Murphy Oil Corp (MUR) 2014 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation's second-quarter 2014 earnings conference 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.

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 will now turn the call over to Kevin.

Thanks, Barry. Net income for the second-quarter 2014 is $129.4 million or $0.72 per diluted share. (technical difficulty) 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 net income for the first 6 months of last year of $763.2 million or $4.00 per diluted share.

This year's second quarter included a loss from 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. Our income from continuing ops for the 6 months of 2014 is $312 million or $1.72 per diluted share, compared to 6 months of 2013 $442.6 million or $2.32 per diluted share.

Looking at income by segments, in 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 more mostly attributable to higher exploration expenses, higher extraction costs 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 the 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 from the Tupper area in British Columbia and from fields offshore Sarawak, Malaysia, partially offset by increased production from the Eagle Ford and from the startup of the Dalmatian field in the Gulf of Mexico.

In the Corporate for second quarter of 2014 we had net charges of $58.1 million compared to net charges of $30.3 million in the second quarter of last year. These increased costs primarily related to unfavorable effects from foreign exchange transactions and higher financing costs.

During the second quarter this year we completed the accelerated share repurchase program begun in the first quarter and retired an additional 123,380 shares over that previously reported. Additionally, during the second quarter we initiated a 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, (technical difficulty) percent of total capital employed. This long-term debt figure includes approximately $342 million associated with the capital lease production equipment for the Kakap field offshore Malaysia.

With that, I will turn it over to Roger.

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 equivalents 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 2014 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 a $125 million share repurchase under our new Board authorization in May. We have now repurchased 9% of our Company's stock since October 2012.

In the UK 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.

A separate transaction for the sale of the UK retail business is at a very advanced stage. We will provide further update on this in due course. We anticipate repatriating to the US cash in the range of $550 million once these transactions are completed.

As we 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, as overall capital spending was low in the quarter, especially in shallow-water Malaysia, post installation of four platforms and associated pipelines 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 to SK realized average price close to $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 two 2014, we delivered nearly $40 per BOE, which compares well to the full-year 2013 metric of just over $41 per barrel.

EBITDAX in quarter two 2014 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 when compared to our operational peers when using 2013, first quarter of 2014, and second quarter of 2014 data where available.

Our worldwide lease operating expenses, or LOE, for the second-quarter 2014 for 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 a barrel.

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

Looking ahead to the second half of the year, we have our planned production increases supported by the completing of all of the Siakap North-Petai well work, full startup of Dalmatian, the addition of 97 new Eagle Ford Shale wells through midyear, we've completed the Syncrude unplanned maintenance, further progress in startup efforts at the non-operated Kakap-Gumusut field, and the addition of seven 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 wellheads at Eagle Ford, Montney, in SK oil for the rest of the year.

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

We expect to spud our 50% working interest and operated lower Miocene prospect at Urca in Mississippi Canyon 697 in the third quarter. The predrilled gross mean resource estimate for this well is 130 million barrel equivalent.

The two prospects at [White] and Opal that were originally scheduled for late this year have been moved to 2015 as we have set rig schedules to align the timing with our partners, who are currently working on two international opportunities that could spud later this year.

In other exploration drilling, the nonoperated Hon Khoai prospect in Vietnam and the operated Serai 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. Indonesia drilling will lead to an expense of approximately $8 million in the third quarter.

Through the first half of the year, we completed our seismic programs in Equatorial Guinea, Vietnam, Namibia, and are moving forward to process and analyze this data. In third quarter we will continue with the data processing and finalizing our plans to conduct a seismic program across Block EPP 43 in the Ceduna basin offshore Southern Australia starting in the fourth quarter.

Looking ahead, I see us participating in two wells in the Gulf along with the drilling in the Perth basin offshore Australia starting in the first quarter of 2015. We are also considering three wells in Malaysia in addition to some other international opportunities.

Our new offshore fields in both shallow and deep water have demonstrated excellent deliverability at or about planned rates. The subsurface performance of these fields along with the Eagle Ford has greatly enhanced our ability to achieve continued production growth.

In Malaysia we have been hurt by the timely execution of our Kikeh field development plans by a 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 online since the rig returned to service, and it is performing well at nearly 4,000 barrels per day. We expect a place to new wells online through the end of the year at Kikeh.

