shale with over 600 potential locations that are identified in the Upper Eagle Ford Shale and over 1,500 well locations to go in the Lower Eagle Ford Shale on the previous guided downspacing plans. Proved reserves in the Eagle Ford Shale totaled just over 200 million barrels at the end of 2013. We have a large resource in the Eagle Ford Shale, and we will continue to migrate resources to prove in with continued drilling out of offset locations downspacing in targeting upside of Upper Eagle Ford Shale. We see the total resource now at just over 700 million barrels net.

We're in the process of negotiating 2 separate pipeline agreements in Karnes and Tilden areas of Eagle Ford to transport up to 28,000 barrel per day net to market and expect to sign final agreements in the near future. This will reduce our exposure to trucking and improve overall reliability while maintaining our price advantage through the segregation of our low API gravity, premium quality crude oil in these dedicated systems. We have hedged approximately 21,000 barrels of WTI for the second half of the year at just under $94 a barrel. We continue to make good progress on operating expenses in the second quarter with total LOE in Eagle Ford of just under $10 per barrel. In addition, we continue to improve drilling and completion costs.

Based on current prices, we see the Eagle Ford Shale beginning to generate free cash flow in the fourth quarter of this year as production continues to ramp up. Our portfolio work continues and we closed on the sale of our upstream properties in South Louisiana and signed a letter of intent to sell our assets on the north slope of Alaska.

Third quarter production guidance is 225,000 barrel equivalent per day and our annual production guidance is now in the range of 220,000 to 225,000 barrel oil equivalent per day. We're still on track to achieve record production growth this year with continued ramp-up at Eagle Ford and growth support from our new offshore fields.

The takeaways: we're making progress in the U.K. downstream sales process with the signed agreement for Milford Haven refinery in place and advanced negotiations on the retail business. On exploration, I'm very satisfied with the focus and rigor that the teams is applying to our program. Strategy is sound, and we're building a strong properly-risked portfolio that will yield results long term. And I believe a new focus back in the Gulf of Mexico will allow for improvement we need in exploration results.

In all of our new offshore fields, we will see DD&A unit rates improve with further reserve booking across all of these properties. We remain pleased with all subsurface results and deliverability from our new fields. Operationally, I'm very pleased with the execution at Eagle Ford Shales. We continue to improve our drilling and completion metrics and lowering operating costs. Our new offshore fields, along with the continued execution in Eagle Ford, will support continued production growth as we're headed toward new record levels for the third consecutive year and 8% growth over last year.

We continue to have reserves at a strong pace and on track to achieve reserve replacement in excess of 150% for the fourth year in a row, and our oil-weighted portfolio, will continue to provide strong cash flow metrics, especially with recent deterioration in North American natural gas prices.

We can now open it up for questions. Before that, I'd like to recognize Kevin today. We think this is 75 calls in a row, and I don't know when we'll see that again. So we'll go from there.

Question-and-Answer Session

Operator

[Operator Instructions] We'll go first to Guy Baber with Simmons.

Guy A. Baber - Simmons & Company International, Research Division

A strategic one for me. So the production difficulties this quarter, obviously, mainly attributable to the offshore and some of the unpredictability that comes with that business. So the question is, did a quarter like this change at all your view of the optimal portfolio mix between offshore and more predictable onshore operations? Does it maybe add a little more sense of urgency to M&A on the margins? Just trying to get an understanding of your thoughts kind of M&A on a leading-edge basis and portfolio optimization. And then I have a follow-up.

Roger W. Jenkins

Thanks, Guy. No, we're probably in a long-range plan basis. We're about 50-50 onshore and offshore. Eagle Ford Shale is doing very, very well. But we made a lot of money in the offshore, too, and I'll look at great projects like Dalmatian, it's -- has incredible deliverability above plan, and we are seeing Siakap North-Petai and we execute a lot of subsea wells. There's a lot of rate of return there. I do think you're seeing people going back to the Gulf that were formally in the onshore and some announcements today. I still believe that some onshore to try to balance some of these problems, and we have had some problems with it, we'll admit. Over a long haul of about 9 quarters, we're in pretty good shape here. You just had a run of it as we execute, there's a lot of things this year in the offshore. But overall, no, I believe that an onshore business [ph] to help balance some of this. Once we get our projects streamlined and all of the new things online, I think it will still bode to better returns. It gives us a competitive advantage, too, Guy, because we're a -- we have a super major execution ability in deepwater and built a very, very successful onshore effort. So we have the ability to play in both. I think it bodes best for our staffing, our people, our company's history and how we perform, and so I like to be 50-50. And I'm happy. As to the M&A, I think if you were to portfolio yourself out offshore, we probably would look for some more balance in the onshore. I don't believe that going into something for sale by a super major, which has been a source of a lot of our delay, is somewhere where we really probably want to go. Does that answer your question?

