Murphy Oil Corp (MUR) 2015 Q4 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation fourth-quarter 2015 earnings call. Today's conference is being recorded. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations. Please go ahead.

Good afternoon, everyone, and thank you for joining us on our call today. With me are Roger Jenkins, President and Chief Executive Officer; John Eckart, Executive Vice President and Chief Financial Officer; Gene Coleman, Executive Vice President Offshore; and Mike McFadyen, Executive Vice President Onshore

Please refer to the informational slides that we have placed on the Investor Relations section of our website, as you follow along with your webcast today. Today's prepared comments will be a little bit longer than usual, so that we can give you more color on our recently announced joint venture.

John will begin by providing a review of the fourth quarter financial results, and key year-end balance sheet positions. Roger will then follow with an operational update, as well as more details regarding the Montney midstream monetization, and Duvernay Montney joint venture opportunity we just announced. We will end the call with a question and answer period.

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 discussions of risk factors, see Murphy's 2014 Annual Report on the Form 10-K on file with the SEC. Murphy makes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to John for his comments.

Thank you, Kelly, and good afternoon to everyone. Consolidated results in the fourth quarter of 2015 were a loss of $587 million. That's $3.41 per diluted share, and that compares to a profit of $375 million or $2.11 per diluted share a year ago. Excluding discontinued operations, continuing operations had a loss of $583 million in the fourth quarter of 2015, $3.39 per diluted share. And that compares to the fourth quarter of 2014 of $442 million profit, $2.48 per diluted share a year ago.

The fourth-quarter results for 2015 from continuing operations included non-cash property impairments of $192.2 million, which after taxes amounted to a $123.5 million charge. These impairments were attributable to a decline in future periods oil prices, and primarily were related to an oil and gas property in the deepwater Gulf of Mexico.

The just completed quarter also included an after-tax expense of $183.3 million to reflect the cost to exit two deepwater drilling rig contracts in the Gulf of Mexico. We chose to stack these rigs, as lower oil prices led to significant reductions in our capital expenditure program in the Gulf of Mexico, and the Company was no longer able to obtain partner support for US deepwater drilling as these partners are experiencing significant capital constraints.

Murphy also recorded a US income tax charge of $188.5 million in the fourth quarter, due to US taxable income generated by a foreign dividend declared in December. The Company had previously recorded US income tax benefits earlier in 2015 associated with an anticipated US operating loss carry forward, prior to our decision to make this foreign distribution to the parent.

The foreign distribution was made through a combination of $800 million in cash, and the remainder in the form of a 10 year note. This distribution effectively was cash tax neutral in 2015, due to operating losses, and availability of foreign tax credits. This US tax charge was recorded in the Company's corporate reporting area, which led to a higher corporate net cost overall in the 2015 quarter, compared to the prior year.

Let me speak about adjusted earnings. These adjusted earnings adjust our GAAP numbers for various items that affect comparability of earnings items between periods. And this adjusted earnings was a loss of $130.5 million in the fourth quarter of 2015, down from a profit of $69 million a year ago. This decline in adjusted earnings was primarily attributable to lower oil and natural gas sales prices in the current period.

Our schedule of adjusted earnings is included as part of our earnings release, and the amounts in this schedule are reported on an after-tax basis. The Company's average realized price for its crude oil production fell more than $28 per barrel in the fourth quarter, compared to the prior-year, which amounted to a 40% drop between periods. Natural gas prices also were weaker in the fourth quarter, compared to the prior-year quarter.

Realized oil index natural gas prices offshore Sarawak fell 31% to an average of $3.81 per Mcf, following the decline in global crude oil prices. Sales prices continue to be soft in January, and therefore revenues continue to be under pressure as quarter one 2016 prices remain significantly below prices a year ago. As a reminder, however, the Company has oil price hedges for -- excuse me -- for 20,000 barrels per day at a WTI price of $52.01 for the remainder of 2016.

At December 31, 2015, Murphy's long-term debt amounted to slightly more than $3 billion, which represented 36.4% of total capital employed, while net debt amounted to 32.8%. As of year-end, we had $600 million borrowed under our $2 billion revolver, plus we had a total of cash and invested cash of about $450 million worldwide.

Murphy's sole debt covenant is a total debt to total capital ratio of 60%, which obviously we're well below. I believe we have adequate liquidity to weather the lower-for-longer oil price environment currently being experienced. That concludes my comments, and I'll pass it now to Roger.

Thank you, John. Good afternoon, everybody, and thanks for listening to our call today. Our Company remains focused on balance sheet metrics, as the entire industry experiences further commodity price drops. With this focus comes an extensive drop in capital spending, however, Murphy intends to be in the business for the long haul, and as evidenced with news of our two purchase and sales agreements we released yesterday, when closed, will allow Murphy's to sell the natural gas midstream business, and use a portion of the proceeds to purchase a long-term asset that would deliver value to shareholders, especially in a price recovery.

Looking back at operations over the course of the year, the following highlights stand out. We spent $2.2 billion in capital, which is 42% down from the prior-year, while still growing production with the prior-year, when factoring in the 30% sell-down in Malaysia. On the cost side, we made significant improvements in reducing both operating and G&A expenses. We lowered our operating costs, excluding Syncrude, by $1.82 per BOE to $9.21 per BOE or 17% over the course of 2015, and lowered our G&A expenses by over $57 million or 16% compared to 2014 levels.