At Siakap North-Petai, where we hold 30% working interest, we have completed the final two production wells with the field achieving a deliverability target of approximately 35,000 barrels per day gross. We have 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. We now see this field starting up in the late third quarter.

In shallow-water offshore Sarawak we added seven new wells in our SK Oil project at Serendah in the first half of the year. Following the jackup rig mobilization, we have since drilled and brought on three new wells at South Acis, above plan this month.

The rig will remain here for the rest of the year. We expect to add nine total wells at South Acis this year. We have also completed the planned shut-in of the Permas field and installed the permanent topsides, with the planned shut-in and tie-in 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 two wells, where we hold a 77% working interest, have the capability to deliver a combined rate in excess of 20,000 barrel equivalent per day with approximately 50% liquids, well above the plan rate.

The third well is planned to be added to the project at Dalmatian South in Desoto Canyon Block 134 in early 2016. We are also planning a fourth development well for Dalmatian located in DC Block 4.

In Medusa and Mississippi Canyon Block 538 and 582 we're moving forward with an accelerated subsea development where we operate with 60% working interest. The field requires additional wells, as we are still producing original completions much longer than planned. We will be drilling two wells later this year with a subsea tieback to the Medusa facility and first production in 2015.

To the Montney and the tougher area of Western Canada, we are moving forward with our plan to drill the field. Our existing plant capacity of 320 million [scuffs] per day, there's three rigs in operation. We expect to put approximately 20 wells online this year.

We have completed seven 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 are 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 are currently processing approximately of 60 million of third-party gas through our facilities, with up to 80 million of our plant capacity contracted. We have 110 million cubic feet per day of gas hedged at near CAD4.00 AECO for the remainder of 2014, with 65 million of gas hedged at near CAD4.10 AECO for 2015.

In the Eagle Ford Shale, the second-quarter production averaged 52,815 barrel of oil equivalent per day net, 90% liquids, as we brought on 53 new wells. We currently operate eight drilling rigs and four 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. We are testing upside potential of the Upper Eagle Ford Shale zone.

We have tremendous running room in the Eagle Ford Shale, with over 600 potential locations now identified in the Upper Eagle Ford Shale and over 1,500 well locations to go in the Lower Eagle Ford Shale under previous guided downspacing plans. Proved reserve 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 proven with the continued drillout of offset locations, downspacing, and targeting the 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 two separate pipeline agreements in the Karnes and Tilden areas of the Eagle Ford, transport up to 28,000 barrel of oil per day net to market, and expect to sign final agreements in the near future. This reduces our exposure to trucking and improve overall reliability while maintaining our price advantage through 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 the 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 barrel equivalent per day, and our annual production guidance is now in a range of 220,000 to 225,000 barrel of oil equivalent per day. We are 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 are making progress in the UK downstream sales process, with the signed agreement for the Milford Haven refinery in place and advanced negotiations on the retail business. In exploration, I am very satisfied with the focus and rigor that the team is applying to our program. The strategy is sound, and we are building a strong, properly risked portfolio that will yield results long term. 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 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 am very pleased with the execution in Eagle Ford Shale as we continue to improve our drilling and completion metrics and lowering operating costs. Our new offshore fields, along with continued execution in the Eagle Ford, will support continued production growth as we are headed toward new record levels for the third consecutive year and 8% growth over last year.

We continue to add 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 would like to recognize Kevin today. We think this is 75 calls in a row, and I don't know when we will see that again. So we will go from there.

(Operator Instructions) Guy Baber, Simmons.

Kevin, congrats on your streak. Okay. 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: Does 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 margin? Just trying to get an understanding of your thoughts on M&A on a leading-edge basis and portfolio optimization. And then I had a follow-up.

Thanks, Guy. No, probably in a long-range planning 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. I look to great projects like Dalmatian that has incredible deliverability above plan. And our Siakap North-Petai, we executed a lot of subsea wells. There is a lot of rate of return there.

I do think you are seeing people going back to the Gulf that were formerly 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, I will admit. Over a long haul of about nine quarters, in pretty good shape year; we just had a run of it as we have executed a lot of things this year in offshore.

But overall, no. I believe that an onshore (technical difficulty) [build] helps 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 and gives us a competitive advantage too, Guy, because we have supermajor execution ability in deep-water and have built a very, very successful onshore effort.

