Kelly L. Whitley - Vice President-Investor Relations & Communications John W. Eckart - Chief Financial Officer & Executive Vice President Roger W. Jenkins - President & Chief Executive Officer Paul Sankey - Analyst, Wolfe Research LLC.

Roger D. Read - Wells Fargo Securities LLC Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Paul Cheng - Barclays Capital, Inc. Guy A. Baber IV - Simmons & Company Kyle Rhodes - RBC Capital Markets LLC Evan Calio - Morgan Stanley & Co. LLC Brian Singer - Goldman Sachs & Co. Pavel S. Molchanov - Raymond James & Associates, Inc. Sean M.

Sneeden - Oppenheimer & Co., Inc. (Broker) Arun Jayaram - JPMorgan Securities LLC John P. Herrlin - SG Americas Securities LLC.

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 information on slides that 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, and 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 and $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 $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 Seal properties in Canada. The just completed quarter also included an after-tax expense of $6.2 million to reflect restructuring cost 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 adjust 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 barrels sold, which was almost $13 per barrel lower, 27% in the first quarter 2016 compared to the prior year.

Natural gas prices also were weaker in the first quarter compared to the prior year's quarter, average North American gas price realizations of $1.57 per 1,000 cubic feet, drop of $0.89 per Mcf or a decline of 36%.

Realized oil index natural gas prices 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 or 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 C$3.19 per 1,000 cubic feet on 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 borrow – 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 C$538 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 barrel equivalents. We were able to exceed our quarterly guidance with high level of execution.

We experienced close to zero plant downtime or maintenance across 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's 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 with $580 million from the previously announced $825 million plan, and 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 continued to reposition our portfolio, including closing a previously announced non-core asset sale of our Montney midstream assets, as well as recently signed a purchase and sale agreement to divest 5% non-operated working interest at Syncrude.

We're working diligently to close our previously announced joint venture focus on expanding our footprint in the North American onshore unconventional business in the Kaybob, Duvernay and liquid rich Montney areas in Canada. We continue to review our portfolio when opportunities present themselves.

I'm pleased with the ongoing efforts our team is making on cost reductions, the lease operating expenses in quarter one excluding Syncrude at $7.50 per boe, showing a reduction of some 22% from first quarter 2015 and a reduction of 9% from the fourth quarter last year.

As a result, our decreased activity following lower commodity prices and implemented a companywide workforce reduction lowering our staffing levels by about 20% in 2016. We've been able to lower our G&A costs, excluding restructuring charges, by approximately 26% quarter-over-quarter.

The capital program for 2016 is being maintained, as I previously said at $580 million, while maintaining our production guidance range of 180,000 barrel equivalents per day 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 as such should be acquired. Updating for production and capital spending will be released from the closing of these transactions.

Production for the second quarter 2016 is estimated to be in the range of 177,000 barrel equivalents per day 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 were partially offset by delays in bringing on our Kodiak subsea well in the Gulf of Mexico, as well as increased downtime in Sarawak and Kikeh involved in our natural gas production in that area.

It is important to note that our second quarter production guidance of 177,000 boepd to 180,000 boepd compared to first quarter has negatively impacted our planned downtime and maintenance across many of our assets including 10 days at Sarawak natural gas, the Kakap-Gumusut subsea well, two subsea wells, shutting for 21 days in offshore Malaysia and Terra Nova there working on 28 day turnaround, and we are part of the 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, (10:52) in this place resonance in the Fort McMurray area.

First to (10:57) 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, Eagle Ford Shale continues to perform well, where we average near 56,000 barrel equivalents a day for the quarter, where we delivered 13 new wells online, bringing our total operated well count to over 660.

In the Eagle Ford Shale, that first quarter operating expense is just under $8, a 6% reduction from the fourth quarter of 2015. We continue making strides in decreasing drilling and completion costs as we averaged $4.1 million per well, which is 26% below first quarter 2015.