In our onshore business, the Eagle Ford shale continues to outperform expectations, where we averaged just over 57,000 barrel equivalents per day for the year, delivering a front-loaded schedule of 136 new wells, of which 27 were in the fourth quarter. We drilled our first Austin Chalk well in Karnes County, achieving a very successful IP 30 flow rate of 1,500 barrel equivalents per day. We're planning on drilling our second Austin Chalk well in the first quarter of 2016.

In Canada, we recently completed -- our recently completed wells in the Montney continue to produce above plan, where we averaged 194 million cubic feet per day for the year. In the Gulf of Mexico, the Dalmatian South 2 well which was drilled in the third quarter, achieved first production ahead of plan late in 2015. The well is currently flowing back to the [PETRONAS] facility. Development work continues at the non-operated Kodiak project, where the first two wells will flow in the coming days.

In Malaysia, fourth-quarter Sarawak natural gas production is over 134 million per day net, and oil production was over 14,000 barrels a day. Full-year production for Malaysia was over 65,200 barrel equivalents per day. We're seeing continued drilling success at our South Axis field in Sarawak, where we announced these sanctioned volumes doubling. In addition, we drilled the Keratau well offshore Brunei, finding commercial natural gas that were in line with pre-drill estimates adding to our resources in the Kelidang field. And our fourth-quarter production was just over 200,700 barrel equivalents per day, and our full-year -- for the year, we produced close to 208,000 barrel equivalents per day.

We're pleased with the ongoing efforts we are making on cost reductions. Our LOE for Q4 2015, excluding Syncrude, is $8.25 per BOE, showing a reduction of 19% from the Q4 of 2014. This is in line with the 17% reduction for full-year 2014 on LOE.

And Eagle Ford shale, had a Q4 operating expense of just under $8.50 per BOE, and we expect this to be a reasonable run rate going forward. In 2015, we produced over [207] barrel oil equivalent per day. Our strong production variance over the course of the year is attributable to Sarawak oil and natural gas fields performing better, the Eagle Ford shale and new well volumes exceeding plan, due to EUR increases and completion performance, and higher natural gas production from the Montney. More importantly, we spent $2.19 billion as compared to our original CapEx plan of $2.3 billion. Even with the significant reduction in capital for 2015, we grew annual production by 3%.

In 2015, based on preliminary data, we expect to add reserves at replacement rate of 123%, with a finding and development cost of $18.70 per BOE. Year-end 2015 reserve volumes represent a reserve life index of 10.2 years, an increase from 9.2 years from a year ago. This is consistent with our five-year average reserve replacement rate greater than 180%, and is our 10th consecutive year over 100%. During the same time frame, we have more than doubled our production including a sell-down of our Malaysia assets.

The capital program for 2016 is currently $825 million, which is approximately 62% lower than the $2.19 billion we invested in 2015. We expect production for the full-year to be 180,000 to 185,000 barrel equivalents per day, which is lower than 2015, due to significant CapEx cuts. As common in our industry, the capital program still remains under review for further reductions, should the commodity prices persist.

Moving on to subsequent year-end events. As you have read in our news release from last night, we signed two purchase and sale agreements announcing the monetization of our midstream Montney, and a joint venture in the Kaybob Duvernay and liquids-rich Montney area. We signed a definitive agreement with Enbridge to divest our natural gas processing sales pipeline assets, that support our Montney natural gas fields in Tupper and Tupper West. The cash consideration is expected to be CAD538 million, and is expected to close early in the second quarter.

In a separate, but related transaction, we signed a definitive agreement for a joint venture with Athabasca Oil Corporation to acquire 70% operated working interest in Athabasca's acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30% non-operated working interest in the liquids rich Montney. The total consideration is CAD475 million, of which CAD250 million is in cash at closing, and the remaining CAD225 million, is a carry for a period of up to five years.

In the Kaybob Duvernay, there were 230,000 gross acres, 200,000 currently prospective that are currently producing 6,900 barrel equivalent gross per day of production, of which 58% is liquids. This area will also includes 247,000 gross acres with [overlifing] rights in the conventional Montney.

In liquids rich Montney area, there are 60,000 gross acres, 21,000 currently viewed as prospective, that are currently producing 900 barrel equivalents a day gross at [34]% liquids. We're very excited enter into the Kaybob Duvernay and the liquid rich Montney, as it complements our current onshore North American resources. It fits well with our in-house expertise, and it will be our third significant North American unconventional position.

The CAD225 million carry and long lease terms associated with the Kaybob Duvernay is flexible over five years, which is key in this period of low commodity prices, where we able to control the pace of spend. We are allocating partial proceeds from our Montney midstream monetization into this project. And I see it as efficient use of capital that has a positive impact to cash on hand for our balance sheet this year, as well as use of Canadian funds in Canada in a tax efficient manner, and enter a project expected to be self-funded within Canada over the life of the carry.

The primary marketable product here as realized will be produced condensate, which is used as diluent for oil sands bitumen production and transport. The Western Canadian oil sands projects have long demonstrated a record of production resiliency, that will continue to generate demand well in excess of regional supply, resulting in relative price stability for the foreseeable future. Our joint venture has oil battery capacity of 30,000 barrels per day of oil, and a gas pipeline with over 100 million [SCFS] per day of capacity.

