Barry Jeffery - VP Insurance, Security and Risk Roger Jenkins - CEO John Eckart - CFO.

Leo Mariani - RBC Guy Baber - Simmons & Company Ed Westlake - Credit Suisse Evan Calio - Morgan Stanley Roger Read - Wells Fargo Brian Singer - Goldman Sachs Ryan Todd - Deutsche Bank Paul Cheng - Barclays.

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation's second-quarter 2015 earnings call. Today's conference is being recorded. I would now like to turn the call over to Mr. Barry Jeffery, Vice President..

Good afternoon, everyone, and thank you for joining us on our call today. With me are Roger Jenkins, President and Chief Executive Officer; John Eckart, Executive Vice President and Chief Financial Officer; and Kelly Whitley, who has recently joined us as Vice President of Investor Relations and Communications.

Please refer to the informational slides we have placed on the Investor Relations section of our website as you follow along with our webcast today. Today's call will follow our usual format. John will begin by providing a review of second-quarter 2015 financial results.

Roger will then follow with an operational update, after which questions will be taken. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995.

As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2014 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..

Thank you, Barry, and good afternoon, everyone. The consolidated results of Murphy Oil Corporation in the second quarter of 2015 were a loss of $73.8 million, which equates to $0.42 per diluted share; and that compares to a profit of $129.4 million or a profit of $0.72 per diluted share a year ago.

Excluding discontinued operations in the United Kingdom, continuing operations had a loss of $89 million or $0.51 per diluted share in the second quarter of 2015, again compared to the second quarter of 2014 of a profit of $142.7 million or $0.79 per diluted share.

The second-quarter current year results from continuing operations included a $23.8 million charge for a recent 2% tax rate increase in Alberta. This change will increase future tax rates for operations in that Canadian province to a total of 12% tax beginning in 2016.

Additionally, we had after-tax severance and other charges of $7.5 million in the quarter. Since the beginning of 2015, we have had overall staffing reductions of about 7% associated with the Company reorganization plan. The savings from these staffing reductions will benefit us going forward.

The quarter also included a benefit of $19.3 million from post-closing settlements associated with our earlier combined sale of 30% of our interest in Malaysia. That sale occurred in late 2014 and early 2015.

These and other items affecting comparability of earnings between periods are listed in our schedule of adjusted earnings, which is included as part of our earnings release. Amounts in this schedule are reported on an after-tax basis.

Earnings in the 2015 second quarter were negatively impacted by significantly lower realized sales prices for crude oil, natural gas liquids, and natural gas, compared to the same quarter in 2014. The Company's average realized price for all of its crude oil production fell more than $37 per barrel, amounting to a 40% drop.

Natural gas prices also were weaker in the second-quarter 2015 compared to the prior year's quarter, with average North American gas price realizations dropping $1.61 per MCF or a decline of 40%. Net natural gas prices offshore Sarawak fell similarly.

Our oil-weighted diverse portfolio of assets benefits our Company, as 52% of our second-quarter production was sold off of Brent and LLS benchmarks, which continue to bring stronger prices compared to West Texas Intermediate based volumes.

Sales prices have further softened in July, and therefore revenues continue to be under pressure, as 2015 prices remain significantly below prices from a year ago. Crude oil and gas liquids production in the 2015 second quarter was lower than 2014 levels primarily due to the 30% sale of interest in Malaysia.

Taking the Malaysia sale into account, our liquids production in the 2015 second quarter actually increased 6% compared to a pro forma total for the prior year. Total oil and gas liquids production in the second quarter of 2015 was just over 131,000 barrels per day.

Natural gas volumes were 425 million cubic feet per day in the 2015 quarter, flat to 2014. However, again, factoring in the pro forma effects of the 30% sale in Malaysia, gas production actually increased 17% in the second-quarter 2015, primarily due to higher production from the Montney area in Western Canada.

Capital expenditures for continuing operations for the first six months of 2015 totaled $1.15 billion, which was a 34% decline from the comparable 2014 period. We continue to project our total 2015 capital expenditures at $2.3 billion.

At June 30, 2015, end of the second quarter, Murphy's long-term debt amounted to approximately $3.3 billion, 29% of total capital employed, while net debt amounted to just over 20% at the end of the second quarter.

In July we moved $150 million of funds from the UK following the sale of the UK downstream assets back to the United States, and these funds have been used to repay a portion of our outstanding debt early in the third quarter. That concludes my comments, and I will turn it now over to Roger..

Thank you, John. Before we get started in our operational review today, I want to welcome Kelly to Murphy in her new role overseeing IR and Communications. Kelly brings many years of experience to the position and we look forward to working with her. Barry has done a great job for us over the past five years in Investor Relations.