We drilled a pacesetter well in only six days from spud to rig release in our Catarina area. It is important to note our strategy to work inside a lower for 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 operating wells we bought online in 2015. We still have significant running room ahead of us here of over 2,000 potential Eagle Ford Shale locations; reserves are all weighted at roughly 90%; 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 wells performance and just recently we spud another Austin Chalk well in 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 that we have approximately 265 Austin Chalk locations of which 115 are in Karnes and 115 Catarina. The Karnes area, which is currently de-risked by current well being online for some seven months, could add an additional 30 million barrel equivalents of resources through our Eagle Ford Shale business.

In Canada, our Montney asset continued 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, but no new wells brought online in this quarter, but we plan complete four wells in the second quarter targeting 15 to 18 this year EUR in those wells.

We closed the sale of our Montney natural gas processing plants earlier in the second quarter, that's incurring a new tariff associated with the sale, we can expect well breakeven process for a 10% rate of return to be approximately $1.65 U.S. AECO at a 4X conversion of 0.79.

This significantly lower LOE along with our greatly reduced drilling and completion cost and higher EUR wells enable us to easily manage the new tariff, and take the advantage of – and took advantage of the monetization by the point (13:49) proceeds into higher returning assets.

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

In Kakap-Gumusut, first quarter production averaged over 142,000 mbopd gross with peak production nearing 157,000 mbopd gross in that field, that feels simply incredible. In the Gulf of Mexico, production for the first quarter of 2016 was approximately 19,200 barrel equivalents per day, 80% liquids.

Kodiak well initially came online at planned rates during the first quarter, it was taken offline 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 two exploration commitment wells, one in Malaysia and one in Vietnam.

In Malaysia, the Beduk-1, offsetting our South Acis field, and a non-commercial natural gas accumulations plugged and abandoned. Vietnam CC-1X well in Block 11-2 found oil paying well, but it's not commercial for planned sidetrack, we also plugged that well.

These are both shallow water low-cost opportunities and together will result in total expense of near $15 million for this second quarter.

There're no exploration wells planned for this year, as a result of our reduced capital plan and continue progress of our farm-in agreement with Petro Vietnam for the 15-1 LDD field in the Cuu Long Basin, where we got a successful well test last year. We continue working to protect our balance sheet.

End of the first quarter we have $1.1 billion of availability under our revolver, with $925 million drawn. We had $569 million of cash in our corporation, which does not include the proceeds from our midstream monetization, some C$538 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%. The takeaways today, and we continue to operate at 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, in the price collapse, look to further strengthen our balance sheet. This significantly reduced our 2016 capital plan of $580 million, while maintaining our annual guidance of 180,000 equivalents per day to 185,000 equivalents per day.

Our key plays continue performing well, especially on 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 preserve our balance sheet is 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 a recent signing of a purchase to sale agreement to monetize our Syncrude concession.

That's all I have, and I would like to open up for phone lines for questions now. Thank you..

Thank you. And our first question will come from Paul Sankey from Wolfe Research..

Hi, Roger..

Good afternoon, Paul..

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..

Well, thanks, Paul. I mean, we have a lot of recalibration going on in Murphy right now, because we're selling an asset that's a 13,000 barrels a day, 14,000 barrels a day type number, fairly flat. We've repositioned our-self into a new unconventional position once closed.

We're very, very pleased about that, so we have a lot of comings and goings, Paul, as to that right now. And if we look out in the fourth quarter, 175,000 boe – 174,000 boe kind of a fourth quarter number for us.

And take away Syncrude and add in the new unconventional project in Duvernay Shale, you don't (18:19) get ourselves into the 160,000s boe range, and I believe we can modestly grow that with some high 40,000s boe 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're looking to do.

And really believe we can have some growth there, again but it'll 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 accelerated (19:06) review at the moment or preview with – are we at a kind of level that you think what – is what you are saying that in a high-40,000s boe, you believe you're now balanced for 2017 with basically flat volumes?.

Yes, toward – we now look at the fourth quarter, and adjust for Syncrude, yes..

Yeah, 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' times, Roger? Will we ever go back to deepwater exploration or do you see it now as very much an unconventional 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, made a lot of money in the offshore business. We are seeing probably more review of discovery reserve opportunities where we bring our competitive advantage of executing wells, facilities in the offshore.