The Kaybob Duvernay is an emerging play, and has three same segments seen in the Eagle Ford shale, natural gas, gas condensate, and light oil. The gas condensate area has included several prolific wells of late, and in the light oil area that we now have a significant position in, is in the early stages of development. We're seeing all signs of the shale play success with increasing EURs, improving completion techniques, as well as lowering of drilling and completion costs. We feel that with three to four wells per section, we will have over 500 gross locations in the play. And this number can greatly increase, should downspacing opportunities exist here as seen in other successful North American plays.

We are seeing many successful wells across the play now, approaching 30 test intervals of over 2,000 barrels equivalent per day, with yields ranging from 200 to 950 barrels per million, and a clear indicator of the oil-rich nature of this basin. The Duvernays have been heavily drilled through other types of plays through the years in the basin, which leads to thousands of penetrations, and knowledge of the shale characteristics. Additionally, we have a black oil area in the play, again matching success seen in the Eagle Ford shale area.

Our new joint venture partner, Athabasca has been successfully play, with results in the condensate region, and most importantly in the light oil area of play. Athabasca has recently released information about a key well in the gas condensate light oil area that's flowed 1,300 barrel equivalents per day with 62% liquids. This appears to be a very good well by any measure.

As in any shale play, the optimization of the fracture treatments are key to the learning curve. Of late, higher proppant concentrations have been used in the region. This slide highlights the increase in EURs seen, with data up to two years in duration, illustrating recent higher treatments lead to consistent EUR levels. Some wells are [announcing] above the 1,000 -- 1 million, rather barrel type curve. These wells shown here, in the condensate window, are now partnered in the 33,000 acres, with a 70% working interest.

We're seeing -- we see the same well performance with higher stimulation treatments in the Duvernay light oil area, as well as where we are working a [70]% working interest, with our partner in 67,000 acres. We believe there is significant upside in the black oil area, where our partnership has 110,000 gross acres. Current data is showing high proppant content, at the 670,000 barrel equivalents EUR level.

Our joint venture also includes the liquids rich Montney, which is among the top active plays in Canada. We participate here as a non-op 30% working interest. The region has a minimum of 30% of the flow streams containing liquids, similar to the condensate and light oil areas. The results of the liquids rich area are also shown increasing EURs due to completion enhancements, and the lowering of costs with 750,000 barrel equivalent EURs seen in the data set. This area has significant running room, in the range of 100 to 200 locations with downspacing.

We see a tightly leased up area around our new acreage, with many known North American shale players. Rates here are also prolific, in the range of 800 barrel equivalents with high liquid yields. Like all major shale plays in North America, the key economic driver is the lowering drilling and completion costs, while simultaneously improving the completion techniques for each area. We are seeing the early stages of a major improvement in costs for the region, and our expertise in two other plays, where we are a top quartile drilling and completion company, will enhance our ability to quickly move up the learning curve here.

Our partner, Athabasca is active in the cost reduction business, and we will be able to quickly adapt to the area where they have recently seen [prevalent] improvements, as we see great upside in lowering costs from the current CAD9.4 million per well down to CAD6.5 million per well. Athabasca has recently seen wells being drilled for as low as CAD3.25 million, which is an outstanding performance.

As we close our call today, here are a few takeaways. We are focusing on our balance sheet at Murphy, the purchase and sale agreement to monetize our natural gas midstream, and use a portion of the proceeds to enter and launch [unconventional] shale play that allows for balance sheet neutrality, with a five-year carry and further liquidity this year for our cash positions. We see this venture as investment for the long-term, with total spend flexibility over a five-year period, as we anticipate a price recovery.

Cost reductions will continue to be our focus. Our Eagle Ford shale continues to perform very well for us. Budget reductions will lead to a very limited exploration spend this year. We continue to illustrate the execution advantages we have in the offshore.

We had an excellent year operationally in our Company, with reserve additions, significant capital reductions, and lowering costs leading the way. I would now like to open the phone lines up for any questions, and thank you.

Thank you.

(Operator Instructions)

Roger Read, Wells Fargo.

Hi, Roger, how are you doing?

I'm good, Roger, how are you?

All right.

Good. Can we talk about the acquisition? I mean, I know the sell-down in Malaysia a little over a year ago -- I think that's right, yes, the -- or at least the announcement. Then the talk of a transformative acquisition, is this one of those transformative acquisitions, or should we still consider something in the Lower 48 as though, more likely and still desirable opportunity?

No. I think of it as transformative for us. I mean, it's got all the things we're looking for today. It's very rare to get into M&A in North America and have flexibility in the first year of capital spend, and have no continuous drilling clauses, be able to drag out the carry over a very long period of time, and a very low oil price.

I've said for a long time, that I would like a 10% cost of capital type return at a strip price and with the drilling costs we're seeing here, we're able to do that here. Even on a strip that we used on January 19, which was probably $4 behind where we are today. So I see this as transformative, as far as Roger, honestly, because it has a 200, 300 million barrel ability for us.

It's a pretty low cost entry. It's different from buying from a company that's flipping acreage, because we have a partner that's working there, and has drilled there, and has infrastructure there. And we are able to work with them, and take over as the operator. They're able to operate a piece where they've been very successful. It's in Canada, where I have Canadian proceeds. There's a low ForEx right now for this transaction, where the USD equivalent of that would not get you what used to get you here in the United States. And all those factors led to this decision.