Guy A. Baber - Simmons & Company International, Research Division

Yes, definitely. That's helpful. And then my follow-up was on the 2015 production outlook. I was hoping you could just address that, if even at a high level. But I know you have some longer-term production slides that you put in presentations that would show a pretty high '15 production number. So just wanted to kind of talk through, if the 2014 guidance changes would impact 2015 at all, do we need to be risking maybe the offshore piece in your graphs a little more heavily than what is shown? Just trying to put those slides in appropriate context as we start to think more seriously about the 2015, 2016 production outlook in underlying drivers and assumptions.

Roger W. Jenkins

Yes, I mean, we -- this is a difficult problem that we have and something I'm really focused on and trying to improve. It's a more difficult than you think to fix it or we probably would've fixed it by now, you would think. If you look at our slides that are out there on page, it's like, $269 million going to $294 million in '16, $295 million in '17, things to that nature. We are in the midst of preparing some risking. It's real hard to pick what the problem is because it's -- while I need to risk it better and I need to do a better job of risking it, we do have a lot of production going to: a nonoperated LNG plan in Malaysia; a nonoperated methanol plant for Kikeh gas in which we achieve little value; and then we have some third-party start-up at Kakap-Gumusut. And we're now flowing Dalmatian, which is probably successful to a super major field in the Gulf. So I'm exposed to things out of my control. It's hard to put the pin on what the factor may be, if you ask me today what we're looking to do, it's more than likely we're going to take an 8% off for these other years just from planning purposes. And you're probably exactly right, it'll probably come in the offshore. It's hard to say exactly where, but the onshore is fairly accurate. And if I have an onshore business, I probably would be doing pretty good. So that's kind of the number I'm looking at. But we really would like some time to work that to our budget and apply some risking factors to the right place. But it would be inappropriate just to maintain that with the struggles that I've had through mid-year this year, Guy, to be fair.

Operator

And we'll go next to Leo Mariani with RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just wanted to get a little bit more color around the Eagle Ford. It looks like production this quarter was a little light versus your prior expectations. You guys are expecting a pretty big ramp in the third quarter. Can you just kind of walk us through what's going on there?

Roger W. Jenkins

Yes, overall in our onshore North American business, it's pretty tight because we have risked -- kind of over-risked Syncrude, and it did a little better, and out Montney is doing better, and our Eagle Ford did have a bit of a miss. We fill a lot of gas into DCP pipeline. And that DCP pipeline went down, causing us some back pressures and to shut in some wells and some recovery from some offset fracs and sometimes a in that game, what we're running to in the Eagle Ford, there's a little bit of an issue with other people frac-ing near us which caused us to have to shut in because there's some areas are condensed down there. I consider it a one-off thing where we have a lot of production to add this quarter because we are putting 18 wells on together at Karnes and a big thing where we've kind of real concentration of wells, an area that we control the frac-ing around us. And we're also executing wells in this month, so they're very early in the quarter. We'll probably add 10 more wells operated this quarter than last, and most of them are early in the quarter. So we feel pretty good about the big build we have coming there. We're doing very, very well of late. We're also capturing some more gas and add some more facilities. And we do that, we'd catch some BOEs there and catch some NGL as well. And that issue is a pipeline issue and offset frac issue that was early in the quarter and I consider it isolated earlier.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

That's helpful color for sure. I guess, just jumping over to Seal. Productions have kind of been shrinking for the last few quarters here. I mean, how should we think about what that looks like over the next couple of years?

