Murphy Oil Corp (MUR) 2014 Q1 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation's first-quarter 2014 earnings call. Please note today's conference is being recorded.

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

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 modified our format slightly to introduce some informational slides as part of our webcast and of the call. You can follow along with the slides as part of the webcast, which can be found on the Investor Relations section of our website. Otherwise, today's call will follow our usual format. Kevin will begin by providing a review of first-quarter 2014 results. Roger will then take -- follow-up with the 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.

With that, I'll turn the call over to Kevin.

Thanks, Barry. Net income for the first quarter of 2014 was $155.3 million or $0.85 per diluted share compared to net income in the first quarter of last year of $360.6 million or $1.88 per diluted share. This year's first quarter included a loss from discontinued operations, which includes the UK downstream business of $14 million or $0.08 per diluted share compared to income of $177.9 million last year or $0.93 per diluted share. For 2013, discontinued operations numbers included results from the UK downstream and US retail operations, and also included an after-tax gain of $147.4 million from the sale of two E&P properties in the United Kingdom.

On income from continuing operations, for the first quarter of 2014, it was $169.3 million or $0.93 per diluted share compared to income from continuing ops last year of $182.7 million or $0.95 per diluted share. The decline in 2014 compared to 2013 was primarily due to higher exploration costs in the current quarter, partially offset by more favorable effects from transactions in foreign currencies.

Looking at income by segment, from continuing operations in the E&P segment, we had net income in the first quarter of 2014 of $210.6 million compared to net income in the first quarter of last year of $231.9 million. Although the 2014 quarter was favorably impacted by higher oil sales volumes, this was more than offset by higher exploration costs. Crude oil condensate and gas liquids production for the quarter averaged approximately 137,800 barrels per day in 2014 compared to approximately 126,900 barrels per day in 2013, with the 8.5% increase being mostly attributable to volume growth in the Eagle Ford Shale.

Natural gas volumes were approximately 400 million cubic feet per day in the first quarter of this year compared to 450 million cubic feet per day in the 2013 quarter. This decrease was primarily due to lower production in the Tupper area of British Columbia, where development drilling activities have been voluntarily curtailed since the historically weak North American gas sales prices during the recent years.

In the corporate segment, the first quarter of 2014 saw a net charge of $41.3 million. This compares to a net charge in the first quarter of last year of $49.2 million. This favorable variance was mostly attributable to improved results from transactions denominated in foreign currencies and lower administrative costs somewhat offset by higher interest expense in the current quarter.

During the first quarter of 2014, we initiated the fourth and final $250 million tranche of our $1 billion stock repurchase program. Between the completion of tranche three and the beginning of tranche four, we acquired some 4.3 million shares of our stock during the quarter, bringing the total acquired under the program to just over 16 million shares. At the completion of the ongoing piece, which occur in mid-May, we currently expect to receive approximately 130,000 additional shares.

At the end of the first-quarter 2014, our long-term debt amounted to approximately $3.4 billion, including approximately $342 million related to the Kikeh FPSO lease and 29.1% of total capital employed. Cash, cash equivalents and short-term investments totaled over $1 billion at March 31.

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

Thanks, Kevin. And hello, everyone. First, to some highlights. As Kevin said, we continued our share repurchase under a $1 billion authorized program. We produced an Eagle Ford shale quarterly record, just over 49,600 barrel oil equivalent per day, up 18% from the fourth-quarter of 2013 and 72% from first-quarter of 2013. We completed the Sarawak gas compression upgrade to 300 million cubic feet per day capacity to improve the system's livability. We completed the planned shut-in of the Kikeh field to tie in Sea Cat North to tie development with the first production from the field achieved on February 28 of this year.

We sanctioned the floating LNG project in Block H Malaysia, and we are seeing the full field development plan approval from Petronas. Reached a new single-day production record in March -- just over 226,000 barrel oil equivalent net per day, and averaged near 222,000 barrel equivalent per day net for the entire month of March. We added new exploration acreage in the Central Gulf of Mexico by placing high bids on 16 new blocks at the leech sale in March, and entered into Block 26-13 A/B offshore Namibia in West Africa.

We continue to deliver strong cash margins with our oil weighted price advantaged portfolio. With respect to our UK downstream sales process, this business as mentioned by Kevin, was reported financially as discontinued operations. As previously reported, our exclusive peer with a potential buyer recently expired, and we're now marketing the business to other interested parties. The Company has entered into a period of consultation with certain refinery employees and their representatives. The consultation period began on April 7 and must last at least 45 days, which would put the end of the process on May 22nd. Our goal here is to follow all required protocols and continue with our firm desire to make Murphy a pure play E&P company as soon as possible to redeploy the UK working capital to our upstream business.

As for prices in the first quarter, Malaysia oil net backs remain strong, with realized prices for Block K and Sarawak Oil averaging approximately $100 per barrel post-supplemental payments, despite a $1.00 drop in Brent. The oil indexed SK gas averaged approximately $5.60 per Mcf, including the impact of supplemental payments as well. Our realized oil prices in North America onshore in the Gulf of Mexico increased compared to the fourth quarter of 2013, on improved differentials and increases of over $1.00 per barrel in WTI, and over $4.50 in LLS.