So we have the ability to play in both. I think it bodes best for our staffing and our people, our Company's history, and how we perform. So I like to be 50-50 and I am happiest.

To the M&A, I think if you were to portfolio yourself out of offshore, we probably would look for some more balance in the onshore. I don't believe that going into some things for sale by a supermajor, 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?

Yes, definitely. That's helpful. 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 2015 production number. So just wanted to 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 the appropriate context as we start to think more seriously about the 2015/2016 production outlook and underlying drivers and assumptions.

Yes, I mean we -- this is a difficult problem to have, and something I am really focused on and trying to improve. It is more difficult than you think to fix it, or I probably would've fixed it by now, you would think.

If we look at our slides that are out there, on page -- it is like 269, on to 294 in 2016, 295 in 2017, things of that nature, we are in the midst of preparing some risking. It is real hard to pick what the problem is.

Because while it's -- 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 non-operated LNG plant in Malaysia, a non-operated methanol plant for Kikeh gas in which we achieve little value; and then we have some third-party startup at Kakap-Gumusut.

We are now flowing Dalmatian which is incredibly successful to a supermajor field in the Gulf. So I am exposed to things out of my control.

It is hard to put the pin on what the factor will be. But if you ask me today what we're looking to do, it is more than likely going to take an 8% off of these other years just from planning purposes. And you are probably exactly right; it would probably come in the offshore. It is hard to say exactly where, but the onshore is fairly accurate.

And if I had an all-onshore business, I would probably be doing pretty good. So that is kind of the number I am looking at. But really we would like some time to work that through 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 have had through midyear this year, Guy, to be fair.

Understood. Thanks for the comments.

Leo Mariani, RBC.

Just wanted to get a little bit more color around the Eagle Ford. 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 walk us through what is going on there?

Yes, overall in our onshore North American business we're pretty tight, because we had kind of overrisked Syncrude, and it did a little better; and the Montney is doing better. Now, our Eagle Ford did have a bit of a miss.

We flow a lot of gas into a DCP pipeline, and that DCP pipeline went down, causing us some back pressure issues and to shut in some wells, and some recovery from some offset fracs. And sometimes the net gain, what we run into in the Eagle Ford, there is a little bit of an issue with other people fracking near us which causes us to have to shut in because some areas are condensed down there.

I consider it a one-off thing. We have a lot of production add this quarter because we are putting 18 wells on together in Karnes in a big thing where we have got a real concentration of wells, an area that we control the fracking around us. And we are also executing wells in this month, so they are very early in the quarter.

We will probably add 10 more wells operated this quarter than last, and most of them early in the quarter. So I feel pretty good about the big build we have coming there. We are doing very, very well of late.

We are also capturing some more gas and adding some more facilities. When we do that, we catch some BOEs there and catch some NGL as well.

That issue is a pipeline issue and an offset frac issue that was early in the quarter. And I consider it an isolated event.

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

Well, it's just when you start trying to make sure we're at cash flow CapEx, where we are as a Company, and do the right stewardship around rate of return, we have got out of the primary business at Seal for years and years, and did some primary horizontal drilling. And now we are all about EUR type work at Seal.

Our Seal steam project at Cadotte is doing very well. I would say two of the four wells are really well. So we are looking to just focus our efforts on capital on EOR and less on primary, and that is why the pullback in production.

If you look into our long-range plans, you're probably looking at some growth, and significant growth in 2016, 2017. We will be hopefully sanctioning some steam in small fields here starting the last part of this year.

We also look for at that time in our global prices there is some improvement in WCS and some improvement in heavy, and hopefully some help with XL pipeline and things of that nature by that time, that will meet our build. Our long-range plan is to go all-EOR, no conventional; and that is why there is a pullback in the barrels a bit.

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

I would say that would be best, yes.

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

We are 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 are 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 cost after the pullback in gas over the last years. And we are pleased with the cost, real pleased with the result.

You know, as we struggle a little bit with production, I am not a big gas player; I don't have the heavy gas BOE and a lot of that will help you in a lot of ways. So we are real pleased with our early wells.