Roger W. Jenkins

Well, just when you start trying to make sure where cash and CapEx where we are as a company and do the right stewardship around rate of return, we've kind of got out of the primary business at Seal. For years and years, we did some primary horizontal drilling and now we're all about EOR-type work at Seal. Our Seal steam project at Kudat is doing very well. I'd say 2 of the 4 wells are really well. And so we are looking to just focus our efforts on capital, on EOR and last on primary, and that's why the pullback production. And if you look into our long-range plans, you're probably looking at some growth in -- significant growth in '16, '17 and we'll be hopefully sanctioning some steam and small fields, so you're starting last part of this year. We'll also look for that time when our global prices just saw improvement in WCS and some improvement in heavy and hopefully some help with Exshaw pipeline and things to that nature by that time that we'll meet our build. Our long-range plan is to go all EOR, no conventional, and that's why there's a pullback in the barrels earlier [ph].

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. So I guess, prior to 2016, should we expect kind of a slow decline? How should we think about it between now and then?

Roger W. Jenkins

I would say that'd be best, yes.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And I guess just looking at the Montney, obviously, it sounds like you guys have some wells flowing back, it's early days, it sounds like decent results there. Any comment on what you guys are seeing in terms of well costs in the Montney.

Roger W. Jenkins

We're drilling these wells cheaper than the Eagle Ford wells, probably in the $5.5 million range. These wells are a little more expensive because they're going to the slick water big tonnage per frac, of course they're still half the sand of an Eagle Ford well. But a lot of competition up there to drive costs after the pullback in gas over the last few years. And we're pleased with the costs, we're pleased with the result. And you know as we struggle a little bit with production, I'm not a big gas player, I don’t have the heavy gas BOE and a lot of that will help in a lot of ways. So we're really pleased with our early wells. So I think one way to describe the Montney is of all the wells we have in Tupper West, we have about 17 of them that we consider cream of the crop. I mean, they make -- they have EURs that's greater than 5 BCF and the type of the pressures they have. Well, 5 of the first 6 of these new completions meet our cream of the crop. So we're really on to something with this. I think there's some other in-fill out in the press from others nearby. And we think we're on to something here and has some price hedging, have some improvement in supply costs, have people come across our facility. Got this thing to net income here, and have a nice little business so we can build on here.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And I guess just shifting gears slightly, you guys talked about recently selling South Louisiana. Can you maybe just give us the proceeds in terms of what you all got there and give us an indication of when that closed? And I guess I wasn't aware you guys had properties in Alaska, it sounds like you're looking to sell. Can you give us any more color on that?

Roger W. Jenkins

Sure, Leo. They're just some very small -- just trying to clean some things up. I mean, in Alaska, you're talking about 120 barrels a day forever up there. I don't know the real history of it to be -- before my time, there was -- Hill Court [ph] bought some properties there from BP, we got in with them and sold at the same metric. We're talking $6 million sales price with 250,000 barrels of reserves. And South Louisiana, not even 1 million barrel equivalent resolves and selling that thing for $3 million cash and probably had a small loss if you dig into this big document here, Leo. I'm sorry.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. That's helpful. And I guess just in terms of your LOE, it looks like we're moving in the right direction. In terms of what we're seeing at the Eagle Ford, it's coming down nicely. But looking at Canada, that's kind of been going up recently, and Malaysia has kind of been bouncing around. Should we -- what should we expect out of those couple of areas? I'm assuming Eagle Ford keeps getting better as you guys grow. But can you talk about LOE in Canada and Malaysia?

Roger W. Jenkins

Malaysia, I think, we're kind of there we are. We start up these new fields and should be slightly better as we go out the rest of the year because we put 4 new fields on pipelines, all the [indiscernible]. We start off with low rates, and park a jack-up rig and you add wells, so the OpEx will get better. In Canada, it's primarily related to Syncrude and primarily related to that big unplanned CoCo repair. When you had all that at cost without any barrels that drove it up to the first half and I think it would improve a little bit in the second half, but that's what got that out of kilter there.

Operator

And we'll take our next question from Roger Read with Wells Fargo.

Roger D. Read - Wells Fargo Securities, LLC, Research Division

I guess if we could get any more detail on the sale of the U.K. refinery and retail assets. Going back through the notes, the thought process has typically been something in the range of $600 million, you said $550 million after taxes are paid on the repatriation. Is that a material change or that's -- I'm just kind of wondering what else is moving around here?