Okay. That's great. And then, as you think about Lower 48, are there still opportunities? Are we still too far apart on a bid/ask spread? Just curious, any update you would have on what you're seeing there?

Well, we look at many opportunities. I do the same thing. Whether it's offshore or in the Permian or in the Eagle Ford or wherever, we look at the rate of return we get at strip prices, and with costs. And how will it flex our balance sheet? And how -- will we have to drill, with so much capital and hurt our balance sheet further? And that's come up as a new factor in the M&A analysis that we had from a year ago.

And that's just as important now, the balance sheet of how one of these projects would impact you, as anything for me now. So we saw the returns here, very similar to a project we were working in the Lower 48. But we ended up with a project in the Lower 48, totally downspaced, every zone working, to have the same rate of return as one in Canada where we have no downspacing at all, a built-in partner, a five-year lease program, a five-year carry period and it just offered every advantage to me in $30 oil that I don't have down here right now.

Okay. Great. And last question, I'll ask on the acquisition front. You've always talked about wanting to use cash or debt. Obviously, now debt is a little more questionable as an opportunity for a whole host of reasons. Would you at all consider issuing equity? I know that's not something the Company has historically done, but as you think about that cost of capital, does that factor in, or not so much?

Well, Roger, we've been working pretty hard on these two transactions, and I don't have another one in my pocket today. I'm pretty tired. And it's taken us a lot of work to do these two. We didn't have to use debt, and we didn't have to use equity, and I'm very pleased and I am not looking for a deal today to issue equity at this price in my Company.

Great. Thank you, Roger.

Thank you.

Kyle Rhodes, RBC.

Hey, how are you doing?

Hey, guys. Is there any more light you can shed on the new midstream agreements with Enbridge, just maybe in terms of minimum volume commitments, and what that means for future drilling obligations there? And then, maybe run rate, gathering and processing expense, we should be modeling in, going forward?

We have a very nice transaction. They are very pleased with it. We're not disclosing the tariff arrangement there. You would have to look at cost of capital, those type players, residual value, and you can work through that.

I think the way to think about this business is, if you have $1.90 to $2.00 [ACO], running through that business every year. We're able to drill our wells and have cash flow neutrality, and not hurt our balance sheet in any way. A lot of optionality around how many wells we drill.

We're doing very, very well there in a EUR per well basis. We're able to get the money at a -- from these guys at a favorable rate to us, as to how this works. And we're able to use these proceeds of selling steel, and getting into 200 to 300 million barrel reserves, type P2 number.

And I like the sound of it. I like the transaction, and we're not concerned about the level of drilling that we'll need to do to allocate capital here, because of the incredible reduction in our operating expenses, our improved fracturing techniques, our lower drilling costs. And all the positive attributes of the shale we have in the Montney too. And we have a very good partner there, one of the dominating players in North America in this space, and very, very happy about it.

Okay, great. Then maybe just circling back to the Duvernay, realize the ink is still not even dry yet on this deal. But how are you guys, just kind of high-level thinking about development over the next couple years, is the light oil window going to be the near-term area of focus? Or just how should we be thinking about, in terms of derisking that new position there?

Well, I mean -- we have -- we just got the ink dried on the thing. These deals are complex, and today and the price collapse and doing a deal like this, with our partner, very happy about all the areas. And I would say that, we concentrate in a mixture of both the condensate, which is very, very successful, by many successful shale players. A pretty big light oil window that we are creeping northward, if you look through these slides today.

And we have a limited capital in 2016, because of severe drop in price. Most of that capital will be allocated toward completing wells that are owned by the partner today, if -- when we close the transaction. And we got about six or nine month period to plan out where we want to execute on that. But very pleased with all the areas, and be happy to drill wells in any of it, to be honest with you.

That's helpful. And one last one for me, Roger, just what's your current comfort level with the dividend?

Well, we've had a dividend policy here for a very long time, and the oil price has just collapsed for a short time. But like any company today, if these price levels persist, then the dividend discussion will be on the table here, in our Company and we will have that, and review that as necessary. And I would say, it would be on the table in these prices more than before. And that's really all I have to say on that matter.

I appreciate it, Roger.

Thank you.

Guy Baber, Simmons & Company.

Good morning, Guy.

Good morning. Congrats on the transaction.

Thank you.

On the JV transaction, I wanted to follow up on a comment that you made earlier, Roger, about the returns. But can you just help frame for us, and maybe discuss the economics that are underlying the deal?

On the last call, you talked about running four price decks, I think the screen deals, and wanting to get a return at the strip. And we aren't as familiar with these assets. So any return framework, or how you think these assets compete for capital in the current environment, or a rising oil price environment I think, would help us better understand this?

Well, we're in a very big collapse in price here recently, of course, and when we say strip, we were using a January 19 strip and it was around $32.76 2016, [$37] for 2017, and up to $44 in 2020. Of course, today these numbers are about $4 better than that. And when we run through this entire thing, as we've always said and always desired, and is a requirement here, is we'd be above 10%, when we look at current drilling and completion costs which are very critical -- and that's without any downspacing at all.

