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.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division Guy A. Baber - Simmons & Company International, Research Division Roger D. Read - Wells Fargo Securities, LLC, Research Division Paul Y. Cheng - Barclays Capital, Research Division Ryan Todd - Deutsche Bank AG, Research Division Paul I.

Sankey - Wolfe Research, LLC Edward Westlake - Crédit Suisse AG, Research Division Pavel Molchanov - Raymond James & Associates, Inc., Research Division John P. Herrlin - Societe Generale Cross Asset Research.

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation Third Quarter 2014 Earnings Call. 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..

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

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

Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained.

A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see both Murphy's 2013 Annual Report on Form 10-K and Form 10-Q for the quarterly period ended June 30, 2014, both on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements.

I'll now turn the call over to Kevin..

Thanks, Barry. Net income for the third quarter of 2014 was $245.7 million or $1.37 per diluted share compared to net income in the third quarter of last year of $284.8 million or $1.51 per diluted share.

For the 9 months of 2014, we had net income of $530.4 million or $2.94 per diluted share compared to net income for first the 9 months of 2013 of $1.05 billion or $5.51 per diluted share.

This year's third quarter included a loss of discontinuing operations of $25.3 million or $0.14 per diluted share compared to net income of $19.8 million or $0.10 per diluted share for the same period last year.

For the 9-month period, 2014 included a loss from discontinued operations of $52.6 million, $0.29 per diluted share, compared to income of $340.4 million, $1.79 per diluted share in 2013.

From continuing operations, we had income in the third quarter of 2014 of $271 million or $1.51 per diluted share compared to income and continuing operation in the third quarter of last year of $265 million, $1.41 per diluted share.

For the continuing operations for the 9 months of 2014, we had net income of $583 million or $3.23 per diluted share compared to income from continuing ops for the 9 months of 2013 $707.6 million, $3.72 per diluted share. Looking at income by segments.

The E&P segment for the third quarter of 2014 had income of $311.4 million compared to the income for the third quarter of 2013 of $264.2 million. Higher E&P earnings for the 2014 quarter were mostly attributable to higher oil and gas sales volumes, lower cost for exploration activities and U.S.

tax benefits on foreign exploration activities partially offset by significantly lower oil sales prices at higher extraction cost. Crude oil and gas liquids production for the current quarter was approximately 155,900 barrels per day compared to approximately 138,100 barrels per day in the corresponding 2013 quarter.

This increase was attributable to higher production at the Eagle Ford Shale, the Gulf of Mexico and shallow water Malaysia, partially offset by lower volumes from Block K in Malaysia.

Natural gas sales volumes averaged 443 million cubic feet per day in the third quarter of 2014 compared to 415 million cubic feet per day in the third quarter of last year. This increase was attributable to higher volumes from the Eagle Ford Shale and the Gulf of Mexico, partially offset by lower volumes at Tupper area in British Columbia.

In the corporate segment, we had a net charge in the third quarter of '14 of $40.4 million compared to a net gain in the third quarter of '13 of $800,000. This unfavorable variance is primarily related to lower asset tax gains from foreign currency transactions and higher net interest expense.

As of September 30, 2014, Murphy's long-term debt amounted to just under $4 billion, approximately 32.2% of total capital employed. This long-term debt figure includes approximately $341 million associated with the capital lease of production equipment for the Kakap field in offshore Malaysia.

Excluding this lease, long term debt to capital employed at September 30 will be approximately 30.3%. Now with that, I'll turn it over to Roger..

Thanks, Kevin. Highlights for us this month. Looking at the highlights in the third quarter, we announced the signing of the sale and purchase agreement for 30% of Murphy's Malaysia business for $2 billion. We closed on the sale of the U.K. retail gasoline business on September 30 with the sale of the Milford Haven refinery scheduled for tomorrow.

We approved a $500 million share repurchase program and increased our dividend by 12% to $1.40 per share at our August 6, 2014 board meeting. We achieved a record production level of 229,759 barrel equivalent per day. We produced an Eagle Ford Shale quarterly record of just over 60,500 BOE per day, up 15% from the second quarter of this year.

In recent years, Murphy has been known as a company with leading production growth, reserve replacement and cash flow for BOE metrics, along with a consistent dividend policy. Since 2012, Murphy has returned significant value back to our shareholders totaling near $4 billion through the spinoff of Murphy U.S.A.

valued at $1.75 billion in September of 2013, share repurchases of $1.125 billion, which retired approximately 18 million shares or 9.3% of outstanding shares to date, and as just mentioned $500 million authorization by our board in August of this year. We paid a special dividend of $2.50 per share totaling $486 million.

