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Murphy Oil (NYSE:MUR)

Q1 2014 Earnings Call

May 01, 2014 1:00 pm ET

Executives

Barry F.R. Jeffery - Vice President of Investor Relations

Kevin G. Fitzgerald - Chief Financial Officer and Executive Vice President

Roger W. Jenkins - Chief Executive Officer, President, Director and Member of Executive Committee

John W. Eckart - Senior Vice President, Principal Accounting Officer and Controller

Analysts

Paul I. Sankey - Wolfe Research, LLC

Edward Westlake - Crédit Suisse AG, Research Division

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

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

Paul Y. Cheng - Barclays Capital, Research Division

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

Peter Kissel - Howard Weil Incorporated, Research Division

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

Operator

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation First Quarter 2014 Earnings Call. Please note, today's conference is being recorded. I would now like to turn the call over to Mr. Barry Jeffery, Vice President, Investor Relations. Please go ahead, sir.

Barry F.R. Jeffery

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

We've modified our format slightly and have introduced some informational slides as part of our webcasting of the call. You can follow along with the slides that's 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 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.

Kevin G. Fitzgerald

Thanks, Barry. Net income for the first quarter of 2014 was $155.3 million or $0.85 per diluted share, compares 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 U.K. 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. The 2013 discontinued operations numbers included results from the U.K. downstream and U.S. retail operations and also included an aftertax gain of $147.4 million from the sale of 2 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 '13 quarter. This decrease was primarily due to lower production in the Tupper area of British Columbia, where development drilling activities have been voluntary curtailed due to historically weak North American gas sales prices during the recent years.

In the corporate segment, 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 low 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 3 and the beginning of tranche 4, we acquired some 4.3 million shares of our stock during the quarter, bringing the total acquired on the program to just over 16 million shares. At the completion of the ongoing piece, which should 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 Kakap FPSO lease or 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.

Roger W. Jenkins

Thanks, Kevin, and hello, everyone. First, just some highlights. As Kevin said, we continued our share repurchase under our $1 billion authorized program. We produced an Eagle Ford Shale quarterly record of just over 49,600 barrel oil equivalent per day, up 18% from the fourth quarter of '13 and 72% from first quarter of 2013. We completed the Sarawak Gas compression upgrade to 300 million cubic feet per day capacity, improved the system deliverability. We completed the planned shut-in of Kikeh field to tie in Siakap North-Petai development, with first production from the field achieved on February 28 of this year. We sanctioned the Floating LNG project in Block H Malaysia, received a full Field Development Plan approval from Petronas. We reached a new single-day production record in March of 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 lease sale in March and entered into Block 2613 A/B offshore Namibia in West Africa. We continue to deliver strong cash margins with our oil-weighted price advantage portfolio.

With respect to our U.K. downstream sales process, this business, as mentioned by Kevin, is reported financially as discontinued operations. As previously reported, our exclusive period with a potential buyer recently expired. 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 22. 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 and redeploy the U.K. working capital to our upstream business.

As for prices in the first quarter, Malaysia oil netbacks remained strong with realized prices for Block K and Sarawak oil averaging approximately $100 per barrel post-supplemental payment, despite a $1 drop in Brent. Our 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 and the Gulf of Mexico increased compared to the fourth quarter of '13 on improved differentials and increases of over $1 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.

Seal heavy oil netback price improved to near $51 per barrel. In East Coast Canada, we had a strong Brent-supported price of just over $107 per barrel.

Financially, our portfolio continues to deliver leading EBITDA and EBITDAX metrics. Looking at EBITDA for quarter 1 '14, we delivered $41.81 per BOE, which compares to the full year of 2013 metric of $41.21. EBITDAX for quarter 1 '14 was $49.48 a barrel comparing to $47.89 per barrel in full year 2013.