I think one way I'd describe the Montney is, of all the wells we have in Tupper West, we have about 17 of them that we consider the cream of the crop, meaning they make -- the EUR is greater than 5 BCF and the type of pressures they have -- well, five of the first six of these new completions meet our cream of the crop. So we are really onto something with this. I think there is some other infill out in the press from others nearby.

We think we are onto something here and have some price hedging, have some improvement in supply costs, have people coming across our facility. Got distinct net income here and have a nice little business we can build on here.

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

Sure. These are some very small -- just trying to clean some things up. In Alaska you're talking about 120 barrels a day forever up there. I don't know the real history of it because it was before my time.

There was -- Hilcorp bought some properties there from BP. We got in and sold at the same metric. We are talking $6 million sales price with 250,000 barrels of reserves in South Louisiana, and not even 1 million barrels 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.

Okay, that's helpful. I guess just in terms of your LOE, it looks like they are moving in the right direction in terms of what we are seeing out of the Eagle Ford; it is coming down nicely. But looking at Canada, that has been going up recently; and Malaysia has been bouncing around.

What should we expect out of those couple areas? I am assuming Eagle Ford keeps getting better as you guys grow. But can we talk about LOE in Canada and Malaysia?

Malaysia, I think we are there where we are. We start up these new fields and should be slightly better as we go out the rest of the year. Because you know, we put four new fields on pipelines, all the etc., we start off with low rates; we park a jackup rig; and we add wells. So the OpEx will get better.

In Canada, it is primarily related to Syncrude and primarily related to that big unplanned coker repair. When we had all that at cost without any barrels, that drove it up for the first half. I would think it would improve a little bit in the second half, but that is what got that out of kilter there.

Okay. Thanks, guys.

Roger Read, Wells Fargo.

How are you all doing with the call today? Hopefully your iPhone hasn't been keeping you awake at night this time.

No, I do not look anymore, Roger. I changed that.

I understand how that goes. I guess if we could get any more detail on the sale of the UK 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 is -- I am just kind of wondering what else is moving around here.

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 has always been our thinking that the tax situation would equal itself out on the loss and the gain of the various parts. I am going to have Kevin comment on this, but I think it is best to pull it back to where we are.

We are just trying to describe this, Roger, as trying to exit this business, trying to be a pure E&P player has been a goal for a long time. I think that is going to be the money that ends up coming back; and I would just rather describe it as what that is, and that is what the focus is by me.

And I will let Kevin add any other color you may need for help there.

Yes, Roger. I mean, frankly, one of the reasons that that number has drifted down is as we have held on to this refinery longer and longer, it has periods where it actually runs cash flow negative. So we have actually eaten into a little bit of what we have had over there.

The retail is a good business. It has kept on going along. But we are just eating a little bit into the cash and we have dropped that number some.

Okay. That's helpful. 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 didn't see it necessarily from you all, but we have 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 along those lines. Frame up maybe how we should think about future growth, at least out of the Eagle Ford, even if your long-term growth profile maybe from, like you said, a risk-adjusted standpoint needs to maybe be bent down a little bit.

No, I mean I think from our perspective our EURs that we originally guided to are about the same, about 700-plus and Karnes; 450 in the Tilden area. We have enormous acreage in Tilden. We find the wells to be very, very economic.

I think when we downspace from down to 40 acres and maybe on down into 20 we will see 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. We have of 11 wells on there, all for various points of time. They appear to be in the 350 to 400.

I would say, to be honest, they are a little insubordinate. They are a little below the regular Eagle Ford. But again in pad drilling and the lower drilling costs we have they are very, very economic on a single well basis.

We are trying to identify more what our total resources in the Eagle Ford, which is very, very large for a company of our size. We were in on the ground floor and we have added a lot of value there.

And that is -- I am not so sure we answered the adding of the EUR, but we are certainly maintaining. And I think there could be an add of EUR by technology, and there are certainly going to be longer laterals, more stages, and things of that nature. And we are starting to work a lot on, as we move to change things in certain parts of the field and longer laterals.

So I think we have a good bit of upside to go there technically to change EUR. But we are pat with what we have, and we haven't changed EUR to add up to the enormous resource we have here shown today, Roger.

Okay. Well cost, is that fairly static or are you still seeing some (multiple speakers)?

Well, we just essentially -- there is some slide in here today as you look into our slides that we provided by our call. We call this slide doing more with less, where for the same amount of money we are drilling a lot more wells.