And during this time, from 2012 to '14, we paid regular cash dividends of $700 million. Looking at the prices in the third quarter. Realized oil prices in Block K and our 2 blocks in Sarawak averaged $89 and $80, respectively.

We forecast Block K and Sarawak realize oil prices in the fourth quarter to be near $77 and $75, respectively, primarily related to the recent drop in benchmark prices. Our index -- our oil index SK gas averaged close to $5.10 per MCF for the quarter, and we anticipate realized prices in the fourth quarter to be near $5.70.

Moving to the United States. In Eagle Ford Shale, oil prices are just over $93 for the quarter, including impact of our WTI hedging program. We have 22,000 barrels oil per day hedged, at WTI and our Eagle Ford business for the fourth quarter at an average price of just over $93.

Our realized oil price in the Gulf of Mexico averaged near $97, keeping pace with the movement in LLS. Syncrude was closed to $93 per barrel. And Seal, including the hedge, was a little under $58 per barrel. Both were lower in the third quarter with drops in WTI. Our oil-weighted portfolio continues to deliver solid cash flow metrics.

In the third quarter, we saw the growth for the second quarter in both EBITDA and EBITDAX per BOE. We do see a reduction in cash metrics to a year ago when major price indexes were some $9 to $12 above levels in the third quarter of this year. We have for this quarter just under $44 per BOE of EBITDA and near $49 per BOE of EBITDAX.

We continue to demonstrate strong results compared to our operational peer group in this metric. Our solid cash flows derive from strong supply cost position in our key oil and gas fields. Our supply costs will continue to prove advantageous to us as we weather the storm of recent price pullbacks.

In our key oilfields, we tend to be in the low-40 range in total supply, which includes OpEx and DD&A, and averaged near $14 per BOE from a total operating expense perspective. These metrics are further supported by our historic East Coast Canada production.

On the gas side, supply costs are in the $20 per BOE range, or just below $3 per MCF, which generates income in SK Gas and keeps us in positive earnings territory in the Montney. Both major gas areas generate strong cash flow, where operating expenses at SK and Montney are near $1.20 and $0.80 per MCF, respectively.

On our global lease operating expense, or LOE, our quarter 3 2014, excluding Syncrude, is near $10.50 per BOE, showing an improvement of $1.40 per barrel over the second quarter of this year led by reduced unit cost in the Gulf of Mexico on higher volumes.

Overall operating cost continue to trend significantly lower than the 2013 annual average of $14.61 per BOE as we continue to emphasize cost reductions. Third quarter production averaged 229,759 barrel oil equivalent per day, exceeding our quarter 3 guidance by 225,000 barrels equivalent per day.

This was primarily attributed to higher production from the Gulf and shallow water offshore Sarawak in Malaysia, offset by lower volumes from Syncrude and Sabah Gas. Looking ahead, we're guiding to the fourth quarter production level of 250,000 barrel oil equivalent per day. Hitting this target will provide 9% production growth for the year over 2013.

2014 has been a year with major subsea execution projects, including Siakap North-Petai, Dalmatian, and first oil from the non-operated floating production system on Kakap-Gumusut. We have the execution phase of these projects behind us now, which should derisk production guidance. In the fourth quarter, the Eagle Ford Shale will add 40 new wells.

We'll also add new wells in the Montney, and Syncrude has returned to full production following unplanned maintenance in the third quarter. In exploration and our global offshore exploration program. We released information stating the Titan Well in the Gulf of Mexico was dry in our August 6 press release.

Further, in the Gulf of Mexico, the rig is on location at our Urca prospect in Mississippi Canyon Block 697. We currently hold a 50% working interest as operator. We're in final negotiations to reduce our equity interest to 35%. The Lower Miocene sub-salt structure has predrilled gross mean resource size of 130 million barrels.

We plan to start an 8,000 square kilometer 3D seismic program across Block EPP43 and the Ceduna Basin offshore Australia in November, where we operate at 50%.

We're currently reviewing our budget and exploration program for next year, but at this time, in the first half of 2015, I see us participating in 2 wells in the Gulf of Mexico and 3 wells in the Perth Basin offshore Australia. Looking at global offshore operations.

In Malaysia, we recently announced the signing of a sale and purchase agreement to sell down 30% of our oil and gas assets for $2 billion, subject to customary closing costs and adjustments. The effective date of this transaction is January 1, 2014, with closing expected to take place in 2 phases.

The first phase comprising 2/3 of the transaction is expected to close late this year and the second phase is expected to close in the first quarter of 2015. Production offshore at Sabah was just over 20 -- just over 35,000 barrels of oil equivalent per day for the third quarter with 94% liquids.

At Kikeh, we continue with planned fuel development work. At Siakap North-Petai, we're currently drilling additional producer for the field. The Kakap-Gumusut main project declared first oil on October 8, 2014. The project's expected to ramp up in stages over the fourth quarter and into early next year.