Including the impact of hedges, crude oil prices in the Eagle Ford and Gulf of Mexico averaged $97 and $100 per barrel, respectively, which now excludes the effect of NGLs, which are broken out separately in our financial reports. GL Seal heavy oil netback price improved to near $51 a barrel. In East Coast Canada, we had a strong Brent supported price of just over $107 per barrel. Financially, our portfolio continues to delever, leading EBITDA and EBITDAX metrics.

Looking at EBITDA for quarter-one 2014, we delivered $41.81 per BOE, which compares to the full-year of 2013 metrics of $41.21. EBITDAX for quarter-one 2014 was $49.48 a barrel comparing to $47.89 per barrel in the full-year 2013. Operationally, we see continued improvements in our lease operating expenses in our upstream business. Worldwide LOE for quarter-one 2014, excluding Syncrude, came in at $11.81 a barrel. This compares favorably to a year ago when quarter-one 2013 LOE was $16.35 per BOE, and to quarter-four of last year with an LOE of a little over $19 per BOE.

As we move to North American onshore business in the Eagle Ford shale, the development activity in our largest resource base continues to yield steady production growth. We're currently running eight rigs and three completion spreads across the play, with 381 wells on production. We've brought 44 wells online this quarter, 37 of those operated, and expect to bring a total of 203 total wells online this year with 172 operated. As mentioned in the highlights, the first-quarter production Eagle Ford averaged just over 49,600 barrel equivalents per day, which is up from 41,900 barrels equivalent per day in the fourth quarter, with new wells added and recovery seen from weather issues.

During the first quarter, we set a single -- a new single-day production record of just over 53,000 equivalent per day. We have a highly profitable production mix at Eagle Ford shale, with 82% oil, 9% NGL, and 9% natural gas on a barrel equivalent sale basis. We are implementing 40-acre downspacing on a go-forward basis in all main currents and Tilden development areas, and have significant running room across the entire play, with over 1750 new well locations identified at these downspacing intervals.

While downspacing in the lower portion of the Eagle Ford shales are standard development plan going forward, with three long-term upper Eagle Ford shale wells within our existing acreage at Carnes, Tilden, and Caterina, with over two years of production history each. A staggered well development that integrates the upper Eagle Ford shale has potential at approximately 270 well locations to the full field development on top of the 1750 just mentioned. In addition, we also are testing a fractured area of the upper Eagle Ford shale in the Tilden field.

We continue to evaluate the potential of other zones across our Eagle Ford shale acreage. We are planning two wells to test the Buda Lime in the second half of the year, one in Caterina and the other in the Tilden area. Well performance continues to improve, with technical evolution as we're focusing on well placement optimal lateral length and completion design across the play.

We've hedged approximately 24,000 barrel of oil per day of WTI in the Eagle Ford for the second quarter through fourth quarter of this year, and average price of just over $95 a barrel. Eagle Ford asset continues to improve in cash flow and profitability. After-tax income for this business this quarter yielded $90 million with an EBITDA of $269 million. In Eagle Ford shale operating metrics and operating expenses, we pulled out severance and ad valorem taxes for the first time, and our quarterly update to highlight lease operating expenses, with a total LOE of just over $11 per barrel in Eagle Ford similar to results of quarter-four, and strong improvement of near $7.00 per BOE as compared to last year at this time.

In addition to making good progress in OpEx, we continue to improve drilling and completion costs. Based on current processes, we see Eagle Ford shale near cash flow CapEx parity in the second half of 2014 as production continues to ramp up. In Canada in Seal, we continue to see good progress at our cyclic steam pilot in the Cadotte area, the second pilot well now producing on its fourth cycle, with peak brakes hitting over 600 barrels per day early in the latest cycle.

SOR continues to demonstrate top-tier performance in the pilot. We recently began steam injection on the third pilot well in the field, and the pilot performance to date supports our plans for commercial development in the Cadotte area. In the Montney and the Tupper area in Western Canada, we currently have two rigs operating with current plans to drill approximately 25 wells this year. We are planning to implement a strategy of utilizing slick water 100 ton fracs and a Choate management plan on flowbacks similar to our practice in the Eagle Ford shale.

Offset wells in the area show improved EURs, averaging 4 to 7 Bcf gross per well increase, reserve opportunities like those we've averaged in the past. We have approximately 320 million cubic feet gross of gas processing capacity between Tupper Main and Tupper West gas plants, in addition to processing up to 70 million a day of third-party gas -- 10 million at Tupper and 60 million at Tupper West. The plan is to drill to fill the existing gas processing plant capacity, which will lead to lower overall costs.

We have close to 110 million cubic feet a day of gas hedged at CAD4.00 AECO for 2014, and another 65 million a day at approximately CAD4.10 AECO -- these are both in Canadian dollars.

