Murphy Oil Corp (MUR) 2016 Q1 法說會逐字稿

Good afternoon ladies and gentlemen and welcome to the Murphy Oil Corporation first-quarter 2016 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.

Thank you operator. Good afternoon, everyone, and thank you for joining us on our call today. With me are Roger Jenkins, President and Chief Executive Officer, and John Eckart, Executive Vice President and Chief Financial Officer. Please refer to the informational slides we have placed on the Investor Relations section of our website as you can follow along with the webcast today.

John will begin by providing a review of first-quarter financial results highlighting our strong balance sheet and liquidity position following our most recently announced divestitures. Roger will then follow with an operational update and outlook, 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 discussions of risk factors, see Murphy's 2015 annual report on Form 10-K on file with the SEC. Murphy takes 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 very much, Kelly, and good afternoon everyone. Murphy's consolidated results in the first quarter of 2016 were a loss of $198.8 million, which is $1.16 per diluted share. That compares to a loss of $14.4 million or $0.08 per diluted share a year ago. Excluding our discontinued operations, our continuing operations had a loss of $199.5 million, again $1.16, versus a profit in the first quarter of 2015 of $3.5 million, which was $0.02 per diluted share.

The first-quarter results from continuing operations for 2016 included non-cash property impairments of $95.1 million, which after taxes amounted to a $68.9 million charge. These impairments were primarily attributable to declines in future periods oil prices as of quarter end March, and the impairments related to both Terra Nova and sealed properties in Canada. The just completed quarter also included an after-tax expense of $6.2 million to reflect restructuring costs by the Company.

The 2015 first quarter a year ago benefited from a $199.5 million after-tax gain on the sale of 10% of our Malaysian assets which closed in January 2015. Adjusted earnings, which adjusts our GAAP numbers for various items that affect comparability of results between periods, was a loss of $112.8 million in the first quarter 2016, an improvement from the adjusted net loss of $198.5 million a year ago. This improvement in adjusted results in 2016 was primarily attributable to lower exploration expenses partially offset by significantly lower oil and natural gas sales prices compared to a year ago. 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 was $34.19 per barrel sold, which was almost $13 per barrel lower, 27% in the first quarter of 2016 compared to the prior year. Natural gas prices also were weaker in the first quarter compared with the prior year's quarter. Average North American gas price realizations of $1.57 per 1,000 cubic feet dropped $0.89 per MCF for a decline of 36%. Realized oil index natural gas price at offshore Sarawak fell 18% to an average of $3.67 per MCF following the decline in global crude oil prices.

The Company's cash flow from continuing operations for the first three months of 2016 was burdened by Deepwater rig contract exit payments of $253.2 million. The income statement charge associated with these Deepwater rig exits was recorded in the fourth quarter of 2015.

For the second quarter 2016, the Company has WTI-based oil price hedges for 20,000 barrels per day at a WTI average price of $52.01. For the last six months of 2016, the Company has entered into an additional 5,000 barrels per day hedge at $45.30 per barrel for a blended average WTI price of $50.67 covering 25,000 barrels per day for the last six months of 2016.

Additionally, the Company has forward sales contracts for Canadian natural gas in the amount of 59 million cubic feet a day at an average AECO price of CAD3.19 per 1,000 cubic feet over the remaining nine months of 2016.

At quarter end, March 31, 2016, Murphy's long-term debt amounted to $3.4 billion, 39.6% of total capital employed, while net debt amounted to 35.5%. As of quarter end, we had $971 million of combined borrowings under our $2 billion revolver and uncommitted credit facilities. We also had a total of cash and invested cash of about $569 million worldwide. The closing of the Montney midstream asset sale for CAD538 million on April 1 added to our cash position early in the second quarter, and the future completion of the recently announced Syncrude sale will also add to our cash position.

Murphy's sole debt covenant at the present time is a total debt to capital ratio of 60%.

Thank you. And that concludes my comments and I'll pass it over to Roger at this time.

Thank you John. Good afternoon everyone and thank you for listening to our call today.

Looking back at the first quarter the following highlights stand out. We produced 196,600 barrels equivalents. We were able to exceed our quarterly guidance with high level of execution. We experienced close to zero planned downtime for maintenance because of our diversified production base and higher field performance in many of our key fields.

From a safety standpoint, we had zero recordable incidents across our entire Company during the quarter, which is a remarkable feat for our operating team.

We remain laser focused on reducing costs across our business. During the quarter, we reduced our 2016 annual capital to $580 million from the previously announced $825 million plan, most importantly, after a 73% reduction from our 2015 capital spend of $2.2 billion. We also reduced lease operating expenses excluding Syncrude by 22% quarter-over-quarter.

Also, we continue to reposition our portfolio, including closing the previously announced non-core asset sale of our Montney midstream assets, as well as recent signing a purchase and sale agreement to divest 5% of nonoperated working interest at Syncrude. We are working diligently to close our previously announced joint venture focused on expanding our footprint in the North American onshore and conventional business in the Kaybob, Duvernay and liquid rich Montney areas in Canada. We continue to review our portfolio and will act when opportunities present themselves.