So drilling continues to come down. I see completions staying about the same. We are looking at $5 million or less in Tilden, $6 million in Karnes, and probably $4 million total. We are drilling these wells in 7, 8, 9 days across the play now, and it used to be 22 days.

So enormous improvements there and I am happy with the whole thing, really.

Okay. Then just my last question. The comment in the press release, the 100 million of BOE proved reserve additions, how did that break down by geography?

Let me just get to -- turn to this here in my little thing and I will tell you exactly. Better than that, I will tell you off the top of my head and I won't look for it.

It is about 73 million barrels will be Block H floating LNG sanctioned; 14 million barrels at Eagle Ford; and that is the bulk of it. The rest would be the smaller field adds as we just get started in Malaysia; but a long way to go there.

So it was a one-off event, primarily on the sanctioning of the Block H, and the signed gas agreement with Petronas, and the continued percolating of adds to lower our DD&A in Eagle Ford as we go throughout the year.

Okay, that's great. Thank you.

Paul Cheng, Barclays.

Hey, guys. Good afternoon. Hopefully several quick questions. Kevin, just want to confirm that the 530 (sic), that is including the sale of both the refinery terminal and the retail? Or just the refinery and the terminal?

No, that is all in. That is everything.

That is all in? Okay. Secondly, do you have a preliminary budget for 2015?

No, not at this time. I think this year was 3.8 and we are keeping that flat. We have no changes in our recent outlook; and I recall next year's to be slightly less, 3.7 or so.

But we are just getting started with that, Paul. But I don't see a big change in it.

Okay, so it should be pretty flat to this year level?

Flat or slightly less is my (multiple speakers)

Roger, with the cash coming from the UK and there is also rumor out there talking about someone had put a bid on -- I don't know what (inaudible) a percentage of the entire Malaysia or just the TK. Yet [indeed] you're going to sell part of Malaysia also. What is the cash usage that we should assume?

Well, we have been wanting to repatriate the UK for a long time, very, very anxious to do so, and we have signed agreements to do so. That would be coming in through our revolver situation, lowering debt here, and be better positioned in the US.

As far as the other thing, Paul, there is a lot of squawking, I think primarily by Reuters in that region, about us selling 30% of our business. We really haven't. We didn't start that rumor; we don't comment on it.

I am not a big believer in sharing all the portfolio work. I believe it is a disappointment primarily on what ends up happening and the timing, because we know these portfolio moves is never what you originally say. And we are just really aren't commenting on that.

I do have a team of people working our portfolio both in and out, in probably a lot more rigor than we have in the past. I don't want to be the guy to turn off all the lights on all these things, and I want to investigate possible mark-to-market in all the things we own globally.

We should do it as a good steward of what we have here, and that is where we are. And I really don't comment on all those articles.

Right, sure. Understand. But how about, if I can ask that, when you have excess cash, what is 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 us, and establish a new platform? Or that more of the priority is returning the cash to the shareholder?

I think it will be a mixture of all the above. We have had a very strong history of late of share repurchase. We have not been a historic heavy M&A player, but I think that I am very, very happy with things near Eagle Ford area, where we are working very well and we have built a very successful team there in only a 3-year period.

I think that we would look at a mixture of all of the above if there were to be some cash 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 -- that would be something I would be interested in reviewing with our Board.

Roger, maybe that [yourself] say comment specifically to Malaysia. But on an overall [debt], when you're looking at your upstream asset to determine 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 say: Okay, once I reach this stage, I will be more eager than I want to be a seller?

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

(laughter) Okay, that's fair.

In Malaysia, Block K based on your production outlook, when do you think we are going to reach the 50-50 profit split, that profit split you will go down to 50-50?

2018.

2018?

Yes.

And then in the press release you are 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 [cross] barrel is getting smaller? Or that this is something more permanent?

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 a production miss or production issue. All of our production matters are one-off operational, period; nothing to do with this.

But we have two blocks in SK Oil: 309, 311. 309 has the historic West Patricia in it, so it is cost current and will be forever. It has a high R-over-C level, so there is no significant changes in entitlement in 309 until 2019 or more.

The other block, 311, has some of the newer fields that were [parked], that we have been used, putting on production of late. It will not have a significant entitlement change from a barrels basis until 2016; and all of this would be in our plan.