Roger W. Jenkins

No, I think that we just have to pull back a little bit. It just hasn’t gone maybe quite as well as we originally thought. It's always been our thinking that the tax situation would equal itself out on the loss and the gain of the various parts, and I'm going to have to Kevin comment on this. But I think it's best to pull it back to where we are, and we're just trying to describe this, Roger, just trying to exit this business, trying to be a pure E&P player has been a goal for a long time. I think that's going to be the money that ends up coming back. And I just sort describe it's what that is, and that's what the focus is by me. And I'll let Kevin add any other color you might need for help there.

Kevin G. Fitzgerald

Yes, Roger. I mean, frankly, one of the reasons that, that number has drifted down is as we've held on to this refinery longer and longer, if those periods we have -- actually runs cash flow negative, so we've actually eaten into a little bit of what we've had over there. The retail is a good business, it's kept on going along. But we're just eating a little bit into the cash so we dropped that number, so.

Roger D. Read - Wells Fargo Securities, LLC, Research Division

Okay, that's helpful. And then delving in a little bit more to the Eagle Ford Shale, your comments about the Upper Eagle Ford being available more well sites and all that. I was wondering, we see -- we didn't see it necessarily from you all, though we've heard from a lot of others where you see continued improvements in terms of lower well costs, higher EURs, advanced completion. Just wonder if you could give us any more detail on those lines, kind of frame up maybe how we should think about future growth at least out of the Eagle Ford even if your long-term kind of growth profile may be from a risk-adjusted standpoint needs to maybe been -- be bent down a little bit?

Roger W. Jenkins

No, I mean, I think from our perspective, our EURs that we originally guided to are about the same. 700-plus in Karnes, 450 in the Tilden area, an enormous acreage in Tilden, we found that wells to be very, very economic. I think when we downspaced from down to 40 acres and maybe going down to 20, we will see some -- in some areas, maybe a 20% reduction in EUR. In some places, none; in some places, no interference, same with the Eagle Ford Shale, Upper. Now we have 11 wells on there, all for various ports [ph] of time, they appear to be in the 350 to 400. I'd say they're -- to be honest, they're a little insubordinate, a little below the regular Eagle Ford. But again, in pad drilling and the lower drilling costs we have, they're very, very economic on a single-well basis. So we're trying to identify more what our total resource is in the Eagle Ford, which is very, very large for a company of our size. We're in on the ground floor, we have added a lot of value there. And that's kind of -- I'm not so sure we're into adding of the EUR but we're certainly maintaining. And I think it could be an add of EUR by technology and they're certainly going to be longer laterals, more stages and things to that nature. We're starting to work a lot on -- as move to change things in certain parts of the field and longer laterals, so I think we have a good bit of an upside to go there technically to change EUR. But we're pat with what we have, and we haven't changed EUR to the enormous resource we have here as shown today here, Roger.

Roger D. Read - Wells Fargo Securities, LLC, Research Division

Okay. And well costs, is that fairly static or are you still seeing some...

Roger W. Jenkins

Certainly, there's some slide in here today as you look into our slides that we provided about our call. I mean, we're doing -- we call the slide doing more with less for the same amount of money, we're drilling a lot more wells. So drilling continues to come down. I see completions staying about the same, and we're looking at $5 million or less in Tilden, $6 million in Karnes and probably $4 million in Total. We're drilling these wells in 7, 8, 9 days across the play now and that used to be 22 days. So enormous improvements there, and I'm happy with the whole thing, really.

Roger D. Read - Wells Fargo Securities, LLC, Research Division

Okay. And then my last question. The comment in the press release, the $100 million of BOE prove reserve additions, how did that breakdown by geography?

Roger W. Jenkins

Let me just get to -- return to this, here in my little thing and I'll tell you exactly. Better than that, I'll tell you off the top of my head, and I won't look for it. It's about 73 million barrels of the Block H Floating LNG sanction; 14 million barrels of Eagle Ford, and that's the bulk of it; and the rest would be the smaller field adds as it just gets started in Malaysia, but a long way to go there. So it's a one-off event, primarily on the sanction of the Block H and the signed gas agreement with the Petronas and the continued percolating of adds to lower DD&A and Eagle Ford as we go throughout the year.

Operator

We'll go next to Paul Cheng with Barclays.

Paul Y. Cheng - Barclays Capital, Research Division

Hope fully these several quick questions. Kevin, just want to confirm that the $530 million, that's including the sale of both the refinery terminal and the retail or it's just the refinery and the terminal?