I'll now move to our global offshore business. In Malaysia, as mentioned earlier, our first production from Siakap North/Petai was achieved on February 28 with four producing wells coming online. We now have six wells producing with two more to follow. The repairs of the Tender Assist Drilling barge used in the Kikeh spar were completed in the first quarter, with the rig back on location. The top copy of landsuit early production system continues to produce to plan through the Murphy-operated Kikeh FPSO.

The two subsea wells that are a portion of the overall field development have now flowed for 17 months, which is greatly de-risked of the resource base, the completion design, and the subsea system operability for the greater field. The non-operated full field Kakap-Gumusut continues to be delayed. And while the field is forecast to start in quarter-three, we have further risks to production in our annual guidance.

Production from our four shallow water oilfield developments placed on production earlier this year, offshore Sarawak continued to plan and will contribute to our production growth in 2014. Long-term gas and Sarawak gas project, we have a contracted volume there of 250 million cubic feet per day gross. We have worked with our partner Petronas in developing a new compression gas compression system that would allow gross production levels of 300 million cubic feet per day of full redundancy.

We completed the project, improved the well delivery and system capacity by producing in excess of 300 million per day for a 24-hour period. This increased capacity provides the opportunity to deliver rates above contracted volume. As reported earlier, the block H Malaysia floating LNG project with our partner Petronas is now fully sanctioned by both parties. The field development plan is approved with oil linked gas price terms agreed. We are beginning engineering and procurement work and anticipated awarding initial upstream contracts in the first half of 2015.

In the Gulf of Mexico, the Transocean Discovery deep-sea has finished up the completion operations on the two wells at Dalmatian, with one well-being an oil producer and the other being a high-yield gas well. First gas production began on April 20, with oil production in the second well scheduled later in quarter-two. The Company has acquired a 29% working interest in the Kodiak oil field located in Mississippi Canyon Block 7-27 and 7-71. The field is being developed as a two-well tieback to Devils Tower host platform, with first production expected in late 2015. We expect to hit peak production near 5000 barrels a day net in 2017.

In exploration, in the Gulf of Mexico, the Central East sale in March, the Company was named high bidder on 16 new blocks that focus on Norphlet and Upper Miocene amplitude plays. The Titan well in DeSoto Canyon Block 178 spud on April 4, with the Discovery deep-sea and expect to reach TB in early August. We hold a promoted 50% working interest and operate the well. This well is targeting oil in Jurassic Norphlet sands with a pre-drill gross mean resource estimate in the range of 200 million barrels. The Titan well is located in the most northern portion of the play fairway and is in close proximity to other successful Norphlet wells.

We farmed into the Oka prospect located in Mississippi Canyon Blocks 653 to 697 as operator with a 50% working interest. This prospect is targeting oil in the Midland lower Miocenes with a mean resource level of near 130 million barrels. We expect to spud this well in the second quarter.

Our Southeast Asia focus area in Vietnam, our partner Santos has spud the Block 13-03 Hon Khoai-1 exploration well on April 27. Murphy holds a 20% working interest. The well is targeting the Oligocene sandstone in a faulted four-way track with a pre-drill gross mean resource estimate of approximately 90 million barrels equivalent. Another Shell order activity we continue to progress our valuation. We recently acquired 3-D seismic survey over Block 11-2, and the Deepwater of 5000 kilometer 2-D seismic program in Blocks 144-145 has been completed.

In Indonesia, we expect to spud our two remaining commitment wells in the Semai II Block starting in May. We added to our prospect inventory in the Atlantic margin with a farm-in to Block 26-13 A/B in the Luderitz Basin offshore Namibia. We will operate this block with a 40% working interest. The area is prospective with high impact oil prospects and multiple play types, and we have a 5000 square kilometer 3-D program already ongoing.

An offshore EG in Block W, we completed acquisition of 3-D seismic through our partnership group in the first quarter, and we are processing the data. On our NTM block offshore Cameroon, we expensed the Bamboo-1 well and plugged in abandonment as a dry hole.

In Australia, we continue with our strategy to acquire acreage in underexplored oil-prone basins with an entry in the Vulcan Basin in Northern Australia offshore. We were awarded one block as operator with 60% working interest, with Mitsui as our partner. The Basin has multiple oil and condensate discoveries and excellent reservoirs. In our Ceduna Basin acreage in Block EPP-43, we hold a 50% working interest and operatorship. We're in the process of confirming our plan to acquire approximately 8000 square kilometers of 3-D seismic in the fourth quarter of 2014, about a year ahead of schedule.

On drilling and seismic work for the full-year, as highlighted on our exploration schedule, we expect to spud 4 to 5 wells this year with a focus on high-impact prospects. As we look at production, first-quarter production averaged 204,436 barrels oil equivalent per day, which is 1% lower than last quarter, while shutting in the Kikeh field for 18 days. Production guidance for second quarter is 217,000 barrel equivalent per day. So far in 2014, we've placed Kikeh North/Petaion production. We progressed Dalmatian with first production on April 20. We added 44 wells in the Eagle Ford shale. We ramped up the four new Sarawak oil fields. We tested the new 300 million cubic feet per day capacity for Sarawak gas.