He will be moving to a new role and will lead three combined corporate functions as Vice President of Insurance, Security, and Risk. The combination of the three corporate functions was developed post the recent organizational efficiency study that John just mentioned.

As part of our reorganization, we have split exploration into two regional groups, each reporting to Gene Coleman, current EVP of our offshore business. We have restructured exploration to reduce focus areas, improve capital allocation, lower costs. Looking back at a pretty solid quarter for us, we have the following highlights.

Our Company remains in favorable financial position with balance sheet flexibility to take advantage of opportunities and carry out capital and corporate programs. We initiated a $250 million stock repurchase in May and completed in July, this past quarter, with just under 6 million shares retired or 3% of the Company.

This represents buying our own proved reserves at near $12 per BOE in this tranche. Since 2012 we repurchased a total of $1.375 billion of company stock or 12.4%. We continue to make progress on the portfolio, completing the sale of the UK downstream business.

The Malaysia selldown was timely hedged to falling oil prices, and we still have many levers remaining to reposition the Company going forward. We are currently reviewing the value of our midstream assets in Canada Montney, Eagle Ford Shale, and in the Gulf of Mexico. Operationally, we made a nice gas discovery in Permai well in Block H, Malaysia.

This 200-plus BCF resource will fit nicely with our floating LNG development plans going forward. In the Gulf of Mexico we achieved first production from the two-well Medusa subsea expansion ahead of schedule and on budget.

And in Kodiak we completed the first of two subsea wells ahead of schedule, with drilling results to plan, significantly de-risking the project returns. In shallow water Sarawak Malaysia we completed a five-well drilling campaign at the Belum gas field to plan and are now drilling at the Permas oilfield.

In our onshore business, the Eagle Ford Shale continued to perform well. We delivered 36 new wells online in the second quarter, and our recently completed wells in the Montney continue to deliver above-plan results.

As we look at our operating metrics, our global lease operating expense for quarter two 2015 excluding Syncrude is $10.90 per BOE, showing an improving of 9% from quarter two 2014 and 30% down from 2013. We are pleased with the overall effort the Company is making in cost reductions, and this effort will continue throughout the year.

The Eagle Ford Shale had a second-quarter operating expense near $10 per BOE and we expect to see further improvements in the second half of the year. We entered the price collapse last year and are currently in a good position relative to cash flow per barrel metrics.

While the price drop has hurt this metric, we have not had any significant impairments which has impacted many in the peer group. We recently finished drilling our first well with the sixth-generation rig Ocean Black Rhino in the Gulf of Mexico. We had strong operational execution on this well at 20% below budget.

The punch line for me here is improved returns are ahead in deepwater, especially in the drilling and completion of delineation wells we have planned and in major deepwater developments in the future. In Eagle Ford Shale we'll continue to lower costs and drive forward efficiency gains.

Our average well cost is now down by 21% from last year, and we're focused on getting that down to 25% overall by year-end. Second-quarter production averaged 201,952 barrel equivalents per day, exceeding our guidance of 197,000.

The near 5,000 barrel equivalence a day variance was primarily attributed to new well performance in the Eagle Ford Shale, rich startup of the Medusa subsea expansion project, and higher than forecasted heavy oil production from Seal. Looking ahead to third quarter, production guidance is estimated 200,000 barrel equivalents per day.

The decrease from second quarter is primarily attributed to lower Malaysia production, with the planned maintenance at the Kakap-Gumusut Main facility, risking of Sarawak and Kikeh gas volumes, and lower Canadian onshore production due to normal well decline, partially offset by higher Syncrude and Medusa subsea volumes for the quarter.

We've increased our full-year production guidance to a range of 200,000 to 208,000 barrel equivalents per day. As we reach the midpoint of the year we remain on track with our capital spend budget, some 34% below last year's level. With that significant reduction in capital, we're targeting production growth this year of around 2%.

The year-on-year growth is led by new well performance in the Eagle Ford Shale and Montney. In Western Canada our natural gas production from the Montney in second quarter was 192 million cubic feet per day.

Our new completion designs continue to deliver strong well performance with EURs now in the 8 to 10 BCF range, well ahead of the original Montney sanctions that called for 4 BCF per well. We have a refrac pilot underway on some of the older wells at Tupper.

We have an inventory of nine previously drilled wells and are currently completing five of them to maintain production rates and keep unit operating expenses low. At Seal we continue to progress our long-term commercial steam project.