When you start looking at the prices in the third quarter, we guided that today. I would say they would improve in the fourth quarter by about $7, $8 a barrel and then stay consistent there through and on into 2016.

So in other words, that really is just a one-time, one-quarter issue in this particular case?

Yes, but we are going to have to be very careful and guide it. We are going to give you guidance on it, and we did today, quarter by quarter. We are working a system to better guide that for you -- at your conference, hopefully.

I think that what happened here is it's very -- what is happening here is it is very, very sensitive to spend. And it is not necessarily the spend, but it is very sensitive to the timing of the payment.

So if you picture what we were doing last year, installing all these pipelines, platforms, drilling, and this drilling in different blocks, 309 versus 311, we have a very detailed model of it here. We know what we are doing on it. So we end that with less cash, end it with a pullback in the quarter; then we should recover some the next quarter and be in pretty good shape on a per-barrel basis on price for a long time.

And then from these entitlement things that are involved in production, many years to go there. And we have all that built into the plan.

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

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

I mean in the long-range plan, Paul, out through that 2020, 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.

So that has not been changed?

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

Okay, perfect. Thank you.

Paul Sankey, Wolfe Research.

Hi, everyone. I had a couple of follow-ups, I think. The first one was: Did you really say it is 75 straight calls for Kevin?

That's correct, man.

Would that be 18 and three-quarter years?

It's hard to count.

Since 1996 when I was made Director of Investor Relations.

Impressive, Kevin; you have only got 6 years ago and you will be at 100.

It just means I am old.

Going to the follow-ups I had -- yes, I just really have follow-ups from the previous. In fact they are really from Paul's questions.

Were you aware about these Malaysian tax changes? Because you are saying now that you have a detailed model of what happens going forward. Was it a surprise to you this past quarter?

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

Right, so you knew it was coming. On the volumes, I guess what we are saying is the operational side was disappointing, and therefore that is how the target got missed again?

Yes, that has nothing to do with entitlement. And looking back I should have guided a price, and we did it today.

Right. Then did you say in the Q&A section, just to confirm, that you will be lowering your long-term guidance now as a result of --?

Well, I am not officially lowering it, but I mean I have to take a look at it. And I have done this before.

We had a really good run through 2012 and 2013 on production, and I thought that with my Eagle Ford taking on a bigger position, which does pretty well, then -- I don't have a problem on subsurface. I have just had a lot of third-party issue.

It really gets down to it, I need to apply some type of factor. One of the earlier calls was about primarily in the offshore, and is true; but of course Syncrude has been problematic.

We are a very good execution Company and I am very, very proud of our ability to deliver subsea project execution and Eagle Ford wells. I am partnered with a lot of people, and we are 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 for parade, and it's going to take some type of factoring to do so. I rattled off an 8% factor; that is what I am working today.

But I haven't got into all that yet. I have 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 am working on it, Paul.

Great, thank you. 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 fairly clearly said is it would be something between share repurchase and maybe some Eagle Ford stuff. I am assuming you wouldn't accelerate your drilling program.

Probably not at this time, but I never said we have billions of cash coming back. That's a lot of people put that word into my mouth there. There is a lot of yakking in the Internet these days.

But if you ask me my favorite things, those two would be it today. Everything changes, but that is it today.

Thanks for the clarification. Thank you.

Ed Westlake, Credit Suisse.

Just a follow-on to Paul's question, I guess. You have always been fairly clear about keeping the Eagle Ford up at that, I think, 70,000 barrels a day, and then having a plateau. You are already at 53,000.

Any plans to drive that a bit harder? Or just keep that in the back pocket as a source of longer-term cash flows?

No, I just think it's -- we need something that is balanced and very predictable as we have these -- this Dalmatian project, Siakap North project, and shallow-water Malaysia projects are very, very economic. Even with this pullback in price these things are enormously economic.

So I need something that is balanced and long-term and flat. We are 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.

That is a way we are thinking about it, is flat over increase at this time.

Then on the Upper Eagle Ford, you have got -- in Karnes some of the folks there have said: Look, here are some Upper Eagle Ford wells, codevelopment, Austin Chalk. And you have had the same type of cumes as some of the productive wells underneath.