I'm pleased with the ongoing efforts our team is making in cost reductions. The lease operating expenses in Quarter 1, excluding Syncrude, were $7.50 per BOE, showing a reduction of some 22% from the first quarter of 2015 and a reduction of 9% from the fourth quarter last year. As a result, our decreased activity following lower commodity prices, we implemented a Company-wide workforce reduction, lowering our staffing levels by about 20% in 2016. Duvernay will lower our G&A costs, excluding restructuring charges, by approximately 26% quarter-over-quarter.

The capital program for 2016 being maintained as I previously said at $580 million while maintaining our production guidance range of 180,000 to 185,000 barrel equivalents per day. Our first-quarter spending is roughly 25% of our annual CapEx, which is on our plan. Our annual and quarter capital and production plans have not yet been adjusted for pending asset divestment and assets should be acquired. Updating for production, capital spending will be released from closing of these transactions. Production for the second quarter of 2016 is estimated to be in the range of 177,000 to 180,000 barrel equivalents per day.

Looking at production, as I said, we produced 196,600 equivalents per day, exceeding guidance. Our stronger than forecasted first-quarter volumes are primarily due to higher production from the Eagle Ford Shale, higher natural gas production from the Montney, higher oil production from both offshore Sabah Malaysia and offshore Canada, and these increases are partially offset by delays in bringing on a Kodiak subsea well in the Gulf of Mexico as well as increased downtime in Sarawak and Kikeh and Baldwin, our natural gas production in that area.

It is important to note that our second-quarter production guidance of 177,000 to 180,000 compared to first quarter's negatively impacted our planned downtime and maintenance across many of our assets, including 10 days at Sarawak natural gas, the Kakap Gumusut subsea wells, two subsea wells, shut in for 21 days in offshore Malaysia. In Terra Nova, they are working on a 28 day turnaround and we are part of their long-term 45 day turnaround at Syncrude, which is ongoing.

The current guidance is based on Syncrude producing at reduced rates until the planned turnaround is complete over the next two weeks. However, we have not updated the forecast with the recent news of wildfires in this area. Our thoughts go to the misplaced residents in the Fort McMurray area. Plus our Eagle Ford Shale will have natural production decline this quarter as we have no new wells planned to be added in that field.

In our onshore business, the Eagle Ford Shale continues to perform well where we average near 56,000 barrels equivalents a day for the quarter, where we delivered 13 new wells online, bringing our total operating well count to over 660. And the Eagle Ford Shale had first-quarter operating expenses of just under $8.00, a 6% reduction from the fourth quarter of 2015.

We continue making strides in increasing drilling and completion costs as we average $4.1 million per well, which is 26% below first quarter of 2015. We drilled a pacesetter well in only six days from spud to rig release in our Catarina area.

It's important to note that our strategy to work inside a lower or longer commodity price regime with our much lower capital spend in 2016 will lead to bringing on 28 new wells and drilling 25 wells in the Eagle Ford. This is well below the 136 operated wells in bottom line in 2015. We still have significant run room ahead of us here with over 2,000 potential Eagle Ford Shale locations. The reserves are oil weighted at roughly 90%, and the asset is very meaningful to Murphy's future reserves production and cash flow.

Last year, we drilled our first Austin Chalk well in Karnes County. We continue to be pleased with the well's performance, and just recently we spud another Austin Chalk well in the Catarina area, testing the most western part of our acreage. We have an Austin Chalk well standing in the Karnes area which will be completed later this year. We estimate we have approximately 265 Austin Chalk locations, of which 115 are in Karnes and 115 in Catarina. The Karnes area, which is currently derisked by current well being online for some seven months, could add an additional 30 million barrel equivalents of resources to our Eagle Ford Shale business.

In Canada, our Montney asset continues to produce above plan. We averaged 207 million a day there for the quarter. LOE was $0.26 per MCF, a 32% reduction quarter-over-quarter with no new wells brought online in this quarter, but we plan to complete four wells in the second quarter, targeting 15 to 18 Bcf EUR in those wells.

We closed the sale of our Montney natural gas processing plant early in the second quarter. After incurring the new tariff associated with the sale, we can expect well breakeven prices for a 10% rate of return to be approximately $1.65 AECO at a ForEx conversion of 0.79. The significantly lower LOE, along with our greatly reduced drilling and completion costs and higher EUR wells, enable us to easily manage the new tariff. We take advantage -- and we took advantage of the monetization by deploying the proceeds into higher returning assets.

In our offshore Malaysia business, we produced over 58,000 barrels equivalents per day during the quarter. We continue with our Sarawak development drilling in South Acis and are on track for a July installation of a new producing facility for that field.

In Kakap Gumusut, first-quarter production averaged over 142,000 gross with peak production nearing 157,000 gross in that field. That field is simply incredible.

In the Gulf of Mexico, production for the first quarter of 2016 was approximately 19,200 barrels equivalents per day with 80% liquids. The Kodiak well initially came online at planned rates during the first quarter, but was taken off-line as it experienced surface facility issues. Those modifications are complete and the well should be flowing very near term.

In the month of April, we drilled to exploration commitment wells, one in Malaysia and one in Vietnam and Malaysia. The Beduk-1 offsetting our South Acis field found a noncommercial natural gas accumulation that's plugged and abandoned. In Vietnam, the CC-1X well in block 11-2 found an oil-paying well but it is not commercial for a planned sidetrack, and we also plugged that well. These are both shallow-water low cost opportunities, and together will result in a total expense of near $15 million for this second quarter.