In fact, we are on track to establish another production record this year, which will be our third consecutive year we've achieved record volumes. Our annual production guidance is now 225,000 to 230,000 barrel oil equivalent per day, primarily reflecting reductions at two nonoperated properties. While the start up of Kakap-Gumusut project is now estimated for third quarter, to further risk the start rate of Syncrude will have a recently announced, unplanned maintenance downtime event. This revised guidance represents an increase of approximately 11% over 2013 production levels.

We've added a great deal of balance and predictability to our global portfolio, with a focus on North American onshore. We have divided our production per well metric by four since 2010. However, we are still subject to minor production guidance issues associated with global deepwater execution and reliance on third-party performance. Our strategy of maintaining a balanced portfolio continues to add value, with our global offshore business provided over half of our quarter-one production of cash margins exceeding those generated by North American onshore business. CapEx in 2014 continues to be on track at near-budgeted levels of $3.8 billion.

With some closing takeaways here, we're still on track to deliver double-digit production growth, led by our operating positions in Malaysia and Eagle Ford Shale. Our oil-weighted diverse portfolio continues to produce competitive financial metrics. The fields we operate are moving forward to plans this year. Our focus continues on international exploration with seismic execution, Namibia intrigue, and a well spud in Vietnam.

Our refocus on the Gulf of Mexico continues with the spud of Titan, high bid in the recent lease sale, and new entries at Erka and Kodiak. The Sarawak gas compression expansion provides upside to our oil indexed gas business in Malaysia. And finally, our early entry into the prolific Eagle Ford shale is producing results for our shareholders with significant running room ahead.

That's all I have today. And I'll open it up for the questions you might have.

(Operator Instructions). Paul Sankey, Wolfe Research.

Forgive me if I missed this but could you just repeat or go over the UK refining process timing and plans? Thank you.

Well, the business, Paul, as you know, we want to not be in that business anymore because there's certain protocols and processes to do that. We -- at the refinery, if you want to cease operations in a refinery like that, you have to consult with the Union and their representatives for a certain period of time. We started that process on April 7. It's continued work and meetings on that and that will end on May 22. It will be the first step toward doing that.

We are engaged with people who want to buy the business as we have been in the past. And all that continues. But I think it's a -- in my mind, it's a point in time we are no longer a purchasing crude there and people that are interested in buying the refinery know that. And it's part of -- got to stop somewhere and get ready to move forward and that's what we're doing.

Right. So the May 22nd is kind of a hard-line at which point I think you referenced that you would be releasing working capital, I guess it would be a shutdown process?

We'll have to then get rid of the midstream business, sell it to someone -- not get rid of -- sell; it's valuable. Sell the retail business. It will take a while if we do not find a buyer to get that freed up, Paul.

Okay, sorry to keep pressing on this so what's the overall timing that we'd be looking for, for this to be resolved?

If we don't have someone take it out between now and then and buy the business in parts, it could take upwards of a year for that to happen, Paul.

Right, I understand. Secondly, it sounded -- I don't know if you slightly changed your disclosure in your communications but it sounded like you greatly increased your leasing and crossed the seismic level activities across the globe. Is that just the way you are kind of handling the call or is that a real step up? I would've thought that that would be cost associated with that. But your CapEx seems to be in line with guidance. Am I sort of missing something here?

No, we're guiding the exploration expenses, are we not, Barry?

Oh yes, everything is part of our plan, Paul.

Yes. But I guess the way the call came across, it sounds like you had a significant step up in leasing.

No, not really. We had in our budget in our CapEx to enter into the lease sale in central Gulf. We've participated in sale probably slightly lower than we had in the budget. We had all these seismic areas in our budget absolutely. And I think we disclose every quarter how much is going to be spent that quarter, and the last quarter and how much we are prognosing for the next. And it's all in our plan, all in our exploration spend and our CapEx has not been increased.

Great. That's what I wanted to clarify. Thanks a lot then.

Thank you.

Ed Westlake, Credit Suisse.

Yes, I'm -- thanks for your time this morning. I'm just interested I guess there's been lots of press circling around the overall strategy within Malaysia. I mean, there's more prospects to drill. There's obviously a lot of cash flow. But any comments on the potential sale of a stake?

No. You know, Ed, we've said this a bunch of times. I'm not a guy to talk about business development opportunities and I don't want to turn this call into just a win, win, win, on business development. We have a lot of things in our portfolio. I think we are taking a closer look at our portfolio. We have a very nice risk development team we formed in Houston with experienced staff. We are looking at both our portfolio and external to our portfolio.

And I think in those type of pockets, just like an example here in the UK -- I got out ahead of that a long time ago and said we are going to sell that. And it's become when now, I don't know -- I guess 12 quarters in a row or more? So I'm not really going to comment on timing and plans on that type of event, and when you hear about it, you'll read about it in the paper.

Okay. And then just operationally, I saw some decent wells in Caterina Dimmit County. And obviously you've got a decent well inventory there. Maybe talk through -- obviously you mentioned the upper Eagle Ford inventory potential. At what point would you come back to the market and update us about your sort of plateau for the Eagle Ford production, given that you're doing a good job so far?