Operationally, we see continued improvements in our lease operating expenses in our upstream business. Worldwide LOE for quarter 1 2014, excluding Syncrude, came in at $11.81 a barrel. This compares favorably to a year ago, when quarter 1 '13 LOE was $16.35 per BOE, and to quarter 4 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, our development activity in our largest resource base continues to yield steady production growth. We're currently running 8 rigs and 3 completion spreads across the play, with 381 wells on production. We 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 in 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're implementing 40-acre downspacing on a go-forward basis in all main Karnes and Tilden development areas and have significant running room across the entire play, with over 1,750 new well locations identified at these downspacing intervals.

While downspacing in the lower portion of the Eagle Ford Shale's our standard development plan going forward, we have 3 long-term Upper Eagle Ford Shale wells within our existing acreage at Karnes, Tilden and Catarina with over 2 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 field -- to the full field development on top of the 1,750 just mentioned.

In addition, we're also testing a fractured area of the Upper Eagle Ford Shale in the Tilden field. We'll continue to evaluate the potential of other zones across our Eagle Ford Shale acreage. We're planning 2 wells to test the Buda Lime in the second half of the year, one in Catarina and the other in the Tilden area. Well performance continues to improve through 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 second quarter through fourth quarter of this year at an average price of just over $95 a barrel.

Our Eagle Ford asset continues to improve in cash flow and profitability. Aftertax income for this business this quarter yielded $90 million, with an EBITDA of $269 million.

In Eagle Ford Shale operating metrics -- in operating expenses, we pulled up severance and ad valorem taxes for the first time in our quarterly update to highlight lease operating expenses. We had a total LOE of just over $11 per barrel in the Eagle Ford, similar to results in quarter 4, and strong improvement of near $7 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 prices, we see Eagle Ford Shale near cash flow CapEx parity in the second half of 2014 as production continues to ramp up.

In Canada and Seal, we continue to see good progress at our cyclic steam pilot in the Cadotte area. The second pilot well is now producing on its fourth cycle, with peak rate sitting over 600 barrels per day early in its latest cycle. SOR continues to demonstrate top-tier performance in the pilot. We recently began steam injection on a third pilot well in the field, and the pilot performance to date supports our plans for commercial development in the Cadotte area.

In Montney and the Tupper area in Western Canada, we currently have 2 rigs operating with current plans to drill approximately 25 wells this year. We're planning to implement a strategy of utilizing slick water 100-ton fracs and a choke management plan on flowbacks, similar to our practices in the Eagle Ford Shale. Offset wells in the area show improved EURs, averaging 4 to 7 Bcf gross per well increase reserve opportunities to what 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 at Tupper and 60 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 CAD 4 AECO for 2014 and another $65 million a day at approximately CAD 4.10 AECO. These are both in Canadian dollars.

We'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 4 producing wells coming online. We now have 6 wells producing with 2 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 Kakap-Gumusut early production system continues to produce to plan to the Murphy-operated Kikeh FPSO. The 2 subsea wells that are a portion of the overall field development have now flowed for 17 months, which has greatly derisked the resource base, the completion design and the subsea system operability for the greater field. The nonoperated full field Kakap-Gumusut continues to be delayed. And while the field is forecast to start in quarter 3, we have further risked the production in our annual guidance.

Production from our 4 shallow water oilfield developments placed on production early this year offshore Sarawak continue to plan and will contribute to our production growth in 2014. Long-term gas in the 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 a gross production level of 300 million cubic feet per day with 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 Plans approved, with oil-linked gas price terms agreed. We're beginning engineering and procurement work and anticipate awarding initial upstream contracts in the first half of 2015.

In the Gulf of Mexico, the Transocean Discoverer Deep Seas finished up the completion operations on the 2 wells at Dalmatian, with 1 well being an oil producer and the other being a high-yield gas well. First gas production began on April 20, with oil production on the second well scheduled later in quarter 2.

The company has acquired a 29% working interest in the Kodiak oilfield located in Mississippi Canyon Blocks 727 and 771. The field is being developed as a 2-well tie-back to Devils Tower host platform, with first production expected in late 2015. We expect to hit peak production of near 5,000 barrels a day net in 2017.