And then, when we have another price deck here, we call it the low -- our low planning price from January, it's a very low price for 2016 around $29, $41 in 2017, and going up to $60 in 2020. And this project looks very good, as good as any M&A we've seen, and above [15%] range. And when you get a big cost -- a big price recovery deck here, we get into the 20% range. So we're very happy about it. It stacks up well with all the opportunities we've reviewed across the spectrum, and we look at a lot, and very, very happy about it.

Okay. That's very helpful.

Thank you.

And then, can you talk a little bit more about the flexibility that you have, the minimum level of activity you all have to progress there with the JV, in terms of holding acreage, or the minimum commitments that you have, when it comes to allocating capital? Because it sounds as if that was an attractive element to this deal. So if you could just talk about that a little bit more?

Yes. It's a very attractive element, because as the whole time we looked at it, we've had another level of price collapse. And looking in the $130 million, $140 million capital through first three years on our low basis, and going into the [$200 million] in 2020 to get this carry behind us. And kind of a smooth $200 million a year doesn't lead to incredible growth for us. We're talking about a 30,000 barrel a day type number in 2023 or so.

Of course, that can be greatly enhanced with -- we feel we have conservative EURs in this analysis. And start drilling some wells in proven, and try not to build up the big overspend here. And the key thing for us, is if you look at our [Mocal] cash position [today] of [$240 million], [$250 million], whatever it is, take this money in from midstream. Have a big Western Canada business, Syncrude, East Coast Canada, and our Montney business, and our new midstream business and we're able to run through this business here, and it's EBITDA accretive to us.

It's income, a slight income accretion to us with a -- very, very low prices and we're able to run through that, and keep all of our Mocal cash balances intact and it's some $300 million-something the whole time. And that's very attractive for us, because we have to get on the balance sheet here, have to get back to free cash flow, have to get this debt worked down over time and that's about the only project we had, that had the returns I wanted, and had the ability to do that for me right now.

Okay. Great. And then, a final one for me, on the capital budget for 2016, you made a comment that the budget would be under review for further reductions. So just trying to understand that comment, is that if the current strip persists? Is that if we see another leg down in price? Help us understand -- on that comment?

And then, it seems as if you've hit the CapEx budget pretty hard, obviously. Where do you have incremental flexibility to flex lower if you choose to do that?

We have a lot of flexibility in the Eagle Ford, and we can go down $100 million there if we want to and that's the beauty of these plays, is you can slow it down, more difficult than offshore. And that would be where that would come from. And while price is on a rampage the last four days, it's still not too exciting to me. I can tell you that.

So we have got to keep this balance sheet intact, we cannot be lulled into believing this is back, here headed in the $40s, and just not headed that way. I'm not scared to cut the CapEx, and I will and we're going to get it on balance sheet instead of production, because I've grown production as much as anybody through the years. And so, we're going to stay in business for a long time. We're going to keep our balance sheet in the right ZIP code here.

Okay. Great. Thanks for all the comments, Roger.

Thank you.

Ryan Todd, Deutsche Bank.

Ryan, how are you doing?

Good, thanks. How ar you doing, Roger?

All right.

Maybe following up on capital allocation a little bit. Can you talk a little bit about relative competition in the capital between the Eagle Ford, and the Athabasca JV going forward? I mean, where are the relative rates of return are -- yes, what are the relative rate of return right now between the two plays? And if we were to see incremental upward pressure on the commodity, where would we see capital go first?

I think that our Eagle Ford, because of its oily nature, and not the US [ACO] nature, it will always be slightly ahead of our wells up there. But then you have this balance sheet issue of US costs, and repatriation and tax efficiency, and working in the Mocal area. But if we were to move it around pretty good, they compete very well, a condensate well, and a oil window well up in Canada competes very well with a Lower Eagle Ford shale in Karnes.

And that's what's so interesting, Ron, about this deal, and about these shale plays, is that four years ago, the Catarina area, where we have an enormous acreage position in Western Eagle Ford shale, was one of our lowest rate of return areas in the Company, or in the Eagle Ford I mean. So over this time, the EURs have doubled, the drilling costs have halved, and it went from the bottom to the best. So it's the best individual well, economics around 25%, on that January 19 strip day, where we normalized all of our costs. And this project up there, is competing with there.

But the point is, is things change. Some areas become better than others, places not so good last time are better this time. The costs in this northern light oil area are very, very good, and getting much better and we've put those costs in here, this project going to compete with Eagle Ford very well for us. And then it will be a matter of our capital -- what we do about repatriation, and how we want to work in our Mocal cash balance. But on the overall allocation of capital, it will work well and it will be some hard decisions there.

Great. Thanks. And then maybe one -- maybe another one on CapEx. In the Eagle Ford, the level of spend in the Eagle Ford seems fairly high for running 1.25 rigs. I mean, is there a timing issue related to there? How much of that infrastructure related, or is there -- as we look forward over the next year or two, is there some of that CapEx that we should expect to see roll off going forward?

(Multiple speakers) I'll let Mike answer that for you.

Hi, it's Mike McFadyen here. I guess, can you repeat the question again, please?

The question is, it looks like you're spending about $340 million in the Eagle Ford, running 1.25 rigs roughly for the year, which I mean, the absolute level of spend seems a little high. Is that -- can you -- how much of that additional capital in the Eagle Ford is infrastructure related, or and should we expect to see any of that roll off over the -- or is it a timing issue over the next period of months or years?