Regulatory applications for central thermal project were submitted in quarter one this year, and we recently sanctioned FEED work for the project. We are seeing some positive results from primary production from multilateral horizontal wells and have running room in that area.

In the Eagle Ford Shale, second-quarter 2015 production was comprised of 90% liquids, averaging near 60,800 barrels equivalent per day. As planned, we continue to operate four rigs and two completions spreads, and the current plan is to stay at that level activity for the rest of the year.

We brought 36 new wells online in the second quarter and have brought on near 60% of our total estimated wells for the year in the first half. We are planning on delivering 36 wells in quarter three, 25 wells in quarter four, with the program being front-end-loaded as per guidance and plans.

Production in the third quarter of 2015 is estimated to be near 60,000 equivalents per day, with the 2015 full-year outlook not expected to exceed 59,000, some 2,000 barrel equivalents a day ahead of our annual production for 2014.

We continue to optimize our frac designs and are seeing strong results from recent superslick completions in the Karnes and Tilden areas. We have now begun a new trial of high-intensity completions with larger sand volumes and tighter stage spacing. Like any major oilfield we are always searching for additional productive zones.

We are assessing the potential of the Austin Chalk Play in our Eagle Ford Shale acreage. We have begun a three-well appraisal plan in the play, with the first well coming online in October.

Our current assessment shows a minimum of 70 Austin Chalk locations in the Karnes area with potential for additional locations depending on the results of this appraisal. Murphy is well positioned in the Eagle Ford Shale with our oil-weighted production mix compared to many peers.

Our limited exposure to lower NGL and natural gas prices gives us leverage in an oil price recovery. Murphy's well ramp-up strategy focuses on maximizing value by balancing early production rates with ultimate recovery. This strategy has led Murphy to have one of the highest levels of two-year recovery per well across the play.

The Eagle Ford Shale is a valuable asset within our portfolio. The value of Eagle Ford to Murphy is enhanced by our early ground-floor entry in the play. We have over 2,000 potential well locations remaining, and now estimate the total resource at near 750 million barrels equivalent, which is very similar to the entire reserve base of Murphy today.

Needless to say, the field is going very, very well for us. In Malaysia in the second quarter we completed a five-well drilling program for natural gas at the Belum Field in shallow water offshore Sarawak.

The Belum Field has low nitrogen content that will blend into our current gas production, allow us to derisk our 250 million per day contractual volume on demand going forward. We are currently drilling oil wells in the Permas shallow water development, and this operation is going well, with cost trending 20% under budget.

Sarawak gas production for the second quarter was 111 million cubic feet per day net, supported by strong gas nominations and liquid production at near 14,700 barrels of oil per day. We successfully completed the planned outage in early second quarter at our Sarawak facilities to complete required inspections and major maintenance.

Production in offshore Sabah averaged nearly 30,900 barrel equivalents per day for the second quarter, with 85% liquids. Planned maintenance activities at the Kakap-Gumusut main facility to install gas handling and injection system commenced on June 9 and have recently been completed.

Early this month we had a gas discovery at Permai exploration well on Block H, where we operate the well with 42% working interest -- our eighth consecutive success in the area around that field. This 200-plus BCF discovery will allow optimization of the floating LNG project and lower our development costs.

In the Gulf of Mexico, production for the quarter was over 22,900 barrels equivalents per day with 61% liquids. The Medusa two-well expansion achieved first oil in the second quarter, with the wells starting up late April and mid-June respectively. We exceeded our projected daily volumes and beat our scheduled targets.

Field development work at the non-operated Kodiak project continues, where the first two wells have been drilled and completed to plan, and modification of topside facilities and subsea executions underway.

The Sea Eagle prospect in Mississippi Canyon Block 692 failed to encounter commercial quantities of hydrocarbon and will be expensed as a dry hole. The well, which we operated with a 35% working interest, was not included in our second-quarter guidance as it was expected to reach total depth in the third quarter.

Our drilling operations team completed the well 30 days ahead of schedule and $25 million gross under budget. We have expanded into a new area in the Gulf of Mexico with our entry into the Wilcox play through a 20% working interest ground-floor farm-in into the non-operated Solomon prospect in Walker Ridge Block 225.

The well has a gross pre-drill estimate of over 300 million barrels. Looking at our drilling program for the rest of 2015 in the Gulf of Mexico, the Solomon well, which is currently projected to reach total depth sometime near the end of the third quarter or early fourth quarter, has been included in our dry hole exposure for the third quarter.

Black Rhino is moving to drill a lower-risk prospect at Dalmatian South Number 2. The Transocean Discoverer Deep Seas is expected to complete required inspections by the middle of August and is slated to sidetrack to Thunder Bird discovery, which will be a subsea tieback to our nearby Thunder Hawk facility.