In exploration, in the Gulf of Mexico, the central lease sale in March, the company was named high bidder on 16 new blocks, with focus on Norphlet and Upper Miocene amplitude plays. The Titan well in DeSoto Canyon Block 178 spud on April 4 with the Discoverer Deep Seas, and we expect to reach TD 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 predrill 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 close proximity to other successful Norphlet wells.

We farmed into the Urca prospect located in Mississippi Canyon Blocks 653 and 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 with 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 4-way trap with predrill gross mean resource estimate of approximately 90 million barrels equivalent. In other shallow-water activity, we continue to progress our evaluation of the recently acquired 3D seismic survey over Block 11-2. In the deepwater, 5,000-kilometer 2D seismic program in Blocks 144-145 has been completed. In Indonesia, we expect to spud our 2 remaining commitment wells in the Semai II Block starting in May.

We added to our prospect inventory in Atlantic Margin with a farm-in to Block 2613 A/B in the Luderitz space in offshore Namibia. We will operate this block with a 40% working interest. The area is prospective with high-impact oil prospects in multiple play types, and we have a 5,000 square kilometer 3D program already ongoing. In offshore EG, in Block W, we completed acquisition of a 3D seismic with our partnership group in the first quarter, and we are processing the data. On our MPN Block, offshore Cameroon, we expensed the Bamboo-1 well and plugged and abandoned it as a dry hole.

In Australia, we continue with our strategy to acquire acreage in under-explored 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. On our Ceduna basin acreage in Block EPP43, we hold a 50% working interest and operatorship. We're in the process of confirming our plan to acquire approximately 8,000 square kilometers of 3D 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 down 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 Siakap North–Petai on production. We progressed Dalmatian with first production on April 20. We added 44 wells in the Eagle Ford Shale. We ramped up the 4 new Sarawak oil fields. We tested the new 300 million cubic feet per day capacity for Sarawak Gas. In fact, we're 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 2 non-operated properties. While the startup of Kakap-Gumusut project is now estimated for third quarter, with further risks at start date, in Syncrude, we'll have a recently announced unplanned maintenance downtime event. This revised guidance represents an increase of approximately 11% over 2013 production levels.

We've gotten a great deal of balance and predictability to our global portfolio with a focus on North America onshore. We have divided our production per well metric by 4 since 2010. However, we're 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 1 production with 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.

We have 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 in international exploration with seismic execution, Namibia entry and a well spud in Vietnam. A refocus on the Gulf of Mexico continues with the spud of Titan, high bid in the recent lease sale and new entries at Urca 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.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question will come from Paul Sankey with Wolfe Research.

Paul I. Sankey - Wolfe Research, LLC

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

Roger W. Jenkins

Well, the business, Paul, as you know, if we want to not be in that business anymore, there are 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, discontinued work and meetings, and that would end on May 22. That would 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 -- in my mind, it's a point in time we're no longer approaching crude there, and people that are interested in buying the refinery know that. And it's part of the -- you've got to stop somewhere and get ready to move forward, and that's what we're doing.

Paul I. Sankey - Wolfe Research, LLC

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

Roger W. Jenkins

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

Paul I. Sankey - Wolfe Research, LLC

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

Roger W. Jenkins

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

Paul I. Sankey - Wolfe Research, LLC

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

Roger W. Jenkins

Well, we're guiding the exploration expenses, are we not, Barry?

Barry F.R. Jeffery

Yes, yes. Everything is part of our plan, Paul.

Paul I. Sankey - Wolfe Research, LLC

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

Roger W. Jenkins

Not really. We had, in our budget, in our CapEx, to enter into the lease sale in Central Gulf. We participated in the sale probably slightly lower than we had in the budget. We had all these seismic areas in our budget, absolutely. And then we disclose every quarter how much is going to be spent that quarter and the last quarter and how much we're prognosing for the next, and it's all in our plan, all in our exploration spend. Our exploration spend and our CapEx has not been increased.

Operator

Your next question comes from Ed Westlake with Crédit Suisse.

Edward Westlake - Crédit Suisse AG, Research Division

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 the stake?