There are no exploration wells planned for this year as a result of our reduced capital plan. We continue progress our farming agreement with Petro Vietnam for the 15-1 LLD field in the Cuu Long Basin where we had a successful well test last year.

We continue working to protect our balance sheet. And the end of the first quarter, we have $1.1 billion of availability under our revolver with $925 million drawn, we have $569 million of cash in our corporation, which does not include the proceeds from our midstream monetization of some CAD538 million from earlier in the second quarter. Our long-term debt to total capitalization is just under 40% at the end of the first quarter, well below our sole revolver covenant of 60%.

Some takeaways today -- we continue to operate at a high level in terms of drilling and completion improvements and cost reductions, as demonstrated in the first-quarter results. We continue to focus on our shareholders with no issuance of equity, and in the price collapse look to further strengthen our balance sheet. We significantly reduced our 2016 capital plan to $580 million while maintaining our annual guidance of 180,000 to 185,000 equivalents per day.

Our key plays continue performing well, especially our North American unconventional assets as well as our Malaysian assets.

Our portfolio is under continuous review as we remain true to our strategy of focusing on North American unconventional resources while maintaining our global offshore presence. Working to reserve our balance sheets as evidenced by monetizing non-core assets in the Montney midstream, progression of the joint venture closing in the Kaybob, Duvernay and liquids rich Montney area, and the recent signing of a purchase sale agreement to monetize our Syncrude position.

That's all I have, and I'd like to open up the phone lines for questions now.

(Operator Instructions). Paul Sankey, Wolfe Research.

You've done a great job on retrenchments, and a very low CapEx number for this year. I was wondering what would volumes look like in years two and three, if you like, in 2017 and 2018 if we were to hold down at this level?

Thanks Paul. We have a lot of recalibration going on in Murphy right now, because we are selling an asset that's a 13,000 to 14,000 barrel a day type number, fairly flat. We reposition ourselves into a new unconventional position once closed. We are very, very pleased about that, so we have a lot of comings and goings as to that right now.

And if we look out in the fourth quarter, 175,000, 174,000 kind of a fourth-quarter number for us. And take away Syncrude and add in the new unconventional project in Duvernay Shale, we're going to get ourselves into the 160,000s range and I believe we can modestly grow that with some high 40s% next year and kind of get back on the growth plan there.

But our focus is trying to get back to cash flow CapEx parity with all certainty, not necessarily looking to grow production, but to have the right types of returns and capital allocation among our enhancements in unconventionals that we are looking to do, and really believe we can have some growth there again, but it would be a matter of what we want to do to get there. And kind of pleased with that recalibration, but it's going to take some time to get our sales back organized to recover the sale of the Syncrude barrel, if you follow me there.

I do. I understand that it's under sort of review at the moment, or preview. But are we at the kind of level that you think -- is what you're saying in the high [$40s] you believe you are now balanced for 2017 with basically flat volumes?

Yes. Toward -- when I look at the fourth quarter and adjust for Syncrude, yes.

Yes, that's what I kind of derived from your answer. Thanks. And where, assuming oil prices recover, would you want Murphy to be in three years' time, Roger? Will we ever go back to Deepwater exploration, or do you see it now as very much a nonconventional push for you guys? Thank you.

No, we make near $100 million of cash flow, cash margin in Malaysia this month and near $100 million in Eagle Ford. We made a lot of money in the offshore business. We are seeing probably more review of discovered reserve opportunities where we bring our competitive advantage of executing well facilities in the offshore. Offshore is a little bit off the beaten path. I would say today probably not if I get my three unconventionals organized between Duvernay Shale, Eagle Ford and Montney and probably not looking for a fourth there. And the future would be back to where we've delivered a lot of value, a lot of -- and there is such a cash flow shape of the curve, so different between onshore and offshore, as you know Paul, put a lot of money up front in offshore and take in a lot of cash, as we've done for years. Onshore machines need a lot of cash for a while. So that's the thought basis there.

As far as exploration, there will be opportunities in the reduced capital plan. I man even super majors have reduced exploration, so we would too. And we have our thumb in a couple of nice places and we'll see how that goes and look to do that another day, but this year laying low and lowering our cost and keeping the balance sheet as it is or improved is our focus today.

Thank you sir.

Roger Read, Wells Fargo.

Good afternoon. I'm good. I hope you're doing well as well. Kicking into kind of looking at that production level in the 160,000s, can you talk to us a little bit about decline rates, kind of what you've seen and then what you would expect as you look at I would think mostly your core Eagle Ford position but also across what you still have in Malaysia?

Our offshore business is probably around -- offshore Malaysia is probably a 13% to 15% kind of number and our Gulf is around a 20% number. Our Eagle Ford is very complex. As you know, it depends on adding wells, and how many wells you're adding, and the space between them. It's probably in the 30s% for a new well and then after a couple of years it gets into the 20s% and down into the 10s%. So it's a complex machine there when you start and stop your completion program in these shale plays.