Kevin G. Fitzgerald

No, that's all in. That's everything.

Paul Y. Cheng - Barclays Capital, Research Division

That's all in.

Kevin G. Fitzgerald

Right.

Paul Y. Cheng - Barclays Capital, Research Division

Okay. Secondly, do you have a preliminary budget for 2015?

Kevin G. Fitzgerald

No, not this time. I think this year was $3.8 billion and we're keeping that flat. We have no changes in our recent outlook. And I recall next year's to be slightly less, $3.7 billion or so, but where we're just getting started with that, Paul. But I don't see a big change in it.

Paul Y. Cheng - Barclays Capital, Research Division

Okay. So it should be pretty flat to this year level?

Kevin G. Fitzgerald

Flat or slightly less is my guidance.

Paul Y. Cheng - Barclays Capital, Research Division

And Roger, that -- with the cash coming from the U.K. and there's also rumor out there talking about someone have put a bid on -- I don't know whether that is a percentage of the entire Malaysia or just the U.K.? Yet indeed that you're going to sell part of the Malaysia also. What's the cash usage that we should assume?

Roger W. Jenkins

Well, I mean we've been wanting to repatriate the U.K. first for a long time. I'm very, very anxious to do so, and we signed agreements to do so. That would be coming into our revolver situation, lowering debt here and be better positioned in the U.S. Largely, I would think, Paul, I mean, there's a lot of squawking, I think, primarily by Reuters in that region about us selling 30% of our business. We really haven't -- we did not start that rumor, we don't comment on it. I'm not a big believer in sharing all the portfolio work. I believe it's a disappointment primarily on what ends up happening and the timing. As we know these portfolio moves is never what you originally say. And we just really aren't commenting on that, I do have a team of people working our portfolio both in and out, and probably a lot more rigor than we have in the past. I don't want to be the guy to turn off all lights and all these things. And I want to investigate possible mark-to-markets in our -- in all the things we own globally. And we should do that as a good steward of what we have here, and that's where we are, and I really don't comment on all those articles.

Paul Y. Cheng - Barclays Capital, Research Division

Right. Sure. I understand. But how about if I can ask that when you have excess cash, what's the cash priority going to be? Is it going to be going back and moving it back into the business for other M&A-buying assets and that type of new platform or they're just more of the priorities returning the cash to the shareholders?

Roger W. Jenkins

I think it'd be a mixture of all of the above. I mean, we have had a very strong history here of late of share repurchase. We have not been a historic heavy M&A player, but I think that I'm very, very happy with things near Eagle Ford area where we're working very well. We built a very successful team there in only a 3-year period. I think that we would look at mixture of all of the above if they were to be some cash there to brought over there. No special dividend, anything like that, but share repurchase and possible M&A into onshore wouldn't be something I wouldn't -- it'd be something I'd be interested in reviewing with our board.

Paul Y. Cheng - Barclays Capital, Research Division

And Roger, maybe that in stuff, say, comment specifically to Malaysia, but on an overall there, when you're looking at your upstream asset to determine that whether you want to sell down the asset other than, say, in terms of the price, is there any characteristic of the asset that you'll you say, okay, once I reach this day, I will be more eager than I want to be a seller.

Roger W. Jenkins

I have exactly that plan, Paul, but I'm not telling you today.

Paul Y. Cheng - Barclays Capital, Research Division

Okay, that's fair. In Malaysia, Block K, based on your production outlook, when do you think we're going to reach the 50-50 profit split -- that the profit split, it will go down to 50-50?

Roger W. Jenkins

2018.

Paul Y. Cheng - Barclays Capital, Research Division

2018?

Roger W. Jenkins

Yes.

Paul Y. Cheng - Barclays Capital, Research Division

And then in the press release, you're talking about the SK oil price, oil and gas price realization lower because of the PSC impact. Is that a temporary because of the profit -- because of the cost barrel is getting smaller or that this is something more permanent?