It's primarily drilling and completions. We're going to drill 45 wells, and we're going to complete between 55 and 60 wells. So we have some well inventory that we'll complete, with that capital as well.

So it's a fairly significant amount. There's a little bit of electrification work that will help lower our operating costs, probably about $30 million, $40 million of that. But as Roger mentioned, that capital could be considered to be cut as well and we could consider going down to less than one rig in the Eagle Ford, and putting back $100 million to the corporation.

Okay. Thanks. That's great. I appreciate that, and I will leave it there.

All right.

Thank you.

Paul Cheng, Barclays.

Hey, guys. Good afternoon.

Hi, Paul. How are you doing?

Very good. It looks like it's a very good transaction. Roger, just curious, the $825 million CapEx that you put out, I presume that's not including the JV spending, right?

That's correct, Paul. We're going to have a year of explaining this. The $825 million is Murphy as-is. We go into this transaction we, of course, have to pay the down payment. And I'm speaking to you now -- and that's another confusing thing, Paul, we have to keep in mind, is I'm speaking now in USD. So this CapEx would go up by $223 million, but most of it is the purchase, a down payment.

And then, we will have very limited capital at $30 million to $40 million this year, is the current plan. And we have to get with our partner, get with what's going on with their production reserves, et cetera, and allocate capital there efficiently. But we have planned -- now keep in mind, that this deal is structured between November 30 and January 20, and it wasn't an exciting time for oil prices, Paul.

And so, we have very limited capital there planned in 2016, kind of get our feet on the ground. Get in there with a partner that has been working, and has been working well. And they have a pick up, and move forward, and it get on into 2017. But very little this year, Paul. But that is correct, the guidance here for production, and the capital in these remarks today, do not include the transaction we did with our joint venture partner, Athabasca.

Roger, on the first couple years, when you start spending money in this joint venture, are those -- some of this (inaudible) project], or that is going to be, will be already in the [manufacturing side]?

Oh no, I don't see that. There's loads of wells here. There's incredible amount of information being released by nearby shale players like Encana, are very successful here. And Canada is a little different than Texas. It's incredible, accurate data released publicly.

A lot of what all the proppants are, the links to the well are, the orientation to the well. Canada does a very good job in that regard. And I see us getting into pads and drilling four well pads, much earlier than we did in the Eagle Ford. And I think that it's critical to understand that Murphy had zero shale presence in our Company four years ago, 900 wells today. And know what we're doing, and we're going to get in there, and get going, hopefully in pad drilling here pretty quick, Paul.

Yes. Can you give us some idea that in 2017, what kind of range of oil price, and what kind of JV spending going to look like? So if -- (multiple speakers)

2017 is like (multiple speakers)

At [$35] and what would be, and if you had $60, what kind of spending we maybe talking about?

I only have the low case in front of me, Paul. When we get back to $60, we will be glad to speak with you about that. I'm seeing capital in the $130 million range for 2017 and 2018 right now in front of me, as I look at this, Paul.

Okay. And Roger, if you are going to stay at $825 million on your base operations? And if you stay there for 2017, what's going to be 2017 -- the rate look like? Is it going to be a rate similar to -- (multiple speakers)

Paul, we've been doing very well in production here, and the Eagle Ford has been resilient. We have it declining in here this year and we've gone through two or three budgets here, have a Board meeting next week in that regard, and really not getting off into 2017. We've had a pretty big collapse in price. We're trying to focus on our balance sheet above all, and not leading the way on the 2017 guidance parade there, Paul.

Okay. Two final questions. One, can you give us some idea that how's the Eagle Ford production trend by quarter look like? Or that I mean, we start off from what -- and end the year at roughly what run rate? And then finally, it look like you guys didn't have any reserve write-down, or mark down on the proved and reserve, not like some of your peers. I just wanted to make sure that's the case?

Well, that's true, Paul. Mike McFadyen is going to look up the cap -- the production for you, and I'll speak about the reserves.

We had a very good year in reserves in this Company, and we've done a good job on it for a long time and we added some PUD locations in the Eagle Ford. We've had some very small negative revisions in our performance as a Company.

We've had some type curve enhancements in Eagle Ford shale. We had some operating expense help into the long cycle. Actually, Paul with our Company, in Malaysia, you're able to get some adding barrels with price, and as our entitlement goes up.

So it's an advantage in of, not just being in one spot. It's not significant, but it helped us there. And, of course, we sold down 20 million barrels in Malaysia and produced 76 million. So to replace with half the budget, and we're a Company that's very proud of our EURs and our costs, and very happy about the lack of a write-down in our calculations, Paul.

And now, Mike is going to talk to you about the production in Eagle Ford, which is -- have a lot less CapEx this year.

Sure. Thanks. On the production side, so we finished the quarter four of 2015 at about 57,000 barrels of oil equivalent. Forecast forward for the first quarter is about 54,000, second quarter is 48,000, third-quarter is 47,000, and then the fourth is about 44,000, for a 2016 average of 48,400.

Okay. And a final one. John, do you have a rough estimate of the 2016 DD&A for the Company, given all the reserve mark down and everything?

Wait, Paul, we don't have reserve write-downs.(multiple speakers).

I'm sorry -- that

No reserves, Paul. (multiple speakers).

