Murphy Oil Corp (MUR) 2014 Q3 法說會逐字稿

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 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. Our 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 nine months of 2014, we had net income of $530.4 million or $2.94 per diluted share compared to net income for the first nine months of 2013 of $1.05 billion or $5.51 per diluted share. This year's third quarter included a loss from discontinued 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 of last year. For the nine-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 from continuing operations third quarter of last year of $265 million, $1.41 per diluted share. From continuing operations for the nine months of 2014, we had net income of $583 million or $3.23 per diluted share compared to income from continuing ops for the nine months of 2013, $707.6 million, $3.72 per diluted share.

Looking at income by segment, the E&P segment for the third quarter of 2014 had income of $311.4 million compared to 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 US tax benefits on foreign exploration activities, partially offset by significantly lower oil sales prices at higher extraction costs.

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 is 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 the Tupper area in British Columbia.

In the corporate segment, we had a net charge in the third quarter of 2014 of $40.4 million compared to a net gain in the third quarter of 2013 of $800,000. This unfavorable variance primarily related to lower after-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 offshore Malaysia. Excluding this lease, long-term debt to capital employed at September 30 would be approximately 30.3%. 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 a sale and purchase agreement for 30% of Murphy's Malaysia business for $2 billion. We closed on the sale of the UK 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, 201 Board meeting. We achieved a record production level of 229,759 barrels 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 this year.

In recent years, Murphy has been known as a company with leading production growth, reserve replacement and cash flow per 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 spin-off of Murphy USA 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 the 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. During this time from 2012 to 2014, we paid regular cash dividends of $700 million.

Looking at the prices in the third quarter, realized oil prices in Block K and our two blocks in Sarawak averaged $89 and $80 respectively. We forecast Block K and Sarawak realized oil prices in the fourth quarter to be near $77 and $75 respectively, primarily related to the recent drop in benchmark prices. Our oil-indexed 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 and Eagle Ford shale, oil prices are just over $93 for the quarter, including the impact of our WTI hedging program. We have 22,000 barrels of oil per day hedged at WTI in our Eagle Ford business for the fourth quarter at an average price of just over $93. Our realized oil price from the Gulf of Mexico averaged near $97 keeping pace with the movement in LLS. Syncrude was close to $93 per barrel and (inaudible), 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 to 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 flow is derived from strong supply cost positions 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 oil fields, we tend to be in the low $40 range in total supply, which includes OpEx and DD&A and average 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 three 2014, excluding Syncrude, is near $10.50 per BOE showing an improvement of $1.40 per barrel over the second quarter this year led by reduced unit costs in the Gulf of Mexico on higher volumes. Overall operating costs 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 three guidance of 225,000 barrels equivalent per day. This is 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 equivalents 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 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, rigs on location at our Urca prospect in Mississippi Canyon, Block 697, we currently hold a 50% working interest as operator and we're in final negotiations to reduce our equity interest to 35%.

The Lower Miocene subsalt structure has a pre-drilled gross mean resource size of 130 million barrels. We plan to start an 8000 square kilometer 3D seismic program across Block EPP 43 in the Ceduna Basin offshore Australia in November where we operate at 50%. We are 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 two wells in the Gulf of Mexico and three 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 two phases. The first phase comprising two-thirds of the transaction is expected to close late this year; the second phase expected to close in the first quarter of 2015. Production offshore Sabah was just over 35,000 barrels of oil equivalent per day for the third quarter with 94% liquids.

At Kikeh, we continue with planned field development work. At Siakap North-Petai, we're currently drilling an additional producer for the field. The Kakap-Gumusut main project declared first oil on October 8, 2014. The project is 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. We are working on bid documents for subsea hardware and pipelines. The floating LNG vessel, [Kealane], 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 of oil per day for the quarter. The new field developments continue to perform above plan. Drilling continues at South Acis field where we delivered four wells during the third quarter and expect to complete additional four 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 were limited by maintenance work at the non-operated Petronius host platform.

At Medusa Mississippi Canyon where we operate the 6% working interest, we started drilling the first of two 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 of 2016.