But we have a decline this quarter in the Eagle Ford Shale because we are adding new rigs. We actually haven't added a well since March now, so we are looking at over two months without adding a well. And I am real pleased with how the production is looking there and happy about how that's looking and it was part of our success in the first quarter, and real pleased about that. But the exact decline of a start and stop capital spend in a shale I think is a pretty hard number to get out there, Roger.

And along those lines, given the CapEx, you've got laid out commitments across the board, how should we think about completion process, drilling and completion, in the Eagle Ford as we go into the remainder of the year?

Hang on one second, Roger. I have a schedule here. Let me turn to it. They say these microphones can hear every page I turn, so sorry about that.

In the Eagle Ford, we are going to complete three wells in July, and around seven wells in August, and three wells in September, and four wells in November. And we're going to drill a few wells, between two to four wells, a month between now and the end of the year.

So basically taking care of the duck inventory is what that sounds like then.

Well, we are kind of sort of maintaining it I think. We've never going to -- I don't really use that word duck too often. It's not one of my favorite terms. We have some wells that have been completed in the low 30s% right now. We've never been a big leader in that parade, and we'll probably maintain it because we are completing about as many as we are drilling, and end up in the high 30s%. We are not in one of these hundreds of wells duck man as you like to say.

Duck Dynasty. Thanks, Roger.

Ed Westlake, Credit Suisse.

Thanks very much. I hope everyone is all right up in Canada. On the Duvernay transaction, I obviously appreciate still very early there, but any updates in any of the wells that have been drilled by the partner since you were last able to speak?

No, there hasn't been a lot of wells by our partner. We're working closely with our partner. This is a complex transaction to close because it involves two fields, Duvernay Shale, it involves the liquid rich Montney, it involved a built-in infrastructure system that they have a high interest in that has ample room for us to enter. A lot of positive news by our peers in the play, especially the condensate area in which we have 33,000 acres there once we close this with our partner.

And I would say in Canada, we would have more of the recent results there, doing very well in both operating and production, and very excited to get in there with that play, and believe that we can jumpstart the learning curve with all our experience in Eagle Ford and Montney, and get with our partner who has a built-in position and be ready to execute there in short order.

And then totally separate, the cash, I mean obviously you are going to be raising cash through this year in Canada. Is there some sort of need to kind of I guess redistribute that somewhere else internationally as opposed to bringing it back in the US? Maybe just talk about any drivers other than just the value of the cash on the balance sheet.

I'm going to have John answer that for me if you don't mind.

We are, as you know, as Roger said, nearing closing on the acquisition of the Duvernay from another Canadian company. And the transaction, as you probably are aware, requires an acquisition payment of CAD250 million, subject to closing adjustments. And it also comes with a commitment to carry our partner on certain future drilling. So, we have commitments up in Canada.

And the Syncrude -- the good news about the Syncrude proceeds, should we get that transaction closed, is it gives us both investment allocation flexibility within our unconventional assets, as well as financial flexibility by improving our balance sheet position. We will obviously have lower net debt positions post-closing, which is represented by our debt less cash and invested cash. And so we will have both the capability of capital allocation options and financial options in our favor once the Syncrude transaction closes. So we are in the process and we will continue to evaluate our options. We will be discussing this further in future periods when the Syncrude transaction closes. And I think that's really kind of what we want to say at this point in time.

So just if I could maybe probe a little further, the cash comes in from Syncrude later in the year. Oil prices go up. There's no imperative to drill under the Canadian lease structure. So it sounds like you get on the front foot in terms of further delineating and then getting to appraisal in sort of 2017/2018?

Yes. I would say we are well in the mid-year now, and just getting this to hopefully close soon. And this year, our limited capital spend of completing four wells there with our partners, and some additional field development expenses, and then get into a plan next year of a decent capital spend and it will have to complete well with our other unconventionals like Eagle Ford but it has very, very similar returns, and anticipate that we will be wanting to get in there and work there at some capital level. And we're in the middle of that field development plan as we speak.

Thanks very much.

Paul Cheng, Barclays.

I was just curious. You guys own the 5% Syncrude for over 20 years. And speaking theoretically, there has been talk about oh, should you (inaudible). In the last, say, 12 months, it seems like finally, after long-suffering, that the operation is improving. Unit costs are coming down, and the price that we see is not necessary considered very high. So is there any particular change in your thinking about that asset or your portfolio related to the decision that you want to sell your share other than saying that you may want to have the cash sitting on the balance sheet because of position yourself for let's say lower for longer (inaudible). Other than that reason, is there any other fundamental reasons for the decision that you make here?

Thanks Paul. I don't believe the price is that bad as to our long-range planning, and there have been some operational improvements here. They been very short-term as opposed to the 22 years of turnarounds that go over the schedule and various things of that nature. As we look at a price recovery type deck, we see this price to be very fair in our long-range planning and we should know, we've been in an asset for a real long time. So if you're looking at oil being $76 in 2020, or $74 in 2019 -- I like the position we have in Canadian dollars here honestly. I think it's a matter of we probably had 400 million barrels four or five years ago. We have 770 million barrels now. We had a real good year of reserve replacement. We've increased our overall P a good bit in our Company. And it becomes a matter of not -- of when. If not now, when? So we have a strategic situation where I would like to leave the asset and we have a strategic situation where Suncor wants to buy the asset at the same time that have built-in price on a share basis with COS. We were able to turn that into all cash. That opportunity was in stock. I thought that was very good for us and very fair. That's exactly the same money that COS paid for these barrels on a per barrel basis or on an e-metric, exactly the same.