All right. Thanks for that correction, Roger. That's correct. We are looking, Paul, at DD&A rates in the $16 range company-wide for 2016, so down significantly from where we were, due to the impairment expenses that were taken in 2015.

Thank you.

Okay, Paul, thanks, man.

Ed Westlake, Credit Suisse.

Hey, Ed, how are you doing?

Good, very well, and congrats on getting this deal done.

Thank you.

So I wanted to get a little extra detail, if I may. Obviously, $9 million getting down to $6.4 million in terms of the well costs, 11,000 feet of total vertical depth. I mean, maybe just walk us through what the biggest things are, that will get you to that cost down? And then, I'll follow up on EURs.

Mike McFadden, the head of our onshore business is going to comment on that for me, Ed.

Thanks.

Yes, I'll speak to that. So the light oil window, which represents the lion's share of the acreage, we value at about 67,000 acres of that, is can be drilled without intermediate casing. And Athabasca just drilled two Pacesetter wells there in 2015, one at 13 days, and one at 16 days. So it's that kind of drilling performance at -- in the CAD3 million to in the CAD3.5 million is what they spent, including lease construction costs, is what's going to get us there.

It's similar to the northern part of our Eagle Ford, where we've started in the basin with drill times of 25-plus days, and are now down to 7 days in the Catarina area. It's also similar to our Montney operated area, where we are continuing to improve drill times and costs there. Where we've driven - we're down now in the $6 million, sub $6 million drill and complete costs in our Tupper, Tupper West area, where we are targeting anywhere from 12 to 14 days a well this year.

Okay. And then on the recoverable resource of 200 to 350, I'm just looking at the bubble map you've got on slide 12. I mean, as with some of these other combo plays, you've had the better results in the gas condensate light oil. I don't know how many wells have actually been drilled in the black oil area. Maybe talk a little bit about -- there is a decent chunk of acreage up there -- maybe talk a little bit about what was included in that resource number? And then, what economics would be needed to get the black oil window to work?

We didn't count any above the black oil line on page 12, right now. We used only the light oil and the condensate, and then the liquids Montney that shows up in some other slides. And this acreage is quite derisked in the gas condensate area. There are successful wells all around it. And we used a no downspacing there, and used no downspacing anywhere to arrive at that number, Ed.

And then, we took a -- over in the Western part of this thing called light oil on page 12, some very successful wells. And we took a higher EUR curve there. You can see some of the EUR results in the back here, as to the concentration of proppant, Ed. And moving to the east, we took a more conservative one. These wells have a rate of return in the 14%, 15% range at a $30 oil type strip.

I think in the black oil area, it's a matter of -- there would be some experimentation there to figure out how to make that work. That's the issue now with capital allocation. But the advantage here, is that a lot of long life leases like leasing in the Gulf of Mexico if you will, it's a government crown lease, and no continuous drilling clauses, a lot of flexibility, a lot of information to come to us. There's constantly wells being released for information in this region, and we've been monitoring that. And real excited about just a portion of it working, is incredibly valuable to us, Ed.

The final question from me is on the Alberta royalty review. I mean, obviously, part of the reason why Canada does better than the US is because more attractive fiscal terms. So maybe any color in terms of what you think is going to happen there, and how that might impact the economics?

Well, we have about a 5% starting off royalty there, probably going into [15%] over the life. There are some discussions about that royalty. They've been-- I view the Alberta government, and in general being helpful in some of these things, as the price collapse has gone down, probably unlike our administration here. And we're happy -- we think that could impact, like less than a digit type of rate of return, and not significant from the Alberta group that's coming up. And like real happy with the comment that you made, and agree, and happy about the royalties situation up here.

Okay. Thanks so much, Roger. Good luck.

Thank you.

James Sullivan, Alembic Global Advisors.

Hey, good afternoon, guys.

Hey, Jim.

Congrats on the deal, first off. And I just want to quickly ask on infrastructure up there. Athabasca has obviously talked about they own some of the infrastructure processing and so on. So they have some graphics on what they've got up there.

But is that -- is there anything in there that would be an impediment to the pace of the development? I know you guys are obviously sounding like you're going to move pretty slowly. But just wanted to see whether there are any roadblocks there, or whether you'd be dependent on third-party build-outs?

No. Not at all. Today, they have 30,000 of oil batteries, and an ability on oil, over [$]100 million of gas. There's a lot of MLP type activity, and people reactivating gas plants. This has been a historic producing basin.

Similar to Eagle Ford shale in many ways, with a lot of gas pipes headed to Edmonton, a lot of transport of condensate. There's two exits for gas coming out of here, which are very helpful. And we now have part of that infrastructure as to our working interest with our partner there, and glad to have it. It's valuable as well, it's up and going. They're adding to it, used to adding into it, know how to add to it. Pleased to not have to start over in the infrastructure business at a $34 oil.

Yes. No, makes good sense. Thanks for that. Last one -- last two for me are just quick modeling ones. Where did you guys take the accrual for the rig termination on the balance sheet? I was trying to obviously -- (multiple speakers)

John, John Eckart will answer that for me, if you don't mind.

Yes, James, that expense was taken in US E&P business. So you will find it on our oil and gas operating results, as an expense in the US business.

Okay. Great. And then on the balance sheet, where did you guys take the -- where's the credit for that? Because I understand the cash is going to be paid in Q1. Is that right?