Oh, we're real happy with the Eagle Ford there. We're heading up into the [60's] and marching our way up to 70,000 barrel equivalent net. We are in oil player in the Eagle Ford, not a gas player. Briggs has been in place at some of our lower -- you know we have three different distinct plays over very vast wide acreage positions. We've disclosed a good bit of information about how to model that.

It's a 200,000 barrel plus EUR to us, but we do have some very, very nice wells that continue on to produce. And it looks like we will have some EUR increases there. And we are intrigued by upper Eagle Ford there. We think we have a good bit of it in our acreage position in our northern part of our -- our Caterina area is quite one big block, if you will, and we have some very, very nice wells there.

And if you look at our high wheel deck from a month or so ago, you'll get some information about that. So we have 130 locations at upper Eagle Ford there. We have 270 total upper that would include that number. I think what we're trying to do is to pay close attention to not overcapitalize Eagle Ford. We're doing a lot of reservoir analysis around what is the proper downspacing; just not jump in and go to 40s across the play.

We see this to be about a 72-acre downspace as the best recovery for us. But if we could get an upper Eagle Ford going, where it would be on a 40-acre and the rest of the lower would be on a 70, we could be quite a prolific play for us. These are not the headline-making wells. These are 200 barrel a day wells that make 200 for a long time with real low costs and pretty shallow depth. So a lot of running room left there.

But we are not going to be a player probably to increase the plateau in Eagle Ford. We want this to be a long flat business and not turn it into an offshore business, because we want our onshore to be a balance affect to the other things that we're trying to do. And probably aren't interested in changing CapEx or changing the strategy in the Eagle Ford, even though we have some success in the Caterina area right now, Ed.

Great. And you mentioned the Howard Weil presentation. Lots of great new slides. So thanks to you and Barry for that. One little small question. Gulf of Mexico seems to be growing quite substantially. I know you've got some projects to bringing on. But I'm just trying to get some color as to why Gulf goes from sort of 15-ish up to 30, just reading off the slide?

Well, we have -- we are bringing in Dalmatian. Dalmatian is a BOE machine. Now we male 52 million a day on that well today and we have another oil well to go at very, very nice pace. And the well was already completed. So the Gulf is known for high rate. The Gulf is known for high NPV due to high rates. And we've been in the Gulf for all of our careers here, and it's just a place I see as all the topics for a company just about in our industry other, and I want to be there. And we are playing it heavy there.

So, mainly Dalmatian and that small acquisition you made?

Yes, there is Medusa -- Medusa has been one -- Medusa is one of the highest, most profitable margin businesses in Murphy history. And it's produced so long in the original completions that we have to do some subsea work out there at times. So we have two wells and Dalmatian coming on. We have a Medusa subsea development that is in our plan. We have a third well to add in Dalmatian next year. And then we are participating in this entry we just made into a ground-floor entry into a development in the Gulf. So, focusing back on it again and the profile we have in our plan would be the things I just mentioned.

Thank you very much.

Thank you.

Guy Baber, Simmons & Company.

I had -- my first question was around the 2014 production guidance. So you reduced the guidance by about 10,000 barrels a day on Syncrude and Gumusut. But the cut seems a little bit bigger than we would have expected just looking at those two items. So the question is, is there anything else contributing to your changing view? And could you be a bit more specific on the split there?

And then when are you assuming that Gumusut actually begins to ramp up? Have you basically taken that out of 2014, even though you mentioned a 3Q start-up?

Hey, let me walk you through it here, Guy. Glad to do it. January 7, we issued a press release that said our guidance would be to 235 to 240. The reason that was lowered is we had a shut-in of Kikeh that's moved into this year, which is just pure shut-in of the field. That was 1650 barrels for the year. We had a fire on our rig there that's attached to this barge. We had to move the barge to Singapore and repair it. That's 3350 barrels a day. That adds up to 5000 barrels a day.

So that's why our guidance was at 237.5, would be the midpoint of the 235 to 240 range. So we are sitting here with the big field. Every month that Kakap is late, there's over 750 barrels a day for the year for Murphy. It became apparent that the operator would not have production in March. So if we move it to March to July, that's 3000 barrels a day.

Syncrude coker repairs were absolutely 1000 barrels a day. So those items are real, lowering that 237 down by 4000 to 233. I then said to myself, you know, I have a lot of risk going on in my business offshore. I have different things that could happen in execution. So I lowered down 2000 just 1% for global risk business across our whole business. That gets my plan to around -- I got my folks focusing on 231 to 233 a day.

Then I went and said that Syncrude in the past has disappointed me, about like this Kakap thing has disappointed me. So I added [four-more-thousand], I moved Kakap out to November, the end of November. So, I think it will happen in July. I don't know, but the next time I speak to you, Guy, will be right here, the day it's supposed to flow. And I don't want to lower this guidance again and have to read about it on my iPhone in bed over and over and over again. So I lowered the hell out of it so I don't have to do that.

Okay, great. That's very helpful. Thanks for that. And then my follow-up was I wanted to ask about your Malaysian oil price realization. So, realizations relative to Brent, obviously very strong this quarter. You mentioned that in your comments. The strongest it's been in some time. Was there anything specific driving back from a mix perspective? I know there's some moving parts with your Malaysian production right now. So just wondering if there's anything you could point to? And how we should be thinking about that going forward?