This project returns free cash flow when oil is $100, but not so much when it's below $80. So we wanted to move out of that and feel like our reserves have increased. And we want to focus in unconventional nearby acreage there what we can get the OpEx below $10 million, and out of the OpEx, even if it's improved to slightly below $30 million, and it was a built in time to do it, it felt like it was a rare time that we could execute it and went ahead and moved on.

John, is the cash proceeds from the Syncrude sale, is there much of a tax indication or we should assume you receive the full cash?

The cash we receive, and we do have to give some basis to Suncor, and so there could be a little bit of cash taxes that we have to pay in Canada. We are still evaluating that and computing it. So I think there will be a little bit of cash tax owed on the Syncrude transaction, but it won't be a super large amount. On an overall basis, it's going to be probably P&L slightly positive.

Should we assume that at least you would get 90% of whatever is the proceed in cash?

That would -- yes, I think it's that much or more. I would say it's probably a little more.

Okay. And John, do you have an update about your negotiations with the bank on the revolver expansion?

Yes, it's ongoing, and we are -- due to the Syncrude transaction, we are rejiggering all of our numbers for presentation to the banks. Those are being shared with our bankers today -- at this time, not necessarily today. And we will have discussions ongoing for the next few weeks trying to negotiate something there. We have a goal of trying to do something in the next few months obviously, and so we would like to get that behind us. But we clearly are -- things are improving. Our situation with our asset transactions are I think in our favor, so we see it basically being much better and much different that it was two to three months ago. So we are confident that this will get done in a reasonable time and a reasonable way.

With the changing in your asset mix, what is the -- any set of new set of matrix in terms of the financial leverage that you can share with us that you are maybe targeting?

In terms of total debt?

Total debt or debt to EBITDA, or any ratio that you is targeting that at least we would be able to put into our model? Not necessarily, say, for tomorrow, but on a longer-term basis that where you want to reach over the next one or two years.

We were a top quartile EBITDA multiple debt player in October, and when oil prices were higher, a different time, oil price collapsed a lot since then, building back now. And I would like that multiple in the three range, or low threes, and we never want our debt to cap to be above where it is today if we can do something about that. And that's a personal type of number for me. It doesn't mean every day you're exactly on that number, but that is the kind of goals John and I talk about.

Okay. And then John, on the US, I was a little bit surprised that your unit DD&A in the first quarter didn't drop from the fourth-quarter level, given you book additional reserve and you are not bringing on really that many new wells in the shale. Is there any particular reason that unit DD&A may actually be up?

I'm looking at it here.

We'll have Kelly follow-up. We drilled some wells there. We probably had a very small PUD debooking in the Eagle Ford last year but our overall reserves there were very positive. And the DD&A is at our plan and wasn't planned to be reduced. You've got to keep in mind that, on impairments, we didn't have any in our onshore business in unconventionals. And this has probably primarily been an issue in offshore where our DD&A is significantly lower. But onshore DD&A for the Eagle Ford Shale is exactly on the plan we've had for a long time as we add costs. You've got to keep in mind we added 138 completed wells there last year, had enormously higher CapEx, and if you're adding costs and reserves at the same pace, then the DD&A rate should be the same.

Final question, Roger, with the headcount reduction and all that, based on your current organizational capability, if you are not adding people, how many wells -- how many rigs that you can actually run or handle, let's say if the economic is available in the US and Canada?

We can easily go to three or four rigs. I do not see that as an issue. We have capable drilling and completion people both employed in our offshore and onshore assets between Calgary and Houston. And we've kind of recalibrated the size of our Company and looked at it very, very closely around our G&A to drive that to a better quartile improvement. And that is not -- my concern is getting back to work if needed from a G&A perspective. I've been through these (multiple speakers) as people say nine times in my career, and we always get back to work and we are organized to be able to do that and that's not an issue for me.

So Roger, when you say three to four rigs, it's three to four rigs in the US, three to four rigs in Canada, right? (multiple speakers)

No, I would say that would be in North America.

North America three to four rigs. Okay.

Between the Canada and the Eagle Ford together, four rigs. I say that won't be a problem. I can handle the problem whenever we get to that, believe me.

Yes. Thank you.

Guy Baber, Simmons.

I'm doing good. Thank you guys for taking my question. Roger, I had a capital allocation question for you. But as you've ramped down your capital spending, the dividend now has obviously become sizable relative to your CapEx. So, the question is how you think about weighing the potential for incremental growth spending to help arrest declines, or allocate capital to attractive places like Montney and Kaybob Duvernay versus continuing to pay out that same dividend at the same level. How do you think about the relative ranking of capital deployment between those two options right now?

I mean the dividend policy at Murphy is a long-term policy and oil prices have been a short-term change. Oil prices are up even $10 since the last time we had a call. That's well over $200-something million in cash flow for Murphy.

Our dividend here is under closer review than it has been before. It will be under meeting in August. And really you're going to do that quarter by quarter. We've paid two of the dividends at the full price here, and it is -- important to capital allocation than it is for other things.