Yes. It's a current liability, James. So in the balance sheet information we gave, it would be in the other current liabilities section.

Perfect. Great. Thanks. And the last quick one here, with the Montney midstream sale, can you guys give any -- I know you don't want to comment on the terms obviously there. But can you guys characterize in any way the impact on costs or realizations or -- well, first off, maybe just where the costs live? Whether it's in the gas realizations or whether it's in the [LOE] per BOE? And then, what the order of magnitude would be there?

Okay. James, we expect at this point, and have modeled it as it would be an LOE type expense on our books, that we will report in Canada.

Perfect.

Conventional business.

That's just a nice way of asking, James, and I appreciate it, but I can't disclose.

All right. Great. Thanks, guys. Appreciate it.

Thank you.

Paul Sankey, Wolfe Research.

Hi, Paul. How are you doing?

Fine, thank you. Happy new year. Roger, firstly very specifically on the Montney, what are the -- if you like, operational costs of that deal? I mean, what are the impacts on your business, from not having the midstream any longer, if any?

Well, we have a very good partner that operates a lot of midstream in North America, and a lot midstream in Canada. This is a competitive process, very glad with the winter there if you will. If they lower operating expenses at the plant level, we are able to share in some of that with them. They should be able to do that, as they do that for a living there, and we operate just those two plants.

I think we are very good operator. I think they could help, and we could share in that. We've got our operating expenses probably down in the $0.30 range per MCF, it's an incredible job by Mike and his team. And so, that's where that stands. And I'm real pleased to move that midstream into an upstream, and not impact my balance sheet, Paul.

Yes. So the idea is obviously, they're going to bring down the costs for you, and you benefit from that?

If they do, we get to benefit, yes.

Got it. And then, if I could go from micro to macro, when we met in December you I think, kind of rounding the numbers, you were talking about $1 billion of CapEx. And then was implied to be more like $900 million. I seem to remember that you were saying, that you could go down as low as $800 million, but it would be very painful to go any lower than that. And this being a $100 million number thrown around for less activity in the Eagle Ford, are those numbers about right?

Yes.

And can I just clarify I wasn't sure exactly what you were saying or implying. But were you saying that the dividend would or would not be part of a potential change in spending? I couldn't understand whether you were saying --?

Oh. We're going to take a -- I would -- first on that matter what I said is, that if these prices persist -- and I'm not greatly enthused by the run up today, I still believe we're going to be in a low $30s [oil], but I'm very happy -- it's up a little bit I suppose. As we have that persist, we will have to take a closer look at our dividend, than we have before. And it will be done, as we go through the year.

And on your prior questions, I mean, yes, I said the $800 million would be very painful, and it is, because our production levels are down. But we've got to get control of our free cash flow goal. And then, when we get this rig issue behind us this year, which would have caused a lot more capital had we kept it, we will work toward not running up our debt at all, and look to lowering debt the best we can. So that's -- things have changed. Since I saw you, we probably lost $10 a barrel crude, Paul.

Yes.

So it is a lot more -- so if I said it was painful, it is. So and we have to realize it, get on it, focus on cost. We've done a great job on costs, and we are seeing very competitive prices from service companies as to fracking services in North America and these continue to compete well with each other and help us, as to this collapse. And we're going to continue to stay on it. And that's what we're going to do.

Okay, Roger, thanks. Good luck.

Thank you, Paul.

Pavel Molchanov, Raymond James.

Hey, guys. Just two housekeeping items. On the Canadian -- dual Canadian deal, is there a tax efficiency to keeping your proceeds from the midstream deal in Canada, rather than repatriating?

Well, I mean, obviously, if we were to consider repatriating and declaring some type of dividend, Paul, then we'd have to pay a toll for doing that. Because there's withholding tax of 5%. And there is quite frankly, a different and always has been, a differential in the tax rate in Canada being 25%, 26%, 27% range, as opposed to 35% tax rate in the US.

So we've always been declared indefinitely reinvested in Canada. You'd keep it that way, up until you couldn't do it anymore. And because you don't really want to pay that toll, if you don't have to.

But there is cash up there, so it's an evaluation of how you have to look at it, on an overall basis of what's best for the Corporation in total. So yes, keeping it up there, saves cash taxes is the short answer.

And on your oil sands, the legacy oil sands asset, have you calculated what the $20 a ton carbon tax is going to amount to, in extra LOE next year?

I believe it's only around 10%. We don't see it to be astronomical there. It was a -- Suncor is a partner in that and heavily involved in that, was a part of that negotiation if you will, with the government entities there. And we do not see that to be a major impact on that project, and Suncor must not, because they're interested in more of it, I suppose.

So is it a couple dollars in LOE, or a couple dollars a barrel? What's the --?

It would be less. I mean, the OpEx on this thing is quite changing, and you've got to watch the USD ForEx on that. But if it's in the CAD30-something, it would be a couple dollars, the way I see it.

Okay. Appreciate it.

Thank you. Okay. That's all we have today. Appreciate everyone for calling in. And we will be back next quarter and continued focus on costs here at Murphy, and are excited about our new deal that we had today, both of them, in fact. And we'll be back to it, and thank everyone for calling in. I appreciate it. Thank you.

Thank you. That will conclude today's conference. We thank you all for your participation.