The Floating LNG project for Block H continues to progress on schedule, where we are working on bid documents for subsea, hardware and pipelines. The Floating LNG vessel keel-laying is scheduled for late this year.

In shallow water offshore Sarawak, gas production for the third quarter was 175 million cubic feet per day, with the quarter having strong nominations into the Petronas LNG facility. SK liquids production was near 22,650 barrel oil per day for the quarter. The new field developments continue to perform above plan.

Drilling continues at South Acis field, where we delivered 4 wells during the third quarter, and expect to complete an additional 4 in the fourth quarter. In the Gulf of Mexico, the Dalmatian wells, where we hold a 70% working interest, continue to exceed expectations.

Production for the quarter was just over 10,000 barrel equivalents per day, with 53% liquids. The production levels are above original plans, but we're limited by maintenance work at the non-operated Petronius host platform.

In Medusa Mississippi Canyon, where we operate with 6% working interest, we started drilling the first of 2 subsea expansion wells, and anticipate first production from the new wells in the middle of 2015.

Work at the non-operated Kodiak development, where we hold a 29% working interest, continues to plan with first oil expected in the first-half 2016. Looking at North American onshore in Canada, in the Montney and the Tupper area in Western Canada, third quarter production was 146 million cubic feet per day.

We currently have 3 rigs drilling and one completion spread in operation to deliver 19 wells this year. We're continuing to see positive results using our new completion and choke management strategies, with production rates trending near the higher end of the range compared to offset.

But more importantly, blowing pressure is holding up very strong, which supports the expectation for higher EURs. We have 110 million scuffs per day of gas hedged at near CAD 4 AECO for the remainder of '14 and 65 million scuffs per day of gas hedged at near CAD 4.10 AECO for 2015.

Now looking at Eagle Ford Shale, third quarter, which comprised 90% liquids, averaged just over 60,500 barrel equivalents per day, up from near 52,800 barrel of oil equivalents per day in the prior quarter, as we brought on 64 new wells online.

We reduced the 7 drilling rigs and 3 completion spreads across the play and expect to bring on close to 40 new wells in the fourth quarter for a total of just over 200 wells this year, both operated and non-operated. We continue to see a tremendous running room of 10 years of inventory looking forward in Eagle Ford Shale.

We continue to see positive results with downspacing development and piloting to test staggered spacing with upper Eagle Ford Shale and Lower. We have over 2 years of history in reducing the Upper Eagle Ford Shale zone, and we're seeing these wells perform in line with an offsetting Lower Eagle Ford Shale well.

We are now testing staggered spacing with the Upper and Lower Eagle Ford Shale, which is effectively testing a 20-acre spacing. It is still early, but initial production days shows these wells tracking typical lower Eagle Ford Shale wells. While we do not see this potential across all of our acreage, there's upside for some 600 locations.

At the end of 2013, we had just over 200 million barrels equivalent of proved reserves in the Eagle Ford. We see tremendous resource potential with 2P in the range of 500 million barrel oil equivalent. And our focus is to continue to migrate 2P resources into the proven reserve category here.

We're currently adding to our acreage position Eagle Ford Shale the bolt-on acquisition of approximately 5,800 net acres, adjacent to our current North Tilden operations in Atascosa County. This new acreage provides close to 35 well locations at a conservative 160-acre spacing, with upside potential associated with downspacing.

I'm pleased with our execution in the Eagle Ford. We have built a strong team and execution of building the onshore business. We continue to ramp up production, lower drilling and completion cost and focus on lease operating expenses and improve margin and returns. Looking at the fourth quarter.

Production is forecast to be $250,000 barrel equivalents per day, and our annual production guidance remains in the range of 220,000 to 225,000 barrel oil equivalent per day. We remain on track to achieve record production this year, up 9% over 2013, with continued ramp-up at Eagle Ford Shale and growth support of our new offshore fields.

Our major subsea development work is behind us, which derisked production going forward. We're currently in the middle of our 2015 budget process. We're looking hard at the recent price pullback and potential impact on cash flow and capital spending in the budget.

In addition, we will factor in the 30% sale-down in Malaysia and the timing to close that transaction as well as reviewing overall production levels and the appropriate risking for next year. We will approve our final budget in December and expect to roll it out by our fourth quarter call early in the new year. The takeaways today.

We're pleased with the progress of our portfolio work with the sales agreement signed for our Malaysia business, and continued progress on the full exit of the U.K. downstream. We'll continue to reward our shareholders with another approved share repurchase authorization and continued predictable dividend growth.

After a solid third quarter, production's on track to meet our prior released annual guidance. The Eagle Ford Shale continues to perform for us with predictable long-term growth achieved. In addition to Eagle Ford Shale, much of our production growth this year has come from new subsea developments, with the execution of these projects now behind us.