Roger W. Jenkins

No, it's -- I don't want to use the word complicated, Paul, but it takes a lot of modeling. Of course, we have it modeled. This is absolutely positively not involved in the production miss or production issue. All of our production matters are one-off operational period, nothing to do with this. But we have 2 blocks in SK: 309, 311. 309 has the historic West Patricia in it. So its costs current will be forever. It has a high oil to sea level, so there's no significant changes in entitlement in 309 until 2019 or more. The other block, 311, has some of the newer fields that we -- that we've been -- putting on production of late. They will not have a significant entitlement change from a barrels basis until 2016. And all of this will be in our plan. At the prices in the third quarter, we've guided that today. And I would say that would improve in the fourth quarter by about $7, $8 a barrel, and then stay consistent there through and on into '16.

Paul Y. Cheng - Barclays Capital, Research Division

So you're not that worried that your miss, it's just a onetime-one-quarter issue, in this particular case?

Roger W. Jenkins

Yes. For -- we're going to have to be very careful and guide it. And we're going to give you guidance on it. And we did today, quarter-by-quarter. We're working a system to better guide that for you at your conference, hopefully. I think that what happened here -- what's happening here is it's very, very sensitive to spend. It's not necessarily the spend, but it's very sensitive to the timing of the payment. So we set you what we're doing last year, installing all these pipelines, platforms, drilling, and it's drilling in different blocks: 309 versus 311. We have a very detailed model of it here. We know what we're doing on it. And so it ended with less cash and that would have pulled back in the quarter. Then we should recover some in the next quarter, and it would be in pretty good shape on a per barrel basis on price for a long time. And then apart from these entitlement things that are involved in production, many years to go there, and we have all that built into the plan.

Paul Y. Cheng - Barclays Capital, Research Division

Perfect. My one final one Seal, are we still expecting by 2016, the growth trend will start to kick in? And what is the petrol peak rate you guys are currently assuming several year down the road?

Roger W. Jenkins

I don't have that in front of me today, Paul, to be honest with you, on Seal -- Barry do you have the...

Kevin G. Fitzgerald

I mean, in long-range plan, Paul, all through that, we start to really pick it up in about 2018, and the plan there is to get that thing to 20,000 to 25,000 barrels a day.

Paul Y. Cheng - Barclays Capital, Research Division

So that have not been changed?

Kevin G. Fitzgerald

No, that's still where we're at now.

Operator

And we'll go next to Paul Sankey with Wolfe Research.

Paul I. Sankey - Wolfe Research, LLC

Had a couple of follow-ups, I think. The first one was, did you really say 75 straight calls to Kevin?

Roger W. Jenkins

That's correct, man.

Paul I. Sankey - Wolfe Research, LLC

Would that be 18 and 3 quarter years?

Roger W. Jenkins

It's hard to count.

Kevin G. Fitzgerald

That's in 1996 when I was made Director of Investor Relations.

John W. Eckart

Impressive, Kevin. You've only got 6 years to go and you'll be at 100.

Kevin G. Fitzgerald

It just means I'm old.

Paul I. Sankey - Wolfe Research, LLC

Going to the follow-ups I had just...

Kevin G. Fitzgerald

Got to have something today.

Paul I. Sankey - Wolfe Research, LLC

Yes, I just really have follow-ups in the previous -- in fact, directly from Paul's questions. Were your about these Malaysian tax changes because you're saying now that you have a detailed model of what happens going forward. Was it a surprise to you this past quarter?

Roger W. Jenkins

No. Not so much. Not on the spending side.

Paul I. Sankey - Wolfe Research, LLC

Right. So you kind of knew it was coming. And on the volumes, I guess, what we're saying is the operational side was disappointing, and therefore, that's how the target got missed again.

Roger W. Jenkins

Yes, there's nothing there in entitlement. And looking back, I should have guided a price, and we did it today.

Paul I. Sankey - Wolfe Research, LLC

Right. And then, did you say in the Q&A session, just to confirm, that you'll be lowering your long-term guidance now as a result of...

Roger W. Jenkins

Well, I'm not officially lowering it, but I mean I have to look at it. And I've done this before. We had a really good run through '12 and '13 on production. And I thought that with my Eagle Ford taking on a bigger position, in which does pretty well. Then I -- what I -- I don't have a problem on subsurface, I've just had a lot of third-party issue. And it really gets down to it. I need the price on top of factor and one of the earlier calls was about primarily in the offshore, and that's true. Of course, Syncrude has been problematic. We're a very good execution company. I'm very, very proud of our ability to deliver subsea project execution, Eagle Ford wells. And I'm partnered with a lot of people. We're one of the better players. But we simply couldn't overcome this year of the third-party events. We couldn't get perfect enough to overcome it. And I have to get off this parade, and it's going to take some type of factoring to do so. And I rattled off an 8% factor. That's what I'm working today. But I haven't guided into all of that yet. I got a big thing going and working on it. Working on the budget and the long-range plan right now. But clearly, I need to do something a little bit different. I'm working on it, Paul.