Offshore is a little bit off the beaten path, I would say, today I'm probably not – if I get my three unconventionals organized between Duvernay Shale, Eagle Ford and Montney, I'm 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 they're such a cash flow – shape of the curve so different between onshore and offshore, as you know, Paul.

Put a lot of money upfront 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. And as far as exploration, I mean, there will be opportunities and a reduced capital plan, and 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 balance sheet as it is or improve it is our focus today..

Thank you, sir..

Thank you, Paul. See there (21:04)..

And our next question comes from Roger Read from Wells Fargo..

Hey, good afternoon..

Hey, Roger.

How are you doing?.

I'm good. I'm good. Thank you, I hope you're doing well as well..

Sure..

Kicking into kind of looking at that production level in the 160,000s boe.

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%, 15% kind of number and our Gulf is around a 20% number. Our Eagle Ford is very complex. Roger, as you know, we have – it depends on adding wells and how many wells you're adding and the space between them.

It's probably in the 30%s for a new well and then after a couple of years, that gets into the 20%s and down into the 10%s, so it's a complex machine there when you start and stop your completion program in these shale plays.

And – but we have a decline this quarter in Eagle Ford Shale because we're adding new rigs – we actually haven't added a well since March now. So we're looking over two months without (22:26) adding a well.

And I'm 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, I'm real pleased about that. But the exact decline of a start and stop capital spend in the shale, I think, is a pretty hard number to get at 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 (23:01) 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 wells 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, I can – sort of maintaining it, I think, we've never been a – 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 (23:43) right now.

We have never been a big leader in that parade and we'll probably maintain it because we're completing about as many as we're drilling in that high-30s (23:51), we're not one of these hundreds of wells duckman as you like to say..

Duck dynasty..

Correct..

All right. Thanks, Roger..

All right. Thank you. Talk to you next time..

And our next question will come from Ed Westlake from Credit Suisse..

Hey, Ed, how are you doing?.

Yes. Good. Thanks very much. I hope everyone is all right up in Canada.

On the Duvernay transaction, obviously I appreciate, still very early there, but any updates in any of the wells that have been drilled by the partners 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 close, because it involves two fields, Duvernay Shale, involves liquid-rich Montney.

It involved a built-in infrastructure system that they have a hype (24:48) interest in, they have 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 Encana would have more of the recent results there, doing very well on both operating and production.

And I'm 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 (25:27) 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 U.S.? I mean, maybe just talk about any drivers other than just the value of the cash in the balance sheet..

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

Right. Thanks..

Hello, Ed. We are – as you know, as Roger said, nearing – closing on the acquisition of Duvernay from another Canadian company. And the transaction is – you probably are aware, requires an acquisition payment of C$250 million subject to closing adjustments. And also it 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'll have both the capability of capital allocation options and financial options in our favor once the Syncrude transaction closes.

So, we are in a process, and we'll continue to evaluate our options, we'll 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, I mean, there is 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 a price all-in (27:17) sort of 2017, 2018?.

Yes. I would say, we're well in the midyear now, Ed, 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 spending that we'll have to complete well with our other unconventional (27:44) Eagle Ford, but it has very, very similar returns, 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..

Thank you, Ed..

And our next question will come from Paul Cheng from Barclays..

Hey, guys. (28:06)..

Hi, Paul..

Hey, Rogers, just curious, I mean, you guys own the 5% Syncrude for over 20 years?.

Yes..

And speaking theoretically, there has been talking about (28:18). In the last, say, 12 months that seems like finally after long suffering that the operation is improving. Unit (28:28) costs are coming down and the price you receive is not necessarily considered very high.

So is there any particular change in your thinking about (28:39) your portfolio lead to the decision that you want to sell it here other than saying that you may want to have the cash sitting on the balance sheet because – position yourself for, say, lower for longer (28:54).

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 have been very short term as opposed to 22 years of turnaround 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 the asset for a real (29:28) long time. So if you're looking at oil being $76 in 2020 or $74 in 2019, and 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 years, five years ago. We have 770 million barrels now, we had a real good year of reserve replacement, we've increased (29:52) in our company. And it becomes a matter of not – if when – if not now, when.