I'm hopeful that the current industry price indexes are near the low point in the latest cycle. I believe Murphy is well-positioned with our oil-weighted portfolio, our supply cost structure, our overall liquidity and especially our low net debt to EBITDA multiple. We will now open it up for your questions..

[Operator Instructions] And our first question comes from Leo Mariani with RBC..

I was hoping you can talk a little about potential for M&A out there. Obviously, you've got a couple nice checks coming over the next handful of months in Malaysia. I think you guys have been vocal in the past about looking for potential acquisitions.

Can you just maybe kind of talk to what would be sort of most appealing to you all just from a high level in terms of what you might look at?.

Well, first, we have to get this thing closed and get all these proceeds, Leo. That's the first step in the game. That's a little bit of way here. We're all progressing that and feel good about that progress, but yet to have those proceeds. We like -- there's been no secret and no big deal about the North American onshore does have promise.

I think there are other opportunities also in the Gulf of Mexico as well, but on such a 2-week downward slide of crude price, and really, when will that recalibration of the M&A market take place? We know of some deals that have pulled because of that.

And further to that, with the price pullback, what will happen to the cost structure of the onshore? And I think it's just time for a recalibration of that, and they are opportunities there.

And we're interested in reviewing them, but I think this recent pullback has to cause that to recalibrate, both on the expectation of the seller and the cost structure going forward as well..

All right. Can you talk a little bit more about the Eagle Ford in terms of your ability to pick up some acreage? You obviously -- it looks like you added 5,800 acres here.

Can you give us some more color around that? Was that just kind of grassroots leasing? Were there actually more of sort of a purchase involved there? And how much other acreage do you think is available around your existing positions?.

There's a lot -- we're reaching a cycle in the Eagle Ford where people are getting near some of these terms some 3 years ago. And now there's pullback in price that people focus in on certain areas and some people focus in on others who want to sell some of their acreage.

And if we can pick that acreage up and have enough time to execute on it during the primary term, we're interested in doing that. We're seeing some of that these days. Leo, we don’t put everything we do in one of these slides.

We have some information, certain parts of the Eagle Ford, where we may want to pick up some acreage and probably not too interested in sharing much of the color around that because we have a small focus area there that we're working on right now..

Okay, that's helpful. I guess, in terms of your Block K production, you had mentioned that it was a little bit weaker here in the third quarter.

I just want to see if there's any sort of rationale for that and maybe what the outlook is for Block K as we get into 4Q?.

Well, any type of reduction in guidance this year would be due to this continued delay of this Kakap. I mean, it came on October 8. It's probably posted to flow on September 15. And this thing we make about -- we produce for the group about 25,000 gross.

And this thing has the ability to make 60,000 on top of that, and you make that late a couple of weeks, it can impact production. I think our Kikeh production was as just what we thought. Our Siakap North-Petai production is as per we thought. And any type of miss there would be related to the delay at Kakap by Shell.

Now we did have some problems with our Kikeh gas, which is a BOE production machine for us on occasion, but occasionally breaks down on the other end, but it's not a big part of our net income cash flow, perspective, Leo. So I don't see anything major there in that miss..

Got you, okay. Obviously, you guys talked about finalizing the sale of the U.K. retail.

Can you guys give us what the rough proceeds were on that?.

No, we're trying not to split that up. Kevin, for a long time, has talked around the $500 million range of the total bring home of that business. And we'd prefer to leave it that way until we get the whole thing up, buttoned up, Leo, to be frank with you..

Our next question comes from Guy Baber with Simmons..

I wanted to discuss the exploration strategy a bit. But previously, you highlighted some potential new venture opportunities maybe over the back half of '14 and then into early '15. It appears that the new ventures piece is not in the 3Q slide deck.

So wondering if you could just address the geographic focus for high-impact exploration as we go through 2015, what you're thinking about new ventures? And does this signal perhaps a transition to a smaller, more focused exploration in 2015 or am I reading too much into that?.

No, we're looking in Malaysia, quite frankly, at a situation there, and we do not have it solidified today, and that's why I pulled it out. But we're progressing it. I'm pleased with the progress. I would say that any new venture activity will not be in an area that we have not been actively working of late.

And if it's out today, it's because it's in the real stage of getting done. So there's a lot of opportunity there, just like the prior call. We need that to recalibrate as well, what are rig rates doing, what type of deepwater rig is on there, what are those costs.

So no, I think in general, I want to see us continue to focus down more, and we have made significant progress in focusing down, and we're going to continue. But today, I wouldn't see any type of new venture activity outside of where we've announced working or anything of that nature.

I wouldn't read a whole lot to the absence of it today in the slide..