Oh, I think it was an exceptional quarter. I don't know if it will be that high coming up in the next. I'll let John comment as to what we are estimating on that.

Yes, I mean Q1, as you said, Guy, came in pretty strong, just shy of $100 on our sub after supplemental payment. I think for Q2, we are rolling about maybe just in the $90 range for Q2. So we are not seeing it quite as strong looking forward.

Okay, great. Thanks, guys. Appreciate it.

Leo Mariani, RBC.

I was hoping you could speak in a little bit more detail to the ramp you might see in production at Sarawak gas. You basically talked about adding compression, getting that capacity up. I know you got the contract for 250, but maybe hopeful to sort of expand that or whatever. Could you maybe just give us some color on what might occur there and what the timing could be? I'm assuming that you don't have any of that expansion in your guidance this year, but maybe just kind of walk us through how that could unfold over the next couple of years.

Well, I mean, this is something that we work with our partner Petronas on with the LNG business, and we have spot sales and you know the leader in LNG value chain in the world. So when they want you to increase compression usage, you try to do it. We did get a few days in there. There's been lots of times in the history of this project where I've always felt that if we had more ability, we could sell more gas.

And what will happen is, it will be month-to-month we'll get a higher demand, if you will, from them. We probably have a little more than we normally would in our guidance because of that. We usually try to go 250 gross where there's some downtime. We'll probably up that to about 258 gross, due to some word we got from them they want some higher volumes.

So I think it gives us a little bit -- that's not much. Maybe take 8000 Mcf gross there for a couple of months, that's not a big deal for me. But it gives me a lot of ability to make hay when the sun shines over there. We have the subsurface ability there. We have many platforms there. We delivered -- when I say we deliver this capacity, it's a big deal, because I lower my -- all my suction pressure, all my fields. And I was able to do it from a reservoir perspective, all that behaved very well.

This is a giant compression package. It's 200 million, 300 million day units, so we have double redundancy there. We actually even do more than 300 million one day possibly with them. So it's something they wanted us to do. They're expanding into other LNG trains. Very excited about it, and it gives us a chance now and then to get more volume. But it will not be something at this time that we will be guiding towards 300 million a day gross until -- unless we change the contract, which we do not have for in place with them today.

Okay. And I guess can you also just comment on pricing? I mean I'm just kind of looking at historical pricing. It looks like it's been ticking down over the last several quarters here. What's kind of causing that? And what should we expect it to do for the rest of the year?

Well, as you know, we are in a PFC environment here and we do -- these are our received revenue over cost fields. They are by block. Certain platforms in some blocks are in others. We crossed one of those thresholds for Block 309 in the first quarter, so our entitlement went down slightly. We're talking 66% in the fourth quarter to 64% this quarter. When you do that you get into the supplemental payment. And so we lost a little bit of room there on price because we made a lot of money there actually.

So it's been a slight pull-down in price, and I think it will be time now to recalibrate where we are as compared to JCC, which is very, very close to Brent pricing. if you take that factor and start making a new day. Our supplemental payment in 309 was $1.10 Mcf in the fourth quarter. And it went to $2.21 this year. So we've lost a little over $1.00 there on a $1.00 per Mcf because we've produced a lot of Bcfs.

All right. And I guess maybe you guys could give us a little more color on block H? I know you said you're going to start feeding out some of the construction work in the first half of 2015. Now that it's sanctioned, do you have a better idea of when we can see first gas over there?

Well, it's sanctioned to be second quarter of 2018. Lee, I don't know this, they'd beat the hell out of me if I lower anything at all. So I'm certainly not coming off a brand-new sanction after a month and tell you an early gas let some guy beat the hell out of me about it, if I'm still alive in 2018. So it's supposed to flow then. It is very, very good to have Petronas full onboard. It's a very complicated sanction in process because their gas part of their business owns the ship. We have the upstream. They have time to contract and they are starting construction. This will be their second vessel.

So I'm feeling pretty good about all that but it is leading new technology, and they are the leader in it. And we are fortunate enough to be with them on it. And just really, I'm firm about that date of second quarter. And we also have some pretty, pretty high downtime for something of this new technology in our forecast that was out late -- recently. But we only guided through 2019, so this thing really flows most of its life past that. It will be a 10-year field at 250 million a day type number.

Okay. And I guess can you guys just speak a little bit more to Dalmatian? You mentioned kind of a liquids rich gas well that's already on production, and oil well coming on later, I guess, this quarter. Just wanted to get a better sense of what the production split is there? And I guess the gas wells are like a percentage NGL associated with that. And the oil well, is that just all oil? Will there be some gas there too? Just any color you had around that would be helpful.

Yes, the well is about a -- you know, we are an oil company. Kevin and I were talking before the call, we don't do Mcfe. But this is a 50 -- today I made 52 million Mcfe, I suppose. About 1200 barrels of that equivalent would be NGL. So that would be whatever 1200 times 6 is, and the rest would be gas. That's 42 million plus the NGL kind of number.