So we have a strategic situation where I would like to leave the asset, we have a strategic situation where Suncor wants to buy the asset at the same time at a built-in price on a share basis with COS, we were able to turn that into all cash, but that opportunity was in stock, thought that was very good for us and very fair.

It's exactly the same money that COS paid for these barrels on a per barrel basis or on any metric exactly same. This project returned free cash flow when oil was $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 where we can get the OpEx below $10 million (30:44), and out of the OpEx even if it's improved to slightly below $30 million (30:48) and it was a built-in time to do it or felt like it was a rare time that we could execute it and we had (30:56) moved on..

John, is the cash proceeds on the Syncrude sales, is then much of a tax indication (31:05) or that we should assume you receive the full cash?.

Well, the cash we receive and we – they have to give some basis, Paul, to Suncor. And so, there could be a little bit of cash taxes that we have to pay in Canada. We're still evaluating that and computing it, but 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 in a – on an overall basis, this is going to be probably P&L slightly positive..

Right.

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

That would – yeah, I think it's that much, Paul, or more. I would say it's probably little more..

Okay.

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

Yeah. So it's ongoing, Paul, 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 and that at this time not necessarily today, but – (32:23) 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'd like to get that behind us. But we clearly are – things are improving, our situation with our asset, transactions I think in our favor. So we see it basically being much better and much different than it was two months to three months ago.

So we're 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 difference that you can share with us that you may be targeting?.

In terms of total debt?.

Whether it's total debt or that debt to EBITDA or any ratio that you was targeting that at least that we will be able to put into our model.

Not necessary say for tomorrow, but on a longer-term basis that where you want to reach over the next one year or two years?.

Well, Paul, I mean, we were a top quartile EBITDA multiple debt player in October. And when oil prices were high – when – different time oil price collapsed a lot since and 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 cannot do something about that, and that's a personal type of number for me. Doesn't mean every day you're exactly on that number, but that's kind of goals John and I talk about..

Okay. And then, John, on the U.S., I was a little bit surprised that your unit DD&A in the first quarter being dropped from the fourth quarter level given you book additional reserve, and you're not bringing on (34:25) many new well in the Shale.

Is there any particular reason that the unit DD&A may actually be up?.

Paul, I'm looking at it here..

We'll have Kelly follow up that. Paul, we drilled some wells there, we probably have a very small PUD de-booking in the Eagle Ford last year, but our overall reserves there were very positive. And the DD&A is that our plan – and wasn't planned to be reduced.

Keep in mind that on impairments we didn't have any in our onshore business and unconventionals and it's primarily been an issue in the offshore where 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 calls.

You've got to keep in mind we added 138 completed wells there last year (35:20) our CapEx, and if you're adding costs and reserves at the same pace, then the DD&A rate should be the same..

A final question, Roger. With the head count reduction and all that, based on your current organizational capability, if you are not adding people, how many rigs that you can actually run or handle, let's say, if the economic is available in U.S.

and Canada?.

We can easily go to three rigs, four rigs, Paul, I do not see that as an issue. We have capable drilling and completion people in both employed and 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 (36:18) people say nine times, in my career and always get back to work and we're organized to be able to do that and that's not a issue for me..

So, Roger, when you say three rigs to four rigs then – yes, three rigs to four rigs in U.S., three rigs to four rigs in Canada, right obviously (36:34)?.

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

Oh, North America, three rigs to four rigs, okay..

Between – between the Canada and the Eagle Ford together, four rigs to say, that won't be a problem..

Okay. Thank you..

That's not – I can handle that problem, Paul, whenever I get to that I believe..

Yes. Thank you..

Okay. Thank you..

And our next question will come from Guy Baber from Simmons..

Well, Guy, how are you doing?.

I'm doing good. Thank you guys for taking my question..

No problem..

Roger, I had a capital allocation question for you, but as you ramp down your capital spending, the dividend now has obviously become sizeable relative to your CapEx.

So, the question is, how you think about weighing the potential for incremental gross spending to help arrest declines (37:25) or allocate capital to attractive places like Montney and Kaybob Duvernay versus continuing to payout that same dividend at the same level? How do you think about the relative ranking of capital deployment between those two options right now?.