So that is awesome. But maybe just some color on any of the tests you have got on the Upper Eagle Ford in the Tilden and Caterina areas, because obviously those are the larger areas for your footprint in the Eagle Ford.

In Tilden, we are doing very well. I described the EURs there to be very near the lower. We have wells from either a week to 11 months online. We don't have a lot of wells, but we are very happy about their performance; we are happy about the lack of interference.

We're actually in the middle of doing some macroseismic interference testing between the Upper and the Lower now. Out in the Caterina area it, this is a place where you could cut the drilling cost just enormously out there, maybe two-thirds reduction.

So these are lower EUR, as per we've previously guided, but really not showing any decline. We are in an area out there that has some Upper Eagle Ford in it, and it is performing very well and very near our EURs there. So we are really happy with those two areas and have a good bit of growth.

We tried to -- it is a quite complicated slide, and you may have to call Barry and go over it -- but we are trying to guide as to the reserves we have and resources we have in these different intervals, both from offsets and downspacing and upper type distinction there.

If you take some time, look through that, and call Barry, I think you can get a better feel that we put a lot of rigor around this resource calculation.

Then just switching to Titan, obviously disappointment with the main objective, and then you are sidetracking the well. Did you see something in the well that gave you -- but it seems like it is across a fault block. Just give us some sense of the confidence interval in the sidetrack or what you saw to make you want to do that.

Well, we saw -- this is again why we do this business. This is why we have the strategy we have in what we are doing.

We stopped drilling at 700 feet of high-quality sand, some of the best-quality sand I have ever seen in my career. So we would have had -- this is a 700-foot-plus type of a column here if we could have had success.

What we had to risk in here is we needed to have oil being formed here and oil being migrated here. We needed a lateral seal against salt for Titan to be very big. 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 a 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 we 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. Once we found that in a very small accumulation we have, we are going to go for this across the fault, adjacent well that we have. Because the modeling work shows that it should accumulate there, and that is why we are doing it.

I would consider it a 25%, 30% chance, as it would be anywhere else in a deepwater portfolio type of a risking.

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

No, we kicked the well off at 20,000 feet; I think we are drilling at 27,000 or 28,000. It will be over in about 40 days, something of that nature.

Okay, great. Thanks very much.

Pavel Molchanov, Raymond James.

Hey, well, I appreciate the fact that you are 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?

Oh, I don't know, Pavel. It just depends on these fictitious things; it's hard to say. I guess it is just hard to say. There is different days, different situations, and I would hate to say that (technical difficulty) it is time.

I would say that typically we do better when we operate. When we are in charge of a field, we bring a competitive advantage to that. And I would just rather leave it at that.

Okay, fair enough. Then on the UK monetization, the press release indicated that concurrent with the sale of the refinery itself you are 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?

We just really at this time trying to say that we are 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 is about exiting that business, becoming focused in 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. And that is what I am focused on.

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

Okay, understood. Then just a quick one on Titan. Any sense of how long until the sidetrack reaches TD?

I have just said that; I think about 45 days from now.

45 days? Okay. I will leave it at that. Thanks, guys.

John Herrlin, Societe Generale.

Yes, hi. 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?

Well, I mean it is strategic and it is a big part of our R-over-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 want to get our R-over-P level to the 10 level and on, and it is in our plan to do that, and it is a key part of that.

Are there other things that could cause that goal to be made and allow it to be less strategic? Yes, I would say today our early entry in the cash it provides and the R-over-P are the main and only strategic advantage it gives me today. But it's had 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. But that is how I view it, as more of an R-over-P, very critical to us at this juncture, but getting less all along.

Okay. That's fine. Last one for me is on the UK. Any charges associated with this sale that you will be taking? Any future charges?

We made a big write-off last year as to the assumed sale. We think we are okay there. But you never know till it's over, and we have got to close out our books.

I would be very anxious, even if it is one, to end this chapter, I assure you.

Okay, yes. That is what I was wondering, whether there was something incremental. Thank you.

That does conclude the question-and-answer session. At this time I would like to turn the conference back to Mr. Roger Jenkins for any additional or closing remarks.

Appreciate everyone calling in today. We be back this same time and station in late October. It will be cool, football season will be going, and we will try to have a better quarter and get rolling here. And we appreciate all the time and we thank you all.

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