Okay. And then you mentioned taking a closer look at the budget in light of commodity price weakness.

Fully understanding that the budget isn't finalized yet and there's a lot of moving parts, can you just comment big picture on how you're thinking about 2015 spending levels and managing the business, and where do you see flexibility in your outlook, how important it is to balance cash flow and CapEx for you guys? And then relatedly, you've always said that the balance sheet is a priority, that your solid balance sheet as a priority.

Do you have targeted leverage ratios or maybe a maximum leverage ratio that you would be willing to go to relative to where you are? How do we think about that? Do we look at that on a debt-to-EBITDA basis? If you could just help us think about that, that will be great..

Well, that question is long like these political debate questions you hear on TV these days. Wow. First off, I mean, it is a significant pullback in price. I mean, we had a regional budget, $94, we met October 6. We lowered it to $88. We've just been meeting, lowering it to $82 and $87, Brent, something like that.

So it's very difficult to get a hold of your budget with prices like that because as you know, we have supplemental payments and issues to calculated, and PSCs and royalties, et cetera. I have to run through all that. In general, I'd like to be a cash flow, CapEx parity.

Who wouldn't? That is a, I would say, that's more of a prerogative for me than just incredible growth continuing on and on. We have around a 30% debt-to-cap today. And not counting our cash on a net debt business, I feel very comfortable at that level and want all I can do to maintain it or very near it. So that's how we're thinking about that.

It's just we're not going to get into budget today with the -- I believe and I hope, that it's settled in, in the low-80s, which will be very helpful at forming the budget, which is we're working on that today. But that's about all I can say about it, if that answers your question..

Our next question comes from Roger Read with Wells Fargo..

It was mentioned in this press release, and it's been an issue in some prior quarters, I'm sure will continue to going forward, the third-party pipelines, platforms and all that.

Can you help us understand, as you look not just at Q4, but also to think about '15, how you're kind of risking the production profile for those sort of items or is it just simply we'll have to pay attention to seasonal issues and watch those other operators?.

Well, we've said on prior calls some 8% kind of risking numbers, we think, in the offshore business gets their onshore businesses in pretty good shape. We're putting more long-term pipe on in Eagle Ford. And -- but Roger, we're a leader in cash flow per barrel, almost a $10 margin over average of a great set of peers. And you can't have everything.

So we're not a company with the most beautiful production every quarter. But in the big ticket items out there, we're flowing Petronius into Chevron -- we're flowing Dalmatian into Petronius operated by Chevron. They're the operator there. And that put some issue there occasionally. We got through that with outstanding well performance.

If you look at our big SK Gas machine, which is a very nice piece of business, we flow into one of the largest LNG facilities in the world. We've been making around $300 million gross there. We had probably one of our better quarters. And on occasion, they call on the red telephone and lower it to $240 million.

We have Kikeh gas, which flows into a methanol facility, which is not a big cash flow income per BOE provider for Murphy, but can lead to some production. There's a question on it earlier here today. That flows into a facility that we do not operate. So those are 3 of the bigger ones today that are out there.

You always have also Syncrude going into a very old and antiquated pipeline system, that on occasion, has curtailment because we haven't built XL pipeline and the like. So those are the things we have here in our business. But we have a diverse, primarily Brent-weighted portfolio, across a lot of places.

And we have a very high cash flow per barrel metric that I'm very proud of, quite frankly..

That kind of leads me into the next question.

If we are in a situation where 2015 CapEx has to come down versus '14 or versus prior expectations maybe is the way to think about it, what do you focus on? Is it returns? Is there a balanced program here, returns, cash flow, kind of NPV versus absolute returns? Can you help us understand maybe as you go through the process, what falls to the cutting room floor and what goes forward?.

Well, I've been through this many times in my career, '08 and '99, '87. You see these pullbacks. Usually at this time of the year, around budget time, it's difficult. We have a lot of irons in the fire there, Roger. I mean, we're a big explorer. Obviously, you can cut exploration.

You have to be careful with that due to the size and the commitments today lead to wells in the future. It is one of the things that you do go to pretty early. We are -- we do have an NPV rate of return for everything we do in our portfolio. Obviously, heavy oil would probably be on the lower end of that spectrum in Montney.

And then after that, with a very strong Gulf of Mexico production business, things like Medusa, you look at things like in Malaysia, it's under a cost recovery scheme. Those things worked very well and have high rates returns. So if you're a 70-something percent reserves and 70-something percent production player, everything's a pretty decent return.

So it gets tough. And so we look to bring exploration down some. And then we have to dance around with the U.S. cash position and cash abroad and repatriation. And working through all those issues, starting off trying to be cash flow CapEx parity in the upstream at a minimum is where we try to work right now, Roger. But it's a lot of moving parts there..