That well is just a pure straightforward deepwater Gulf of Mexico prolific gas pay zone that should produce fine, and the Oil well -- oh, it's probably a 10,000 barrel a day type well. And we are spooling pipe offshore to hook it back into the facility. The umbilical is laid and all the subsea equipment is laid. Subsea tree is on the well, the well is completed, and we hope to flow that well later this quarter.

All right. And I guess just in terms of the Eagle Ford, I think maybe you said you had eight operator rigs. Can you give us the split by area between Tilden, Carnes, and Caterina?

We usually run 1 to 2 in Carnes, 4 in Tilden and 2 in Caterina, something like that.

Okay. And I guess what's the timing of the Namibia spud?

We just got -- we're just getting the seismic, so it's been an event 2016, 2017 type thing. So we do not have a well commitment on the block, but we have to go shoot the 3-D. And they've already started doing that now. So it will be a year or more before we would be ready to spud there.

Okay, thanks, guys.

Paul Cheng, Barclays.

On Eagle Ford, then, Roger, can you just remind us that what is your net acreage position now there subject to the 40 acres?

Barry, do you have that number broken out? We have a slide that's got all our (multiple speakers) --

We have around 155,000 oil acres there, Paul.

I'll look it up, Paul. But in Carnes, we are just a little less than 15,000 acres in Carnes net, so that's all being developed on 40s. And then you go to the main Tilden field and that's probably in the neighborhood of 50, but I'll look it up for you.

Okay. Yes, you can just shoot me a quick email afterwards; that would be great. And theoretically, I mean, let's not talk about say whether you're going to sell down Malaysia or not, in the event that after you say close down the refinery in UK and release the working capital, and also that sale with the retail operation, in the event that you also are going to sell down in Malaysia, so you (multiple speakers) receive the money, how are we going to look at the priority of that cash?

Well, like I said, we formed a business development team and look at many opportunities, both in our portfolio and external. We have been in data rooms in Permian. If you noticed in my comments today, we do have a very small ground-floor purchase of a subsea tieback in Gulf of Mexico. Those things are very economic, very prolific. We're not going to do some giant M&A thing, but we would like to look at some $1 billion-type M&A that's available, that can help our Company, that can help and add return.

It can -- I'm not interested in a story. I'm not interested in buying something to change one attribute of the Company or that nature. We are looking at deepwater Gulf, looking at North American primarily. And that's part of our ongoing thing and looking at many, many business development opportunities. But that's what we're focusing on today.

So it would be essentially that (multiple speakers) --

(multiple speakers) Let me add one more thing to that, Paul. I forgot. It's a big thing I forgot here. Share repurchase is a big part of where we are headed and we are very happy about how that's going. So if you look at the FTD metric and you looked at our cash flow multiple how we trade, that would always be a part of any of those scenarios at some level.

Roger, do you have a internal target -- you have somewhat of the one-time excess cash mix that -- how is the split between return of cash to shareholder and plowing it back into the business development?

No, I don't have any. We're going to look at opportunities that coincide with all the list of what-ifs you mentioned, and when all that adds up, we'll look at them that day and compare all opportunities to share repurchase and look at it as we go forward. No playbook of that nature developing now.

I see. And you reiterate the 2014 CapEx of $3.8 billion. Any kind of early look for 2015, 2016 in CapEx in terms of production as well?

We are not making any changes today as to what we've guided on to production from our Howard Weil day, which would be the most recent thing we've put out. And these issues we're having today are delays in startup of logged, completed in-the-field, hooked up issues. It's not anything to do with subsurface.

We anticipate by the end of the year, we'll get all these things going again, that we'll be in our portfolio an occasional miss, but our portfolio is very, very profitable. Our portfolio delivers EBITDAX and EBITDA for BOE metrics that I'll put up against anyone. Our net income per BOE I'll put up against anyone in our new peer group that's pure E&P. And when you're doing all that and you have these big high, high-margin offshore projects, to me it's worth it on occasion. And that's about -- that's the story about investing here.

Okay. Two final questions. One, at this point since you're going through the consultation, just your discussion or sales process in UK is still just focusing on selling it as a package? Or you already actually start the process looking at it as a different package?

We are looking at all alternatives to recapitalize -- put that money here, Paul.

Okay. A final one then. I think a couple years -- several years ago that you guys put some position in the Bakken up in Canada. Is that essentially at this point that you have determined that this really don't have a future in the portfolio or that you are still looking at it?

We were in the southern Alberta area. We were never in the Bakken. We were never that far east. We were more western of what I consider core Bakken. We had some experimental wells there. It did not go well for us and we are not in that business today.

Okay. Perfect. Thank you.

Taken care of financially and over with now.

Thank you.

Roger Read, Wells Fargo.

Hopefully, you got some sleep after reading all the production lower guidance commentary last night.

Actually, I did not.

Oh, that's too bad. Taking a look at Milford Haven, the reports in the press that you've quit crude purchases there, I'm not really asking you to confirm that. But if we think about working capital tied up in that unit, if you do sell it or if you are halting purchases, what's sort of the right amount of capital tied up in that from just an inventory standpoint?