Roger W. Jenkins

No. 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're taking a closer look at our portfolio. We have a very nice business development team we formed in Houston with experienced staff. We're looking at both our portfolio and external to our portfolio. And I think, in those type of processes, just like an example here in the U.K., we got out ahead of that a long time ago and said we were going to sell that. And it's become when now, I don't know, I guess, 12 quarters in a row or more. So not really going to comment on timing and plans on that type of an event. When you hear about it, you'll read about in the paper.

Edward Westlake - Crédit Suisse AG, Research Division

Okay. And then just operationally, saw some decent wells in Catarina 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?

Roger W. Jenkins

We're really happy with the Eagle Ford out there. We're heading up into the 60s and marching away up to 70,000 barrel equivalent net. We are an oil player in the Eagle Ford, not a gas player. Briggs has been a place that some of our lower -- we have 3 different distinct plays over a very vast, wide acreage position. 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 Catarina area is quite one big block, if you will, and we have some very, very nice wells there. And if you looked at our Howard Weil deck from a month or so ago, you would find some information about that. So we have 130 locations of 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 over-capitalize Eagle Ford. We're doing a lot of reservoir analysis around what is the proper downspacing. You just not jump in and go to 40s across the play. We see this to be about a 72-acre downspace is 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, then it could be quite a prolific play for us. These are not the headline-making wells. These are 200-barrel-a-day wells, but they make 200 for a long time with real low cost and pretty shallow depth. So a lot of running room left there. But we're 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 balanced effect to the other things that we're trying to do. And we probably aren't interested in changing CapEx or changing the strategy in the Eagle Ford, even though we have some success in the Catarina area right now, Ed.

Edward Westlake - Crédit Suisse AG, Research Division

Great. One little small question. Gulf of Mexico seems to be growing quite substantial. I know you've got some projects you're bringing on, but I'm just trying to get some color as to why the Gulf goes sort of 15-ish up to 30, just reading off the slide.

Roger W. Jenkins

Well, we have -- we're bringing in Dalmatian. Dalmation is a BOE machine. We made 52 million a day on that well today, and we have another oil well to go at a very, very nice pace. And the well is already completed. So rate -- Gulf's known for high rate. Rates -- Gulf's 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 companies, just about, in our industry are there. And I want to be there, and we're playing it heavy there.

Edward Westlake - Crédit Suisse AG, Research Division

So mainly Dalmatian and that small acquisition you made?

Roger W. Jenkins

Yes. There's -- Medusa has been one that -- Medusa is one of the highest, the most profitable margin business in Murphy history. And it's produced so long in the original completions that we have to do some subsea work there out in times. So we have 2 wells and Dalmatian coming on. We have a Medusa subsea development that's in our plan. We have a third well to add in Dalmatian next year. And then we're participating in this entry 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.

Operator

Our next question comes from Guy Baber with Simmons and Company.

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

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

Roger W. Jenkins

Yes. 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 235,000 to 240,000. The reason that was lowered is we had a shut-in of Kikeh that was moved into this year, which is just pure shut-in of the field. That was 1,650 barrels for the year. We had a fire on our rig there that's attached to the spar. We had to move the barge to Singapore and repair it. That's 3,350 barrels a day. That adds up to 5,000 barrels a day. So that's why our guidance was at 237,500. It would be the midpoint of the 235,000 to 240,000 range. So we're sitting here with a big field every month. The Kakap is late, just 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 from March to July, that's 3,000 barrels a day. The Syncrude choker repairs are absolutely 1,000 barrels a day. So those items are real, lowering that 237,000 down by 4,000 to 233,000. And then I said to myself, "I have a lot of risk going on in my business offshore. I have different things that could happen in execution." So I lowered it down 2,000, just 1%, for global risk business across our whole business. That gets my plan to around -- I got to have my folks focusing on 231,000 to 233,000 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 4,000 more. I moved Kakap out to November, the end of November. So I think it'll 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.

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

Okay, great. That's very helpful. 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 that 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.

Roger W. Jenkins

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

John W. Eckart

I'll let Barry...