Okay. And just a sort of last question along those lines.

The Gulf of Mexico development projects that are out there, so Medusa and Kodiak, how would they fair -- I guess in a sense, Medusa's already pretty well already committed to, but how does Kodiak and Medusa fair in the current oil price environment?.

Very well, in the absolute worst, low-20% rate return situation..

Our next question comes from Paul Cheng with Barclays..

Several quick questions. Roger, if you're looking at Eagle Ford, after adjusting for the sales of Malaysia at 30% is now, let's say, more or less, say, 30% up in your portfolio production.

Is there, from a portfolio management standpoint, do you guys look from that standpoint, say, whether there's a percentage as a considered an optimum level you don't want to exceed in terms of the North American onshore shale oil or tight oil exposure?.

No, I mean, right now, we're balanced at near 50%. And I like where that is. And when we have exploration success, we'll probably get it a little below 50%. And I'm probably -- I don't have a number in my mind with that, Paul, but balanced at near 50s, where I'd like to be if I can, I think that's a good situation..

When you say 50%, you're just talking about U.S., not talking about the overall company?.

No, 50% of our total production..

50% of your total production? Right now, you're only about....

North America, Paul..

Oh, North America? Okay..

Yes, we have Canada, too, in there, Paul. When I say onshore, I think in North America, not just U.S..

Okay, so North America, 50% is a comfortable level for you?.

Yes, sir..

Okay.

And in terms of the Malaysia, the oil price guidance that you gave me in the fourth quarter, is that based on the $80 -- $85 Brent based on today's Brent price?.

Barry, could you tell him exactly what is the base now?.

Yes, fourth quarter estimates, Brent is a little under $86, in the high 85s, Paul..

It will still go up from that, right? Does that count that lift, Barry?.

No, that's just Brent as a benchmark at the time of estimate..

Okay, that's fine. So that means we're using a different price in our model. We should just adjust it accordingly..

Yes, that's what we're trying to guide to, yes, Paul..

Right, that's perfect. And I know that you guys are just looking at it.

Any rough wings you can provide? What is 2015, 2016 production? Is that your best guess at this point or what are you meaning to do?.

No, I just -- we're just not going to get into that today, Paul. It's just too drastic of a drop, and I have all these things I've been rattling off here this morning, I need to discuss and price and cost and just not doing that today.

Well, I'll say this, Paul, production will be higher, okay? Production will be higher than adjusted for the Malaysia sale of this year..

And that on the downspacing kind of project for the Eagle Ford looks like a great success.

From that standpoint, should we assume that this is an extension of your petrol rate or your petrol rate is going to be adjust upward?.

We -- that, again, is a budget matter and a U.S. cash situation matter and free cash flow in the Eagle Ford and net back in Eagle Ford. We, for the last year or so, have had Eagle Ford at a consistent rig count and spend and flat for a long period of time. We may reevaluate that now and are kind of in the middle of our long-range plan.

And you've got to keep in mind, we have got to get this Malaysia sale closed and into our plans. And what we might want to do with production in our -- we have a lot of leverage to pull there. And really, it will be probably a longer plateau, Paul, but we have the ability to increase it pretty easily.

And if we were to get a cost structure improvement here, that would be a place to put capital because we're at a very high crude quality, high realized price environment in our liquids NGL gas breakout in Eagle Ford Shale..

But why now for the first preliminary look that you expect you'll just keep the petrol there for a longer time?.

No, we're going to grow into '16, for sure. And it was originally planned to go into '17 and be flat to years after. So we're just looking at a 2-year budget cycle now. So definitely, will increase next year..

Right. I think previously, you were looking at the petrol rate at 70,000 barrel per day.

I guess, my question to that, is that still a good number or should we assume higher?.

No, at this time, you should assume that, Paul..

Okay. A final one on Dalmatian.

How long that it can keep at the peak production before that we start seeing that to decline?.

Oh, it will be another 1.5 years or so, Paul, there..

Our next question comes from Ryan Todd with Deutsche Bank..

Great. A couple -- I guess, one follow-up on the previous one.

Is the -- and I know we've talked about this quite a bit in the past, but the plateau rate -- the balance between plateau and growth in the Eagle Ford, is that contingent at all on oil price right now and the pullback that we've seen? Or is it just still the general philosophy, you prefer plateau over growth?.

I, in the past, have preferred plateau over growth. But what we do every year is redo our budget and we redo our long-range plan, and we have to look at what we've done with this sale down in Malaysia. And I'm not saying I'm not going to revisit it, I'm just waiting for the outcome of all that work.

And it's being worked in both methodologies at this time, Ryan..

Okay. And the fourth quarter completions in the Eagle Ford's is at 40 versus -- and I know 3Q was generally higher than the run rate is.