And we continue to see well costs come down. We are able to execute more well with less cost. We are able to do this at both Montney and Eagle Ford. And I think we are still in such a recalibration mode of our cash flows with all of the ins and outs of our business, this will be something really for the fall. And we're going to be focusing on this production and cash flow and where we allocate capital and will be kicking that can down the road until the fall time, to be honest with you, Guy.

Great. Thanks Roger. And then the capital spending for the quarter, it looked like it was pretty much in line with the annual guidance, but we had actually expected that to be trending lower through the year as you ramp down some of your rig activity. So, it looked like the CapEx was lower than what we had anticipated. Are you operating more efficiently, and does the CapEx look like it could be coming in lower than what the internal plan has been? Anything you can share on that front?

I would imagine today if -- one of our financial outlook books that we produce here at Murphy, we'd find our capital probably $30 million less than our $580 million today. It will be a matter of do we want to add some wells for the savings in a place like an Eagle Ford, but our capital is really on schedule and almost times 4 equal. And we have -- well, I a few minutes ago rattled off some wells in the Eagle Ford. We will have wells in the Montney too. And then we have opportunities. Our jackup rig in Malaysia is farmed out to another party, and it will be coming back, and we are installing a jacket there. And when CapEx gets to that level, small things can change it. But I'm very pleased with the idea that we are not overspending or frontloading our CapEx, because our CapEx is a very real item that we are focused on here, and we are not frontloading it with the idea that we're going to increase it. We have got our CapEx set at these levels, happy with how it's going, happy with the efficiency, the cost reductions, and continuing on with that regime at this time.

Thanks. And then last one for me. The cost performance this quarter, obviously very impressive with the lowest per barrel costs in a number of years. To what extent is the performance that you delivered this quarter, is that sustainable? Were there any one-time benefits? I know you ran very well during the quarter. But is that sustainable? And then also, in an improving oil price environment, to what extent do you think these are structural cost improvements that you've captured?

I would say we have some downtime events this quarter, as I went through in my remarks. So that [doesn't] lead to lower OpEx, as you would imagine. We had a very, very good OpEx in the $7.50 range, and we are trending to get back to where we were last year around the $9.00 range. But in our internal planning, we were $1.00 under our very aggressive budget. So my folks that handle our upstream business are doing a very good job. Our procurement, the cost of services continue to improve, and the focus and the proper allocation of those costs. But we did not have a special item this quarter that drove that. So I continue to be positively surprised on OpEx by my team. It's a big focus that we have. And while I say that we may end up over at the end of the year with declining production, which we've talked about here today, at the same level, I've been greatly surprised and very pleased with how OpEx is going here.

As to the service side, you would anticipate that to run out of room there, but it continues to be positive, reinforce the procurement and aggressive bidding of services. And each time we have procurement, we continue to have small gains in procurement of bidding to companies that have maintained their market share or business. So I continue to be positively surprised. I've got a great team focused on it and I think we're doing a great job there and I'm real happy about it.

Thanks Roger.

Kyle Rhodes, RBC Capital Markets.

Good afternoon guys. Just one for me. Any update you can provide on block H FL&G program, maybe in terms of expectations for first gas and what your future capital outlays are for that project in 2017 and 2018?

We are going to have over $100 million there, and probably some more into 2018. The subsurface side of the field is incredibly successful for us, many successful wells in a row, a great gas project, very, very similar in rates to our SK gas.

Petronas has started this vessel. They're supplying the floating LNG vessel in Korea. It is partially built and they are trying to slow that project down because these are tied to Brent prices, but work -- this project works well when Brent is around $50. They have -- and we have a gas agreement with them. They've come to us about pushing the first gas to that into 2020, in which they would have the expense of changing the capital spend with the vessel in the Korean shipyard if you will, and we are agreeable to that. It would give us more capital for next year to use in our other high returning assets like Eagle Ford Shale or Duvernay Shale. And so we push out that production to 2020, and that's fine with me at this time. It will be another long-term LNG asset with one of the great LNG partners in the world, and it's going to work out for us down the road there.

Got it. So less than $100 million in 2017 spend. And then any idea just what the full development costs are?

I don't have that right in front of me. I apologize. Kelly can get that for you. But that hasn't changed. I would say that costs are lower because I anticipate Deepwater rigs to be lower, and they well may not be by 2019, but I imagine they will. In our services there, we are in a great situation in cost. But our large partner there would like to push it to the right and I'd like to say $100 million right now, and I'm very pleased with the adjustment when we get organized with Petronas.

Makes sense. Thanks guys.

Evan Calio, Morgan Stanley.

Just I know you guys have been very successful in reducing CapEx. I'm just trying to understand the full year of production guidance following that reduction. I know there's steep declines in 2Q, in your 2Q guidance. What operationally flattens those declines out in the second half? Is that just the return of -- for maintenance (multiple speakers) activities that you mentioned?

Yes, that's right. We're looking at production in Canada in the third quarter, second quarter, actually going up as we have some more Montney production there, slightly more. It had an enormous pile on of downtime in the second quarter we knew about. We also have some downtime planned in our business for Kikeh, which is very rarely shutdown. In our Block K area, it's been I guess 10 years since that facility stopped.