Well, I mean, a dividend policy at Murphy is a long term policy and oil price have been a short-term change. Oil price up even (37:50) $10 since the last time we had a call, that's well over $200-something-million of cash flow for Murphy.

Our dividend here is under closer review than it has been before, will be under meeting in August and really we're going to do that quarter-by-quarter. We paid two of the dividends at the full price here and we – it is – it's important for capital allocation than it is for other things and we continue to see well costs come down.

We're able to execute more wells with less costs. We're able to do this at both Montney and Eagle Ford. And I think we're still in such a recalibration mode of our cash flows with all of the ins and outs of our business.

That – 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 we kicking the can down the road to the fall time to be honest with you, Guy..

Okay, great. Thanks, Roger. And then the capital spending for the quarter, it look 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 from your rig activity. So it look like – the CapEx was lower than what we had anticipated.

Are you operating more efficiently and did the CapEx look like it could be coming in lower than what the internal plan has been, or anything you can share on that front?.

I would imagine today if we – one of our financial outlook looks that we produce here, Murphy would fund our (39:25) capital probably $30 million less than our $580 million today. And 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. We're almost times four equal.

And then we have – well, I a few minutes ago rattled off some wells in the Eagle Ford, we'll have wells in the Montney too. And then we have opportunities – or jackup rig in Malaysia (39:49) to another party and it will be coming back and we're installing a (39:53) and when CapEx gets to that level, small things can change it.

But I'm very pleased with the idea that we're not overspending or frontloading our CapEx, because our CapEx is a very real item that we're focused on here, and we're not frontloading it in with the idea that we're going to increase it.

We just got our CapEx set at these levels, happy with how it's going, happy with the efficiencies and cost reductions and continue on with that regime at this time..

Thanks. And then last one from 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? Or are 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?.

Well, I would say, we have some downtime events this quarter, as I went through in my remarks that doesn't lead to lower OpEx as you would imagine. We had a very, very good OpEx in $750 million range and we are trending to get back to where we were last year around a $9 range. But in our internal planning, we were $1 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 (41:37) 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 then, while I say that we may end up over at the end of the year with declining production, which we 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, reinforced through 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 are maintaining their market share or business.

So I continue to be positively surprised, I got a great team focused on and I think we're doing a great job there, and I'm real happy about it..

Thanks, Roger..

Thank you..

And our next question comes from Kyle Rhodes from RBC Capital Markets..

Good afternoon guys..

Good afternoon..

Just one from me. Any update you can provide on Block H FLNG program.

Does it – maybe in terms of expectations for first gas, and what's your future capital outlays are for that project in 2017 and 2018?.

Well, we're going to have over $100 million there, and probably some more into 2018. On the subsurface side, the field is incredibly successful for us, many successful wells in a row, great gas project there, very similar in rates to our SK gas. PETRONAS started this vessel.

They're supplying the floating LNG vessels in Korea, it is partially built and they're trying to slow that project down because these are tied to Brent prices, but work, this project works well and Brent's around $50.

They have come – and we have a gas agreement with them, they've come to us about pushing the first gas for that into 2020 and which they would have the expanse of changing the capital spend with the vessel in the Korean shipyard, if you will, and we are agreeable to that.

And then it would give us more capital for next year to use in our other high returning assets like Eagle Ford Shale or in Duvernay shale.

And so we push out that production to 2020 and that's fine with me at this time, it'd 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 say, less than a $100 million in 2017 spend, and then any idea kind of 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 the costs are low, because I anticipate deepwater rigs to be lower and it will or it may not be by 2019, but I imagine they will and our services there, we're in a great situation in cost, but our large partner there would like to push it to the right, and I'd like to save a $100 million right now.

And I'm very pleased with the adjustment when we get organized with PETRONAS..

Makes sense. Thanks, guys..

Thank you..

And our next question comes from Evan Calio from Morgan Stanley..

Hey. Good afternoon, guys..

Hello. Good..

Yeah. I 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? I mean is that just a return of for maintenance fees (45:15) mentioned?.