Looking at North American onshore and Canada, in the Montney and the Tupper area in Western Canada, third-quarter production was 146 million cubic feet per day. We currently have three rigs drilling and one completion spread in operation to deliver 19 wells this year. We continue 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 offsets. But more importantly, [blowing] pressure is holding up very strong, which supports the expectation for higher EURs. We have 110 million [scfs] per day of gas hedged at near CAD4 [ACO] for the remainder of 2014 and 65 million scfs per day of gas hedged at near CAD4.10 ACO 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 oil equivalents per day in the prior quarter as we brought on 64 new wells online. We reduced to seven drilling rigs and three 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 with 10 years of inventory looking forward in the 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 two 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 data shows these wells tracking typical lower Eagle Ford shale wells. While we do not see this potential across all of our acreage, there is 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 are currently adding to our acreage position in the Eagle Ford shale with the bolt-on acquisition of approximately 5800 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 ability in our onshore business and continue to ramp up production, lower drilling and completion costs and focus on lease operating expenses to improve margin and returns.

Looking at the fourth quarter, production is forecasted 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 rampup at Eagle Ford shale and gross support from our new offshore fields. Our major subsea development work is behind us, which derisks 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 the overall production level 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 are pleased with the progress of our portfolio of work with the sales agreement signed for our Malaysia business and continued progress on the full exit of the UK downstream. We continue to reward our shareholders with another approved share repurchase authorization and continued predictable dividend growth. After a solid third quarter, production is 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 the 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). Leo Mariani, RBC.

Hey, guys. 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 talk to what would be sort of most appealing to you all, even if just from a high level in terms of what you might look at?

Well, first, we've got to get this thing closed and get all these proceeds, Leo; that's the first step in the game. That's a little bit away here. We are 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 North America onshore does have promise. I think there are other opportunities also in the Gulf of Mexico as well, but we're on such a two-week downward slide of crude price and really when will that recalibration in 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 there 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 of 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 5800 acres here. Can you give us some more color around that? Was that just kind of grassroots leasing? Was there actually more of a -- sort of a purchase involved there? And how much other acreage you think is available around your existing positions?

We're reaching a cycle in the Eagle Ford where people are getting near some of these terms from three years ago and now this pullback in price that people focus in on certain areas and some people focus in on others and 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 slots. We have some information in 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 guys mentioned that it was a little bit weaker here in the third quarter. 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 just continued delay of the Kakap. I mean it came on on October 8. It's probably post the flow on September 15. 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 is just what we thought. The Siakap North-Petai production is as per we thought. Any type of miss there would be related to the delay at the 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 UK 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 total -- total bring-home of that business and we'd prefer to leave it that way until we get the whole thing buttoned up, Leo, to be frank with you.

Okay. That's helpful. Thanks, guys.

Guy Baber, Simmons.

Thanks for taking my question. Congrats on a strong quarter. I wanted to discuss the exploration strategy a bit, but previously you had highlighted some potential new venture opportunities maybe over the back half of 2014 and then into early 2015. It appears that the new ventures piece is not in the 3Q slide deck. So I'm 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 are 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 and I'm pleased with the progress. I would say that any new venture activity would 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 our 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 continuing 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 slides.

Okay, thanks. 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 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 is 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 would be great.

Well, that question's long like these political debate questions you hear on TV these days. Wow. First off, I mean it is a significant pullback in price. We had an original 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 calculate [NPSEs] and royalties, etc. and we have to run through all that.

In general, I'd like to be at cash flow CapEx parity; who wouldn't? 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, not counting our cash on a net debt basis. 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. We're not going to get into budget today with you. I believe and I hope that it settled in in the low $80s, which would be very helpful at forming a budget, which we're working on that today. But that's about all I can say about it if that answers your question.

That's helpful. Thanks, Roger.

Roger Read, Wells Fargo.

I hope your phone hasn't been keeping you awake at night again.

No, it hasn't.