And the Eagle Ford Shale is just a less well count decline in the Gulf of Mexico, but it's basically flat. So Quarter 2 to Quarter 3 would primarily be around just a lack of investment in the Eagle Ford Shale, and after that, it would be very flat if it were not for that issue. So I think it's a big downtime in the second quarter. But we have to keep in mind that, all along, our external guidance is the same. And we had a capital spend that was very low, and we came into the year with many wells on the Eagle Ford Shale being completed in December, and now we are at that same guidance. So nothing has really changed on that regard.

Great. My second question, I guess follow-upping on the capital allocation question, but what's the -- is regaining your investment grade rating a key priority in the recovery? And would you expect that would drive running your business free cash flow positive into an early portion of a recovery?

You know, the investment-grade thing is a couple of months ago. We move on to all these assets, ins and outs. We've been fairly active in our Company changing our portfolio. I want to get my own targets on debt and continue to defend our position there. And it's not we get up every day and say let's get back to investment grade again. I think the multiples of EBITDA and a leanment on debt to cap and working inside cash flow CapEx parity, we continue to illustrate that, then we will move back the investment grade line again. We are still investment grade with S&P. So I don't get up every morning focusing on Moody's, but we're going to try to do the right thing, work on these -- being a leader in some of these multiples, and it will work out over time for us.

So free cash flow parity is how we should think about you in terms of the future reinvestment when the commodity price recovers?

Yes, that's correct.

Great. Appreciate it guys.

(Operator Instructions). Sean Sneeden, Oppenheimer.

Go ahead sir. Are you there?

Brian Singer, Goldman Sachs.

Thank you. Good afternoon. I wanted to ask a couple of questions with regards to decline rates. You mentioned in your comments you've been surprised by a more modest decline coming I think out of the Eagle Ford since you stopped adding new wells. And I wondered if that is just the natural decline or whether you're doing anything specifically to try to mitigate that that has been the source of the better performance.

There is a lot of focus on when to put in artificial lift and stay inside our operating expense and cash projections. There's these rigs we hire to optimize when you put on artificial lift, how you set up the artificial lift. And when things get very difficult and you're cutting your budget, people move from focusing on growth to enhancing the base. And we have been very happy with how our teams have performed as to that total focus on what wells are down, where they are down, and how you improve the artificial lift timing. And that's been a source of the success there in my view.

Thanks. If I could ask a very similar question in Malaysia also. Without speaking to the ups and downs of maintenance in various places, can you talk to what your natural oil decline rates are, and then anything that you can do either in terms of Brownfield type legacy type drilling here and there, or decline mitigations?

We think of Malaysia as probably a less than 20% decline. It can be as low as 15%. A lot of these projects are supported by water injection. And we're at very constant production of gas there on a BOE basis. You know, we've been in that business of gas there for a long time. When things are running appropriately, we have at least 250 million gross that we operate into a Petronas LNG plant, so that's a pretty constant production that only is up and down with LNG. So that moves fairly constant, also still a cash flow providing feel for us at $360 per MCF. And the rest of the fields, just Kakap Gumusut where we have 8% is a very, very successful field with limited decline in zone plateau, and you roll all that together and just not an enormous decline rate coming out of there primarily at this time related to these downtime events that I described.

Got it. Great. Thank you very much.

Pavel Molchanov, Raymond James.

Thanks for taking the question. Just one for me. Looking at the possibility that you would resume exploration in 2017 or subsequent to that, other than Vietnam, which you just entered a few months ago, what other geographies might you consider getting back into exploration?

At this time, we have a very nice acreage position in the Vulcan Basin north of Australia, and we are trying to focus at this time until the cost structure in the Deepwater rigs of the Gulf get more organized. We are not focusing their right now. Vulcan Basin Australia is a very underexplored place where we have a very large new seismic data set and we are onto a new play there with some 100 million barrel type opportunities and are very inexpensive to drill. That would be one focus area.

We have a partner there, Mitsui. We are 60/40 with them.

We also, as you know, in the great Australian bite, we have the Ceduna Basin where we have an enormous acreage position with all of our seismic acquired and reprocessed, and we are sitting next to BP and Statoil and also Chevron who will be drilling upwards to six to eight wells over the next couple of years. This is a prolific Basin, the size of the North Sea, and one of the largest left undrilled basins in the world where we have a position to be able to watch them drill. And those are our focus areas in Vietnam. It's Cuu Long Basin. And we have to think Vietnam as a place similar to Malaysia where we start with shallow water blocks. We also have ultra-deepwater blocks and entering that long-term relationship allowed us to enter into the Cuu Long Basin where we are working with them to add some additional acreage. And we formed into a very successful project there and have to look at Vietnam holistically because the Cuu Long Basin is the prize there. And those are our areas today.

We're also interested in Mexico bid round, because they will not have the higher cost placed on the Gulf Mexico by this administration. I think that is positive.

Also of note in the exploration world today, seismic is very inexpensive, massive seismic availability for inside our budget here. We are not looking to increase our budget in any way, especially in that. But we get lots of data today and build up positions again if needed in this low environment.

You mentioned a lot of blocks. Do any of them expire, let's say, by the end of 2017?

No.

Very good. Thank you guys.

Sean Sneeden, Oppenheimer.