Yeah, that's right. I mean, 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, had enormous pile on of downtime this 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 which is basically flat.

So quarter two to quarter three would primarily be around just lack of investment in Eagle Ford Shale and after that it would be very flat, if we work more or not for that issue.

So I think it's a big downtime in the second quarter, but let's keep in mind that all along our external guidance was the same and we had a capital spend that was very low and we came into the year with many wells in the Eagle Ford Shale being completed in December, and now we're at that same guidance. So nothing has really changed on that regard..

Great.

And 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 into a recovery? And would that, would you expect that would drive running your business, free cash flow positive into an early portion of a recovery?.

The investment grade thing is a couple of months ago. We move on to all these assets ins and outs. We have – we've been fairly active in our company, change in our portfolio. We want – 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, just get back to investment grade.

Again, I think that the multiples of EBITDA and a layman (47:22) on debt to cap and working inside cash flow CapEx parity we continue to illustrate that, then we'll move back up the investment grade line again. We're 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 the 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 that is?.

Yes. That's correct..

Great. I appreciate it guys..

Thank you..

We'll take our next question from Sean Sneeden from Oppenheimer..

Okay. Go ahead, sir..

Sean, are you there?.

Sean, you may be on mute. We can take our next question from Brian Singer from Goldman Sachs..

Thank you. Good afternoon..

Good afternoon, Brian..

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, Brian. There're these rigs, it'd be harder (49:10) 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've been very happy with how our teams have performed as to that total focus on what wells are down, where they're down, and how you improve the artificial lift timing and that's been source of the success there in my view..

Thanks. And 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 just talk to what your natural oil decline rates are? And then anything that you can do either in terms of in a brownfield type, legacy type drilling here and there or just decline mitigations?.

We think of Malaysia as probably a less than 20% decline, it can be as low as 15%, all these projects are supported by water injection. And we are – very constant production of gas there on a boe basis, Brian, you'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. It only is up and down with LNG. So that moves fairly constant, also still cash flow providing field for us, a $360-type per Mcf.

And the rest of the field is Kakap-Gumusut, where we have 8% is a very, very successful field, limited decline in its own 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..

Thank you, Brian..

And our next question comes from Pavel Molchanov with Raymond James..

Thanks for taking the question. Just one from me.

Looking at the possibility that you would resume exploration in 2017 or subsequent to that, other than Vietnam which you just entered few month ago, what other geographies might you consider getting back into exploration?.

Well, at this time, we have a very nice acreage position in the Vulcan Basin, north of Australia, and we're trying to focus at a time (51:45) until the cost structure in the deepwater rigs of the Gulf get more organized, we're not focusing there right now.

Vulcan Basin, Australia is a very underexplored place, where we have a very large new seismic data set and we're on to a new play there with some 100 million barrel type opportunities and are very inexpensive to drill. That'd be one focus area. We have partner there in Mitsui, we're 60/40 with them.

We also, as you know, in the Great Australian Bight, we have the Ceduna Basin, where we have enormous acreage position with all of our seismic acquired and reprocessed. And we're sitting next to BP and Statoil and also Chevron who will be drilling upwards to six drill (52:30) wells for the next couple of years.

This is a prolific basin, the size of the North Sea, and one on the largest left on drill 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 of Vietnam as a place similar to Malaysia where we start with shallow water blocks.

We also have ultra-deepwater blocks and that entering that long-term relationship allowed us to enter into the Cuu Long basin, where we're 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 areas today. We're also interested in Mexico bid round because they will not have the higher cost issues placed on the Gulf of Mexico by this administration, I think that's positive. Also of note in the exploration world, today seismic is very inexpensive.

Massive seismic availability for inside our budget here, we're not looking to increase our budget in any way, especially in that, but can get lots of data today and build that positions again if needed in this low environment..

And you mentioned a lot of blocks, do any of them expire let's say by the end of 2017?.

No..

Okay. Very good. Thank you, guys..

Thank you..

And our next question comes from Sean Sneeden from Oppenheimer..

Yes, Sean. We missed you a while ago..

Sorry about that, that's a phone issue I'm facing..