Paul I. Sankey - Wolfe Research, LLC

Okay. And then the final one was just again somewhat of a follow-up. But in the instance of a notional billions of dollars of potential additional cash, I think what you've fairly clearly said is it would be something between share repurchase and maybe some Eagle Ford stuff. I'm assuming you wouldn't accelerate your drilling program.

Roger W. Jenkins

Probably not this time, but I never said we had billions of cash coming back. That's a lot. People would put that word into my mouth there. I mean, there's a lot of yakking in the Internet these days. But I -- if you ask me my favorite things, those 2 would be it today. Everything changes, but that's it today.

Operator

And we'll go next to Ed Westlake with Crédit Suisse.

Edward Westlake - Crédit Suisse AG, Research Division

A follow on to Paul's question, I guess. You've always been fairly clear about keeping the Eagle Ford upward that sort of, I think, 70,000 barrels of them and sort of having a plateau. You're already at 53,000. Any plans to sort of drive that a bit harder or just keep that in the back pocket as a source of longer-term cash flows?

Roger W. Jenkins

No, I just think it's -- we need to something that's balanced and very predictable as we have these -- Dalmatian project, Siakap North project and the shallow water Malaysia projects are very, very economic. Even with this pullback in price, these things are enormously economic. So I need something that's balanced and long term and flat, and we're very happy about that. We want to really do a full-on effort to get back to cash flow CapEx parity and not outspend our cash flow here. And that's the way we're thinking about it, it's flat over increase at this time.

Edward Westlake - Crédit Suisse AG, Research Division

And then on the Upper Eagle Ford you've got, in Karnes, some of the folks there have said, "Look, here's some Upper Eagle Ford wells, co-development, Austin Chalk." And you've had the same type of fumes as some of the productive wells underneath, so that's awesome. But maybe just some color on any of the tests you've got on the Upper Eagle Ford in the Tilden and Catarina areas because obviously those are the larger sort of areas for your footprint in the Eagle Ford.

Roger W. Jenkins

In Tilden, we're doing very well, I described the EURs there, they're very near the Lower. We have wells, for me they are a week to 11 months online. We don't have a lot of wells but we're very happy about their performance. We're happy about the lack of interference. We're actually in the middle of doing some macro sizing interference testing between the Upper and the Lower now. At the Catarina area, this is a place where we've cut the drilling cost just enormously out there, maybe 2/3 reduction. So these are lower EURs as what we've previously guided, but we're really not showing any decline. And now we're in an area out there that has some Upper Eagle Ford in it and it's performing very well and very near our EURs there. So we're really happy with those 2 areas and have a good, big growth. And we tried to -- it's quite a complicated slide, you may have to call Barry and go over it, but we're trying to guide as to the reserves that we have and the resources we have in these different intervals both from offsets and downspacing and Upper-type distinctions there. If you take some time, look through that and call Barry, I think you'll get a better feel that we put a lot of rigor around this resource calculation.

Edward Westlake - Crédit Suisse AG, Research Division

And then just switching to Titan. I mean, obviously, you're disappointed with the main objective, and then you're sidetracking the well. Did you see something in the well that gave you because -- but it seems like it's across the fault block. I mean, just give us some sense of the confidence interval in the sidetrack or what you saw to make you do that.

Roger W. Jenkins

Well, we saw a -- this is again why we do this business. I mean, this is why we have the strategy, we have what we're doing. And we stopped drilling in 700 feet of high-quality sands, some of the best quality sand I've ever seen in my career. So would've had -- this is 700-foot-plus type of a column here we could've had success. And what we had risking here is we needed to have oil be formed here and oil be migrated here. And when we needed a lateral seal, again, it's all for Titan to be very big. And we didn't have that lateral seal. And when you do the modeling it appears that the oil would accumulate just at the very most up crest and then possibly across the fault. And we know that from Appomattox, we have oil levels that are different across major fault features. And we know that here, we see that here, and because we had oil, and this is oil that we got from MDT in the sample. This isn't fake oil, this is oil you can pour out on the desk here. We -- once we find that in a very small accumulation we have, we're going to go through this across the fault adjacent well that we have because the modeling work shows that it should accumulate there. And that's why we're doing it. I'll consider the 25%, 30% chance it would be anywhere else, and a deepwater-portfolio-type of a risk here.