We missed you a while ago.

Sorry about that. That was a phone issue on my line. But thank you for putting me in.

I'm having a little trouble hearing you.

Just one quick one for me. Just thinking about the revolver maturity that's coming up I guess in just over a year, how are you guys thinking through that process? Is the expectation that it's just going to be a simple kind of amend and extend, and it stays unsecured, or can you talk about how you are approaching that now that you have some (technical difficulty) sales in hand?

I'll let John speak to it. But it is a blend and extend type of thing that we prefer, an option we prefer. And we believe our Syncrude situation and the cash that we have on our balance sheet just in general from an asset perspective is helping that, and also our lower capital spending hitting our targets. In a oil price recovery, I think things are leading to positive nature in that in my view. I've sensed a sentiment of improvement in that business over the last six weeks.

There's a little more positive action going on in the marketplace, Sean, and we are -- our goal is to extend, we are talking to our bankers about it, probably consider having to adjust our $2 billion somewhat in terms of the maximum size. We'd like to keep it unsecured obviously, so we are working toward that as well. So it's all in the works, all being discussed and negotiations to proceed over time. And we are confident we can get the thing extended at a reasonable size and in a reasonable manner in terms of security and such.

Okay, that's helpful. Thank you very much.

Arun Jayaram, JPMorgan.

Good afternoon. I wanted to ask you a little bit about the decision to suspend completion activity in the Eagle Ford. Broadly, at a higher level, you guys are shifting towards more of a North American unconventional focus. I was a little bit surprised, given the quality of your Eagle Ford acreage in the quarter, that you would suspend activity, or at least the completion activity. I was wondering if you could help us think about that. And what oil price do you think you need, Roger, where you think your US onshore business could deliver value to the drill bit?

All of our hopefully new to Tubison, Duvernay Shale and our Eagle Ford can deliver 10% rates of return in the low $30s, and we are ahead of that now. We at Murphy set out earlier in the year when the price collapsed to organize our capital around the lowest capital we could have and then recalibrate our Company because, in and around that, I knew of asset sales and different things we are doing. We are not a company that goes out saying we are selling all these assets and doing that, but we have a lot going on to accomplish all these purchase and sale agreements that you read about in the press. So in and around that, we're trying to get to a minimum capital spend, recalibrate our company. Once we had the closing and then we have our revolver to redo, a recalibration of our company, a focus on non-core in North America into unconventionals, all that takes time. So we went into it with a low CapEx, so we go into Eagle Ford and we have continuous drilling obligations and we move our rig around for that. And then from that, we are not a company that builds up drilled and completed wells, and we have a low level of CapEx to meet all these other goals of recalibration I spoke of. And that led to that schedule. And that schedule has only been around since around mid-February, and I am not interested in probably breaking it back up an opening it back up to capital to raid on May 5, or whatever today is. So that's how we are thinking about that. It was derived on purpose from a lowest commitment basis, and we are focusing on costs in that and we will come out of this when we are confident of an oil price recovery. And like any operator, oil gets into the $50s, things change a lot, and we'll have to then allocate capital among that and offshore opportunities and move forward. But today we are looking at a more conservative view of that at Murphy oil Corporation.

Makes sense. Just a follow-up. Any more details on the Kodiak well, timing and the magnitude of what (technical difficulty)

This is a really good well. The key thing in the business is subsurface. You have to have subsurface. The well flow, has the ability to flow over 10,000 barrels a day from a single well, that's the beauty of offshore. That's why offshore still works. And the well had a choke manufacturing issue on the surface involving some products that were built into the choke that had to be changed. There's special order type equipment, we had to get involved with the operator and get the turned around and fixed. There's nothing wrong with the well, it's going to flow at a higher oil price today, so it's fine.

Is that going to come back -- any sense on timing? Is this a second half 2016 (multiple speakers)

Oh, no. We are talking about hopefully right now while we are talking.

Thanks a lot.

We are talking about right now. It better be right now.

Okay. That's helpful. Thank you very much.

(Operator Instructions). John Herrlin, Societe Generale.

Most things have been asked, but I was wondering, with the unconventionals, obviously everybody is doing better with optimizations, more sand, more fluids, more intervals, whatever. Are you working at all with density pilots in your shale plays to --

We worked on about everything, but I have to tell you I'm not aware of it. I wouldn't be surprised. But I will say this about unconventional, there's continued improvement by everyone. And if you look at all these press releases, you will see Murphy executing, performing at or above everybody else. That's not uncommon.

But I know that, in my view, with our big service providers looking to merge, I know they are not going to merge. And with focus on less capital spending, I believe the technological issues in unconventionals have gone on the sideline for this year. And I believe that we are missing -- we could miss some efficiency as you go to less pad drilling and some efficiency on experimentation of capital that I think was driving a lot of the unconventional improvement, which would lead to lower US oil production and an oil price recovery. But if you have just a few well and everyone is reducing their CapEx, not just Murphy, there will be less experimentation of capital, if you will, in my view.

Great. Thanks.

That's all we have today. That's the end of our call. I appreciate everyone calling in, and we'll talk to you the next time we have a quote release. And I appreciate it. Thank you.

This concludes today's call. Thank you for your participation. You may now disconnect.