All right, good. It was mentioned in this press release and it's been an issue in some prior quarters and I'm sure will continue 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 2015 how you're 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 to get to their onshore business is in pretty good shape. We're putting more long-term pipe on in Eagle Ford, but 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. In the big-ticket items out there, we're flowing Petronius into Chevron. We're flowing Dalmatian into Petronius operated by Chevron. They are the operator there. That puts some issue there of occasion. 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 a 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 was a question on it earlier here today. That flows into a facility that we do not operate. So those are three of the bigger ones today that are out there. You always have also Syncrude going into a very old and antiquated pipeline system, which, on occasion, has curtailment because we haven't built the [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 2014 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 of 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, 2008, 1999, 1987, you see these pullbacks. Usually this time of year around budget time, it's difficult. We have a lot of irons in the fire there, Roger. We're a big explorer. Obviously can cut exploration. You have to be careful with that due to seismic commitments today lead to wells in the future. It is one of the things that you do -- do go to pretty early. We are a -- we do have an NPV rate of return per everything we do in our portfolio. Obviously, heavy oil would probably be on the lower end of that spectrum and Montney and then after that, with the 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 work very well and have high rates of return. So if you're 70% something reserves and 70% something production player, everything is a pretty decent return.

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

Okay. Just 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 is pretty well already committed to, but how does Kodiak and Medusa fair in the current oil price environment?

Very well and absolute worst, low 20% rate of return situation.

Okay, thank you.

Paul Cheng, Barclays.

Hi, guys. How are you doing? I just have a quick question. Roger, I mean if we're looking at Eagle Ford, after adjusting for the sales of Malaysia at 30%, it's now I would say more or less say 30% of your portfolio production. From a portfolio management standpoint, do you guys look from that standpoint and say whether there's a percentage as a consider an optimum level you don't want to exceed in terms of the North American onshore shale oil or tight oil exposure?

No, 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 50% is 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 US, not talking about the overall Company?

No, 50% of our total production.

50% of your total production right now (multiple speakers)

In North America, Paul.

Oh, North America, okay.

Yes, we have Canada too in there, Paul.

Okay, because I was --.

When I say onshore, I think of North America, not just US.

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

Yes, sir.

Okay. And in terms of the Malaysia, the (inaudible) guidance that you gave me in the fourth quarter, is that based on $85 Brent, based on today's Brent price? Eric, could you tell him exactly what it's based on?

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

Okay.

We get a little uplift 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 if we're using a different price in our model, we should just adjust it accordingly?

Correct. 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 (inaudible). Any rough range you can provide what is 2015/2016 production that's your best guess at this point or that you're leaning towards?

No, just, you know, 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 that I need to discuss and price and cost and just not doing that today.

Okay, that's fine.

I'll say this, Paul. Production will be higher. I can tell you production will be higher than adjusted for Malaysia sale of this year.

And on the downspacing pilot project for the Eagle Ford, it looked like it's a good success. From that standpoint, should we assume that this is an extension of your (inaudible) or your (inaudible) is going to be adjusted upward?

That, again, is a budget matter and a US cash situation matter and free cash flow in the Eagle Ford and netback in the Eagle Ford. We, for our 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. Keep in mind we've got to get this Malaysia sale closed and into our plans and what we might want to do with production and we have a lot of levers 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 the Eagle Ford shale.

But why now for the first preliminary look that you expect you just keep the (inaudible) for a longer time?

No, we're going to grow into 2016 for sure and it was originally planned to go into 2017 and be flat two years after. So we're just looking at a two-year budget cycle now. So definitely we'll increase next year.

Right. I think previously you were looking at the (inaudible) of 70,000 barrels a day. I guess my question (multiple speakers).

Yes, that should (multiple speakers).

Is that still a good number or should we assume higher?

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

Okay. A final one on Dalmatian. How long that you can keep at the peak production before that (inaudible) would start seeing natural decline?

Oh, it will be another year and a half or so, Paul, there.

Year and a half? Perfect. Thank you.

Ryan Todd, Deutsche Bank.

Great. Thanks, gentlemen. I guess one follow-up on the previous one. I know we've talked about this quite a bit in the past, but the plateau -- the balance between plateau and growth in the Eagle Ford, is that contingent at all on oil price right now on the pullback that we've seen or is it just still of 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 the 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 -- thanks. The fourth-quarter completion in the Eagle Ford is at 40 versus, and I know 3Q was generally higher than the run rate is, is the right rate going forward at a seven-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 use of cash and priorities. There was -- you didn't do any buyback in the quarter. Was that more a reflection of waiting for the proceeds of UK and Malaysia to come in or I guess when you look forward at the balance between buyback, capital spending, potential acquisitions, 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 and 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've released our earnings and can open up with the soak of these earnings, things can change, Ryan. But it will be (inaudible) going forward way and it's our view at Murphy that when we make authorizations, we feel we can afford it and go from there.