Edward Westlake - Crédit Suisse AG, Research Division

And the timing to finish that sidetrack, is that going to be as long as a normal well or?

Roger W. Jenkins

No, we kicked well off at 20,000 feet. I think, we're drilling a 27,000 or 28,000, be over in about 40 days, something to that nature.

Operator

And we'll go next to Pavel Molchanov with Raymond James.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Well, I appreciate the fact that you're not going to comment on press rumors. But conceptually, what percentage of your production base, reserve base, whatever metric you choose, would you like Malaysia to represent in an ideal scenario?

Roger W. Jenkins

Oh, I don't know. Well, it depends on -- these fictitious things is hard to say. I mean, I guess -- it's just hard to say. I mean, there's different days, different situations, and I hate to say that. At this time, I would say that typically we do better when we operate, when we're in charge of the fields, bring a competitive advantage to that. I'd just rather leave it at that.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Okay, fair enough. And then on the U.K. monetization. The press release indicated that concurrent with the sale of the refinery itself, you're looking to monetize the downstream or the retail assets as well. Any sense of what the level of proceeds could be from that part of the sale?

Roger W. Jenkins

We're just really, at this time, trying to say that we're going to bring all this money home as we said in the comments here today, which is $550 million. I think you would describe that business as an EBITDA-multiple-type sale that wouldn't be shocking and wouldn't be unbelievably high or unbelievably low but very fair and very known to benchmarks of industry. And to me, it's about exiting that business, becoming focused on E&P, continuing with the execution of that, which is our goal, getting the money back into our revolver and have a very low revolver and flexibility here for Kevin and moving forward. That's kind of what we're focused on.

Kevin G. Fitzgerald

Pavel, $550 million relates to all of the downstream assets over there.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Okay, understood. And then just a quick one. On Titan, any sense of how long until the sidetrack reaches Kiti?

Roger W. Jenkins

Just said, I think about 45 days from now.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

45 days, okay.

Operator

And we'll take our final question today from John Herrlin from Societe Generale.

John P. Herrlin - Societe Generale Cross Asset Research

Two quick ones. You mentioned that OBO situations can sometimes be problematic. Is Syncrude still strategic now that you have bigger North American production onshore?

Roger W. Jenkins

Well, I mean, it's strategic and it's a big part of our R/P and we got in on that at very, very low ground floor prices. And it still delivers $200 million or $300 million of cash to us in Canada. I would say that if we could have some more success in exploration, it might not be as strategic. But we wanted that our R/P to the 10 level and on, and it's in our plan to do that and it's a key part of that. Are there other things that could tell us that goal to be made and allow it to be less strategic? Yes. I would say, today our early entry and the cash it provides and the R/P is the main and only strategic advantage that gives me today. That's a very disappointing year, and it just continues to struggle there. And even though this maintenance is behind it, to get back going again has been difficult. So -- but that's how I view it. It's more of an R/P, very critical to us at this juncture, but getting less all along.

John P. Herrlin - Societe Generale Cross Asset Research

Okay, that's fine. Last one for me is on the U.K. Any charges associated with the sale that you'll be taking any future charges?

Roger W. Jenkins

We made a big write-off last year as to the assumed sale. And we think we're okay there, but you'll never know if it's over, and we got to close out our books. And I'd be very anxious, even for this one, to end this chapter, I assure you.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. Yes, that's why I was wondering whether there was something incremental.

Operator

And that does conclude the question-and-answer session. At this time, I'd like to turn the conference back to Mr. Roger Jenkins for any additional or closing remarks.

Roger W. Jenkins

I appreciate everyone calling in today. We'll be back the same time and station in late October, it will be cool. Football season will be going, and we'll try to have a better quarter and get well in here. And we appreciate all the time, and we thank you, all.

Operator

Again, that does conclude today's presentation. We thank you for your participation.

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