Roger W. Jenkins

Barry?

John W. Eckart

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're rolling about maybe just in the $90 range for Q2. So we're not seeing it quite as strong looking forward.

Operator

We will proceed to Leo Mariani with RBC.

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

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 can 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.

Roger W. Jenkins

Well, I mean, this is something that we work with our partner, Petronas, who's the owner of the LNG business and has spot sales and 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 through the history of this project where I've always felt that if we had more ability, we could sell more gas. And what'll happen is there'll be month-to-month where 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 of -- that's not much. I mean, you take 8,000 Mcf gross there, that's for 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. And we -- when I say we delivered this capacity, it's a big deal because I lowered my -- all my section pressure, all my fields, and I was able do it from a reservoir perspective. All that behaved very well. This is a giant compression package. It's a 200 million, 300 million a day unit, 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. We're 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 in place with them today.

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

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?

Roger W. Jenkins

Well, as you know, we're in a PSC environment here. And we do -- these are our received revenue over cost of fields. They're by block, certain platforms in some blocks, certain 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. And 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'll be time now to recalibrate where we are as compared to JCC, which is very, very close to Brent pricing. You can take that factor and then start making a new date. Our supplemental payment in 309 was $1.10 an Mcf in the fourth quarter, and it went to $2.21 this year, so we've lost a little over $1 there, $1 per Mcf, because we produced a lot of Bcfs.

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

All right. I guess, maybe you guys could give us a little bit more color on Block H. I know you said that 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 could see first gas over there?

Roger W. Jenkins

Well, it's sanctioned to be second quarter of 2018. Leo, I don't know if you know this, people 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 to 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 process because their gas part of their business owns the ship. We have the upstream. They have signed the contract and are starting the construction. This would be their second vessel. So I'm feeling pretty good about all of all that, but it is leading new technology, and they're the leader in it. We're 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 high downtime for some of this new technology in our forecast that was out late recently. We only had guided through '19. So this thing really flows most of its life past that. It'll be a 10-year deal at 250 million a day type number.

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

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, an oil well coming on later, I guess, this quarter. Just wanted to get a better sense of what the production split is there. I guess the gas wells, is there 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.

Roger W. Jenkins

Yes, the well's about -- we're an oil company, in that -- Kevin and I were talking before the call, we don't do Mcfe. But this is a 50 -- today, it made 52 million of Mcfe, I suppose. About 1,200 barrels of that equivalent would be NGL. So that would be whatever 1,200 times 6 is, and the rest would be the gas. That's 42 million plus NGL kind of a number. So that well's a -- just a pure, straightforward deepwater Gulf of Mexico prolific gas pay zone that should produce fine, and the oil well, it's probably a 10,000 barrel a day type well. And we're spooling pipe offshore to hook it back in to the facility. The umbilical is laid and all the subsea equipment is laid. Subsea tree is on the well. The well's completed, and we hope to flow that well later this quarter.

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

All right. And I guess, just in terms of the Eagle Ford. You guys said -- I think you said you had 8 operated rigs. Can you give us the split by area between Tilden, Karnes and Catarina?

Roger W. Jenkins

We usually run 1 to 2 in Karnes, 4 in Tilden and 2 in Catarina, something like that.

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

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

Roger W. Jenkins

We just got -- we just getting seismic. So it'd be an event '16, '17 type thing. So we do not have a well commitment on the block, but we have to go shoot the 3D, and they already started doing that now. So it'd be 1 year or more before we'd be ready to spud there.

Operator

Our next question comes from Paul Cheng with Barclays

Paul Y. Cheng - Barclays Capital, Research Division

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

Roger W. Jenkins

Barry, do you have that number broken out? We have a slide that's got all our -- we have around 155,000 oil acres there, Paul.

Barry F.R. Jeffery

I'll look it up, Paul. But in Karnes, we're just a little less than 15,000 acres in Karnes 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.