Okay. All right, thanks a lot. Great quarter, Roger.

Thank you. I appreciate it.

Paul Sankey, Wolfe Research.

We're obviously not going to accuse you of lowballing your guidance. Great to see you beating it.

I'm going to confuse you by not responding to that.

In all seriousness, it's good to see you beating guidance there.

Thank you.

The question for me now, Roger, is, obviously, you've got a 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 you, 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, as simple as that? Is it likely that you are going to want to be more conservative with the balance sheet and sort of protect your organic spending or do you see it as an opportunity? Thanks.

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 a Gulf. One thing about international exploration, it is cheaper where the rig rate probably isn't as big a deal because, in Malaysia, deepwater exploration, or Australia or different places, usually much easier to drill much shallower wells. So you do have cheaper wells abroad typically compared to the bigger wells in the Gulf. I am continuing to try to focus down into less areas there and 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 for the money, we don't have the money yet. We need to get the money in, get that done and in our release, the uses of proceeds, or share buyback. You can increase rigs in the Eagle Ford, you can do M&A or debt. All 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. I went over some of my comments of that earlier today. 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 four 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 sitting there and waiting to react to that is a decent position. 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 higher risk, higher growth type approach. 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.

Let me answer this another way. Stock is very cheap, which makes repurchase there, putting rigs in the 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 it funding international exploration or Gulf.

Got you, Roger. Anyway, again, good to see you beating the targets. Thanks.

Thank you. I appreciate it.

(Operator Instructions). Edward Westlake, Credit Suisse.

Hey, congrats on the earnings, the numbers and the cash flows. A lot of questions have been asked, but I just wanted to get an update on Australia. Obviously, the Perth basin I think a little bit shallower. What type of I guess hydrocarbon indications have you got in that basin and sort of target sizes 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. We get to participate with our partners and drill three wells there. They are not large, incredible opportunities. They are 50 to -- one well is around 50 million barrel mean. The other two are near 100. They are in only 60 meters of water. We get a kick at this can, have three wells for around $25 million our share. It's on the Turtle Dove Ridge basin, which is Triassic age. There's three 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, namely Chevron blocks and now the Statoil BP block. So we're 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 is in the game with some dabbling in some really big company-making wells and this will be some of those. We do not have a well commitment there as these wells would be on 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 the Perth basin.

And then in the Gulf of Mexico, just the wells that you're planning for 2015, are they up in the northlet 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 130 million barrel. It's more of a Miocene pinchout against salt play between Big Bend and Blind Faith, which are two 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 the Gulf of Mexico, a very large target there and 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 northlet opportunity toward the end of 2015 that would be an offset of the recently announced Shell Rydberg. It's a very nice opportunity and there's a lot of data coming about where sand is and derisking of northlet and we're very glad. So we have four nice wells, not dependent on each other, almost four different types and very nice, very sizable, very economic, very accretive and helpful to the Company and a real nice program.

Can you just run through the working interest of those four wells?

The Urca well would hopefully and pretty certainly go into 35%. We're 50% on the Opal opportunity with Anadarko. We're 50% today at Sea Eagle and may go down to 35% and we're currently 50% on the Desperado well in the north.

Thank you very much.

Pavel Molchanov, Raymond James.

Hey, thanks for taking the question. On the Malaysian monetization, can you just explain how taxes will work on this, particularly with the two closings in 2014 and 2015?

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

The only taxes related to the Malaysian sale will be when we repatriate the money. There is 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 US, what we're estimating now and been telling people, it's about an 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 pre-drill estimate, but that would be helpful.

130 million [P&E].

Okay, and then for [Whita] and Sea Eagle, is it too early to ask about that?

Sea Eagle is around 110 and Whita is not on the schedule today.

Okay, clear enough. Appreciate it, guys.

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

Yes, hi. Just a strategic question. You mentioned all the capital that you've returned to shareholders and value you've created like spinning off the refinery or the marketing, etc. But 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 is 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 one. Could you say it again?

What I said was you talked earlier about what you've returned to shareholders since 2012.

Yes, I got that part; what were the two 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 (multiple speakers).

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

Okay, thanks.

Thank you. 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. 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.