Roger, this is Kevin. Those numbers bounce around as we run off crudes, turn it into product and distribute it out through the retail system. It's still the best way to look at that. The number we've been using of cash that we would bring back to the US is in the neighborhood of (technical difficulty) [$600 million]. And that is still a decent number to use going forward as of now.

The only thing that's really changed is the timing. It may come back and it's possible it could come back in pieces rather than all at one time, depending on how the transaction progresses.

Okay. And then just as a question off the last presentation, there's, on the exploration side, slide 34, a Gulf of Mexico opportunity is highlighted in the second quarter. Is there any more detail you can provide on that? Or is that date maybe sliding a little bit? It's kind of in very end of Q2 by the positioning of the star. (multiple speakers)

Probably need to put out and look at the slides included as part of this presentation. Roger, it's on slide 14. It went along with the website. That would be the spud of Erka, which we've entered into with Petrobras and which we are operator, and have a rig signed up and a rig is supposed to be available in June.

Okay. And did you provide a potential reserve size on that?

Yes, it was in my comments. It's 130 million barrels (technical difficulty) very near our Thunder Hawk area, near Big Bend discovery by other operator and very near blind faith. A very, very good zip Code area.

Okay, great. Thank you.

Okay, Paul.

Peter Kissel, Howard Weil.

Thanks for taking my questions. I wanted to start with just on modeling really. Operating costs or LOE as you mentioned in particular, Roger, came in at a very reasonable level in the first quarter. And I was just wondering if you could comment on the direction for LOEs for the remainder of the year? Is there any particular quarter we should be aware of where it may fluctuate? Or is it safe to assume it's relatively flat from here?

Well, I think, overall, it's not going to go down much more. I think if you look at Eagle Ford Shale, it's going to be, for this year, we're planning on like a [$10.27] for the whole year there. That's one of our bigger businesses. I think that it will be (technical difficulty), what was our budget number we have, excluding Syncrude, John? It's $11 (multiple speakers) --?

We're still saying around $11. (multiple speakers)

But that's the thing you've got to -- that's the thing that people have to understand about us. We have occasionally an expensive workover offshore. It can cost $20 million or $30 million. We could spike up one quarter $15 per BOE can happen. At the end of the day, we feel our $11 type OpEx is going to be good for the year. But if you haven't been with us long, Pete, it's a bit of a roller coaster to get these kind of margins. It's not that simple.

Got you. I hear you, Roger. Thank you. And then maybe just one follow-up question from an earlier question, and more of a clarification than anything, Roger. But you mentioned 72 acre spacing in Caterina in the Eagle Ford, at least in terms of the middle Eagle Ford. Is that the tightest you think you can go? Or is that just the tightest you've been so far, in which case there may be some opportunity for downspacing? Again, just out of the middle Eagle Ford?

I think that we call it lower and upper. We are not using the word middle, but there's always a new name invented in the Eagle Ford every day. We don't want to overcapitalize this area because it's not one of our high EUR areas. So we are very careful with the reservoir we are modeling around what will be the optimum thing.

So, we have a couple rigs in there. We can't get too far -- I also think it's very difficult to drill a whole field one way and then come downspace it again later. I think it would be quite problematic. But when we look at this staggered approach where we are putting the upper with the lower, then it will be downspaced to 40, if you will, with one riding on top of the other.

I do believe we have some upside there that's not in here today. It will take some reservoir analysis or some nearby competitor analysis for us to probably downspace in what we call lower Eagle Ford in the Caterina area. But right now, our focus would be this upper Eagle Ford, where we've had the better well results, which is shown in our slide 9 today in our deck in that particular area. It'd probably be some of our better upper Eagle Ford, as compared to the main part of the field.

So a little step at a time here, and look at some upper Eagle Ford downspace to a true 40 with the lower being -- when I say 72, we are doing it around 80; it depends on the shape of the lease and the lateral length, et cetera. But that's the plan for now, Pete.

Great. That's helpful, thanks.

Thank you.

Our final question will come from Pavel Molchanov with Raymond James.

Thanks for squeezing me in. Can I just go back to Milford Haven? Are there any regulatory constraints that you would -- any hoops you have to jump through before you can make a decision on a shutdown? And I'm thinking either at the kind of local authority level or the national government level?

No, they're not, but there is a protocol and it would be very inappropriate to break the protocol. Not looking to do so at this time. So the absolute answer to the question is, no, they're not.

Okay. And regardless of what happens with the refinery itself, are you going to essentially get rid of the retail network as well? Is that a package deal? Or can you keep one versus the other?

It is not my desire to be in any downstream business of any kind here or there or anywhere.

Okay. Clear enough.

All right. Thanks a lot.

That concludes today's question-and-answer session. At this time, I would like to turn the conference over back to our speakers for any additional or closing remarks.

That's all we have today. We appreciate everyone following along. We had a new format today, and I appreciate that and the good questions. And we'll see you guys in early August. Appreciate it and thank you.

This concludes today's conference. We thank you for your participation.