Paul Y. Cheng - Barclays Capital, Research Division

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, closed down the refinery in U.K. and released the working capital and also that sale with the retail operation, then in the event that you also are going to sell down in Malaysia, so you receive the money, how are we going to look at the priority of that cash?

Roger W. Jenkins

Well, like I said, we formed a business development team and we looked at many opportunities, both in our portfolio and external. We have been in data rooms in Permian. As you noticed in my comments today, we did a very small ground floor purchase of a subsea tie-back in the 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 -- can 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. We're looking at North American, primarily. And that's part of our ongoing thing and look at many, many business development opportunities. But that's what we're focusing on today. Let me add one more thing to that, Paul. I forgot. It's a big thing I forgot here. Share repurchase is a big of part of where we're headed, and we're very happy about how that's going. Plus, you look to the F&D metric and you look at our cash flow multiple, how we trade, that would always be a part of any of those scenarios at some level.

Paul Y. Cheng - Barclays Capital, Research Division

Roger, do you have a -- an internal target -- do you have somewhat of the onetime excess cash -- how's the split between return of cash to shareholder and powering it back into the business development?

Roger W. Jenkins

No, I don't have any. We're going to look at opportunities to 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.

Paul Y. Cheng - Barclays Capital, Research Division

I see. And that -- you reiterate your 2014 CapEx, $3.8 billion. Any kind of early look for 2015, '16 in CapEx in terms of production as well?

Roger W. Jenkins

We are not making any changes today as to what we've guided onto production from our Howard Weil deck, which would be the most recent thing we put out. And these issues we're having today are delays and 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. There will be, in our portfolio, an occasional miss, but our portfolio is very, very, profitable. Our portfolio delivers EBITDAX and EBITDA per 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.

Paul Y. Cheng - Barclays Capital, Research Division

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

Roger W. Jenkins

We're looking at all alternatives to put that money here, Paul.

Paul Y. Cheng - Barclays Capital, Research Division

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

Roger W. Jenkins

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, did not go well for us, and we're not in that business today. That's taken care of financially and over with now.

Operator

We will proceed to Roger Read with Wells Fargo.

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

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?

Kevin G. Fitzgerald

Roger, this is Kevin. Those numbers bounce around as we run off the crude, turn it into product and distributing it out through the retail system. Still, the best way to look at that, the number we've been using of cash that we would bring back to the U.S. would be in the neighborhood of $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 in -- it's possible it could come back in pieces rather than all at one time, depending on how the transaction progresses.

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

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.

Roger W. Jenkins

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

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

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

Roger W. Jenkins

Yes. It was in my comments. It's 130 million barrels. It's very near our Thunder Hawk area, near Big Bend discovery by other operator in a very near Blind Faith, very, very good zip code area.

Operator

Our next question will come from Peter Kissel with Howard Weil.

Peter Kissel - Howard Weil Incorporated, Research Division

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?

Roger W. Jenkins

Well, I think, overall, it's not going to go down much more. I think if you looked 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'll be comparable -- what was our budget number we have, excluding Syncrude, John? It's $11?

John W. Eckart

We're still saying around $11.

Roger W. Jenkins

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

Peter Kissel - Howard Weil Incorporated, Research Division

Got you. I hear you, Roger. 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 Catarina 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.

Roger W. Jenkins

I think that we call it Lower and Upper. We're 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're very careful with the reservoir modeling around what will be the optimum thing. So we have a couple of rigs in there. We can't get to far -- I also think it's very difficult to drill the 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 that we're putting to 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 Catarina area. But right now, our focus would be this Upper Eagle Ford where we've had the better well results, which is shown our Slide 9 today in our deck. And in that particular area, it would probably be some of our better Eagle -- 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 downspaced to true 40, with the Lower being -- when I say 72, we're doing in around 80. It depends on the shape of the lease and lateral length, et cetera. But that's the plan for now, Pete.

Operator

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

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

Can I 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.

Roger W. Jenkins

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

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

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

Roger W. Jenkins

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

Operator

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.

Roger W. Jenkins

That's all we have today. We appreciate everyone that followed 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. Thank you.

Operator

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

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