Is the right rate going forward of the 7-rig program still kind of around 50 completions a quarter?.

Yes, that would be, but these things aren't -- we're now in these big blitz campaigns, where we do uppers and lowers together, downspace together, and it can still get out of kilter there a little bit. In general, yes, but I can't always guarantee. We'll still have the 60 and the 40 in that way, occasionally, Ryan, to be honest with you..

Okay. And then maybe one follow-up on kind of use of cash and priorities. There was -- I think you didn't do any buyback in the quarter. Was that more a reflection of waiting for the proceeds of U.K.

and Malaysia to come in? Or I guess, when you look forward at the balance between buyback, capital spending, potential acquisitions, how does -- where does buyback fall in a priority there?.

Well, when we set up buybacks, we feel we can afford it or we wouldn't want to do them when we've had a consistent program by quarter in the past, and we will react that same way going forward. And we weren't in an open period, and now that we released our earnings and can open up with the soak of these earnings, things can change here, Ryan.

But it will be at some consistent going forward way. And it's our view at Murphy that when we make authorizations, we feel we can forward it and go from there..

We move next to Paul Sankey with Wolfe Research..

It's good to see you beating guidance there.

So the question for me now, Roger, is obviously you've got a kind of luxurious problem here, and I know you've been answering questions all call around this subject, but can you just go back over again now the relative attractiveness to your, first of all, of international deepwater exploration? And I guess, in that, I'd be wondering about rig rates and if that makes any difference to how you look at that opportunity set.

And then I was really wondering if this oil price environment makes you more attracted towards making an acquisition or less, simple as that.

Is it likely that you want to be -- going to be -- want to be more conservative with the balance sheet and sort of protect your organic spending or do you see it as an opportunity?.

International exploration has been a big part of our business. It's no secret, I'm a favorite of the Gulf of Mexico. And if you look at next year, we're not through with our budget, it's going to be heavily weighted toward the Gulf.

One thing about international exploration, it is cheaper where the rig rate probably isn't as big a deal because the Malaysia deepwater exploration or Australia or a different place is usually much easier to drill much shallower wells. So you do have cheaper wells abroad, typically, compared to the bigger wells in the Gulf.

Continuing to try to focus down into less areas there, continuing to want to be in the 30% range of wells that are approaching 100 million or more, we saw that in the comments today.

But back to the Gulf, less international at this stage, more focused into international being larger opportunities with the right kind of working interest is how I'm thinking about that. As per the money, I mean, we don't have the money yet. We need to get the money in.

It's -- get that done in our release, I mean, the uses of proceeds or share buyback. You can increase rigs in Eagle Ford. You can do M&A or debt. All of those things have advantages at different times. I will say that I still view it as an opportunity. I believe that our balance sheet is okay. Our balance sheet is set up to weather this.

And I went over some of my comments of that earlier today. I think I believe in trying to show these proceeds as they are and not use them to fund what we have. I think it's important to make the right calls there among those 4 things that I mentioned.

Our shares are very cheap today, of course, and then there's M&A activity that needs to calibrate to lower price and possibly some cost help there, maybe onshore North America, if that comes.

And setting there and waiting to react to that is a decent position, and it is an opportunity, and I would prefer at this time -- of course, you never know what will happen. But I prefer not to use it for proceeds in the business at this time, Paul..

Yes. I mean, you've had a history, obviously, of a higher risk, higher growth-type approach.

Does that -- wouldn't that make you more oriented towards using the capital to expand the business? Or is it going to be the fact that your stock as you've highlighted to me many times is so cheap that it's very hard to find anything to buy, I guess, without being dilutive, right, other than the fact you're using cash, obviously..

Well, let me answer this in another way. Stock is very cheap, which makes repurchase there. Putting rigs in Eagle Ford Shale, people asked that in a different way earlier, that's good.

You can't always pay down debt and be more conservative, but I'm not interested in exploring with the money and trying to be able to explain where those proceeds go, and I'm not interested in funding international exploration or Gulf..

[Operator Instructions] We move next to Edward Westlake with Crédit Suisse..

A lot of questions have been asked, but I just wanted to get an update in Australia. I mean, obviously, the Perth Basin, I think, a little bit shallower.

What type of, sort of, I guess, hydrocarbon indications have you got in that basin and sort of target size just as we think about you testing that? And then the other question would be whether you had any early seismic indications on the Ceduna Basin?.

First, in Perth, that's a very nice opportunity. These are -- we get to participate with our partners and drill 3 wells there. They're not large, incredible opportunities. The are 50 -- one well's around a 50 million-barrel mean, the other 2 are near 100 million. They are in only 60 meters of water.