No Problem..

But thank you for fitting me in..

I'm having a little trouble hearing you, Sean..

Sure..

Okay..

Just one quick one from me. Just thinking about the revolver maturity that's coming up, I guess in just over a year....

Right..

How are you guys thinking through that process.

Is the expectation that it's just going to be a simple kind of a message you send and it stays unsecured or could you kind of talk about how you're approaching that now that you have some of your asset sales in hand?.

I'll let John speak to it, but it is a blend and extend type of thing we would prefer, an option we'd 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 and oil price recovery, I think things are leading to a positive nature in that, in my view.

I've sensed a sentiment of improvement in that business over the last six weeks..

Right. There's a lot of more positive action going on in the marketplace, Sean, and we are – our goal is to extend. We're talking to our bankers about it, probably consider having to adjust our $2 billion somewhat in terms of the maximum size and we'd like to keep it unsecured, obviously. And so we're working toward that as well.

So we'll – it's all in the works, all being discussed and negotiations to proceed over time and that we're confident we can get the same extended at a reasonable size and a reasonable manner in terms of security and such..

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

Thank you..

And our next question will come from Arun Jayaram with JPMorgan..

Good afternoon. I wanted to ask you a little bit about the decision to suspend in a completion activity in the Eagle Ford. Broadly, at a higher level, you guys are shifting towards more of a North American unconventional focus.

So a little bit surprised given the quality of your Eagle Ford acreage in the core that you would suspend activity or at least the completion activity. I just wanted to – if you can help us think about that? And what oil price do you think you need, Roger, to where you think your U.S.

ultra business could deliver value to the throughput?.

Well, I mean, it's – all of our, are hopefully new to be signed Duvernay shale and our Eagle Ford can deliver 10% rates of return in the low 30s and we're ahead of that now.

We, at Murphy, set out earlier in the year and the price collapsed to organize our capital around lowest capital we could have, and then recalibrate our company because in and around that I knew of asset sales and different things we're doing.

We're not a company goes out same or selling all these assets and doing that, but we have a lot going on to accomplish all these purchase and sale agreement 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 have the closing and then we have a revolver to redo a recalibration of our company, a focus out of non-core in North America into unconventionals. All that takes time.

And 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're not a company to build that drilled on uncompleted 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's on been around since around mid-February. And I'm not interested in probably breaking it back up and hoping it back up the capital parade on May the 5th, whatever today is. So that's how we're thinking about that.

It was derived on purpose from a lowest commitment basis and we're focusing on cost and that and we will come out of this and we're confident of an oil price recovery.

Unlike any operator, we'll get 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're looking at it more conservative view of that at Murphy Oil Corp..

Okay, makes sense.

And just a follow up, any more details on the Kodiak well timing and then the magnitude of what do you think that could (58:51) in the Gulf of Mexico?.

That's a really good well. The key thing in the business is subsurface. You have to have subsurface. The well flowed, it has ability to flow at over 10,000 barrels a day from 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, a special order type equipment. We had to get involved with the operator and get that turnaround and fixed and 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 is a second half 2016 timing....

Oh no, we're talking about hopefully right now while we're talking..

Okay. Okay. Thanks a lot..

We're talking about right now, better be right now..

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

All right. Thank you..

. Our next question will come from John Herrlin from Societe Generale..

Yeah..

Hey, John..

Most of the things have been asked, but I was wondering about the unconventionals. Obviously, everybody's doing better with optimizations, more sand, more fluids, more intervals whatever.

Are you working at all with density pilots in your shale plays?.

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 unconventionals is continued improvement by everyone and if you look at all of these press releases, you will Murphy executing and performing at or above everybody else and it's not uncommon.

But I know that in my view with our big service providers looking to merge and now they're not going 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're missing – we could have some efficiency as you go to less pad drilling and some of it is on experimentation of capital that I think was driving a lot of unconventional improvement, which will lead to lower U.S. oil production and oil price recovery.

But the – if you have just a few wells and everyone is reducing their CapEx, not just Murphy, there will be less experimentation of capital, if you will, in my view..

Great. Thanks..

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

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