We'll get a kick at this can at 3 wells for around $25 million, our share. It's on the Turtle Dove Ridge basin, which is Triassic age. There's 3 different types of faulting features there. The one negative about the seismic, didn't derisk it as much as we'd like. We took 3D seismic there, but the main structures are there.

There's nearby wells with great sand quality. There was recent an onshore well there that gave some promise to that area. So I'm excited about the kick at the can and the size of it without incredible nontax expense for us. Ceduna Basin, of course, is a big hunk of acreage there.

We have the luxury of being able to watch people drill around us mainly, the Chevron blocks and now the Statoil BP blocks. We are just taking the first shot, maybe not even taking it now. So I won't have a look at that at this time, but we still like that as a megatrend for us.

Murphy always was in the game with some dabbling and some really big company making wells, and that this will be some of those. We do not have a well commitment there. And so wells will be on kind of a deeper, lower tertiary Gulf of Mexico type cost or more. So I'm glad about that. So I get to watch other people drill, look at the seismic and decide.

And I think that's a good position, buttoned up against these cheaper, nice, very economic opportunities we have in Perth Basin..

And then in the Gulf of Mexico, just the wells that you're planning for '15, are they up in the Norphlet? Or what sort of -- what are they targeting?.

As it stands today, we have a very, very nice program, if we can continue with the prices we have and pay for this program, which I believe we will. The Urca well is a 130 million barrel. It's more of a Miocene pinchout against salt play between Big Bend and Blind Faith, which are 2 prolific fields in the Gulf.

We have a very nice well called Opal with our partner, Anadarko, to drill on the Cretaceous edge in the most eastern part of Gulf of Mexico, a very large target there, and a not very expensive well, meaning it's less than $100 million, which in the Gulf today is pretty good.

We have an amplitude Miocene play called Sea Eagle in the second quarter, very, very nice well, similar to a Dalmatian type of opportunity. And we have a very nice Norphlet opportunity toward the end of 2015 that would be an offset of the recently announced Shell Rydberg.

It's a very nice opportunity and it's a lot of data coming about where sand is and derisking of Norphlet. And we're very glad. So we have 4 nice wells not dependent on each other, almost 4 different types and very nice, very sizable, very economic, very accretive and helpful to the company, and a real nice program..

Can you just, I mean, run through the working interest of those 4 wells?.

The Urca well would hopefully improve certainly going to 35% or 50% on the Opal opportunity with Anadarko or 50% today at Sea Eagle and may go down to 35%. And we're currently 50% on the Desperado well in the Norphlet..

Our next question comes from Pavel Molchanov with Raymond James..

On the Malaysian monetization, can you just explain how taxes will work on this, particularly with the 2 closings in 2014 and 2015?.

I'll let Mr. Fitzgerald handle that for you..

Pavel, the only taxes related to the Malaysian sale will be when we repatriate the money. There's no taxes in Malaysia on the sale itself..

Okay, and understood.

So no accruals, anything like that?.

No. The only thing, and if we repatriate the funds back to the U.S., you'd have what we're estimating now and been telling people it's about a 8.5% leakage..

8.5%? Okay, that's helpful. And then for the Urca prospect, I'm not sure if you guys have given out the predrill estimate, but that'd be helpful..

130 million PME..

Okay.

And then for Whydah and Sea Eagle, is it too early to ask about that?.

Sea Eagle's around 110 million and Whydah is not on the schedule today..

We move next to Wayne Cooperman with Cobalt Capital. Hearing no response, we'll move to John Herrlin with Societe Generale..

Just a strategic question. You mentioned all the capital that you returned to shareholders and value you've created like spinning off the refinery or the marketing, et cetera. But if you look at your stock price, and whether you go to 2012, 2010, it's basically flat. You've mentioned, and I agree that your stock's undervalued.

Is it worthwhile to get more aggressive in fast cycle time projects, which the market seems to be rewarding, or be a whole lot more aggressive with the stock buyback?.

I missed your first part before the stock buyback. I didn't quite catch that.

Again, could you say that?.

What I said was you talked earlier about what's your return to shareholders since 2012..

Okay. I got that part.

What are the 2 alternatives you mentioned?.

One, getting more aggressive in fast cycle time activity, like really ramping up Eagle Ford or other type endeavors, or just making a big buyback and leveraging..

Well, I can assure you that we are modeling both of those incredibly closely. And in the middle of this oil price recap -- redrop here, just in the last couple of weeks, it's only flattened in the last few days, and we're greatly calculating those 2 events..

It appears there are no further questions. Mr. Roger Jenkins, at this time, I'll turn the conference back to you for any additional or closing remarks..

No further comments. I thank everyone for calling in, and we'll see you in January. I appreciate it..

This does conclude today's presentation. We thank you for your participation..