Recognizing our lack of expiration success, we plan to focus rig commitments on our lower-risk appraisal wells in blocks where we have had prior exploration success. We will allocate capital to higher-return opportunities near existing infrastructure and not invest further in higher-risk, higher-cost wells at this time.

In Malaysia we will focus on our gas discovery at Permai in Deepwater Block H with two shallow water oil prospects, Merapuh 5 and Marakas in Block SK-314A, adjacent to our very successful Sarawak oil and gas developments. Later in the quarter we will drill the Paus East in Block SK 2C offshore Sarawak.

This well is near a prior discovery on the block and is located in our new focus areas. We plan to finish off the year with a non-operated appraisal of our gas discoveries in Brunei. Our firm well commitments through 2016 are primarily in Malaysia, Brunei, and Vietnam, which is one of our focus areas with lower-cost exploration.

Post-2016 we have only one required well commitment in the entire Company at an estimated net cost of only $4 million. We will have capital allocation options for exploration in 2016 and beyond as we have worked off commitments made in prior years. We, like all deepwater operators, have deepwater rig commitments.

The end of our rig commitments with the Black Rhino and Discoverer Deep Seas are expiring in February and November 2016, respectively. Production for the third quarter is estimated to be 200,000 equivalents per day. We've increased our full-year production guidance with a range of 200,000 to 208,000 barrel equivalents per day.

Capital expenditures remain unchanged from our previous guidance and are currently forecasted to be $2.3 billion in 2015. Murphy Oil has returned significant value to its shareholders over the last six years through regular dividends, a special dividend, the spinoff of Murphy USA, and share repurchases.

Our strong balance sheet supports the current regular dividend and allows the Company to carry out its capital programs and review opportunities. At current prices our dividend yield is near 4%, above industry peer average. Share repurchases since 2012 have acquired our own proved reserves below our F&D costs and competitive to other acquisitions.

While many companies are issuing equity or taking major impairments on their assets, Murphy through its conservative nature has been able to avoid significant write-downs in the business.

The takeaways today are our strong operational performance this year has allowed us to increase our production guidance for the year while staying within our capital spending budget. Our oil-weighted price advantaged portfolio provides us with cash flow per BOE benefit over many of our peers.

We're driving costs lower in our business through the cost reductions and efficiency improvements in both our offshore and onshore segments.

Our conservative balance sheet is a positive for us during the second price collapse in nine months, and allows Murphy to maintain a continued focus on our shareholders, carry out capital programs, and look for opportunities to improve our Company going forward. We will now take your questions. Thank you..

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

Just a longer-term question here on exploration. Obviously you guys are winding down some of the activity. It sounds like you will have some activity next year as well, and then minimal commitments.

Are you guys considering replacing that exploration component of the budget longer-term as we get out into 2017-2018 with acquisitions, or onshore leasing? Or how should we think about the strategy shift here?.

I think the results, Leo, as you know are not where we want to be. We got back into the Gulf here and had three unsuccessful wells in [indiscernible] leading us to take a pause there. We're not stopping exploration around the world.

We've taken a pause in the drilling till we can replenish that portfolio and make sure of these investments, make sure of the partners we're in and what type of wells. Where will costs go? I think drilling rig costs will come down, and a pause here is warranted.

It also, though, as you brought up, does allow us many capital allocation advantages, whether we would consider M&A in lieu of exploration. Would we consider a component of production and exploration from that company? I like to think of it as another price collapse coming, another budget year coming.

Not the success I needed, less commitments, very significantly low commitments in 2017, practically none. And I think it just gives an advantage to regroup and allows us capital allocation across the spectrum there..

Okay.

Could you elaborate a little bit more on acquisitions? Are you guys to looking at offshore Gulf of Mexico and onshore oily stuff?.

Yes, that would be fair. That would be fair. Probably not North of Oklahoma, and Gulf of Mexico is still a place. Our unique strategy of offshore and onshore allows us to look at both. We have the ability to operate in both, and we look at many opportunities. But we like to have a bit of return and strip pricing, Leo.

We are not interested in doing it for store..

Okay. I guess with respect to your comment about moving some of the deepwater drilling to lower-risk opportunities, you guys had talked about sidetrack, offset at Dalmatian, and also some work at Thunder Bird.

Are those just -- are those one-off well opportunities there? Is there more inventory behind that in the next few years?.

There's about three opportunities near Dalmatian that are like an F&D around $15 and have $40 to $50 breakeven full lifecycle 10% rate of return. I consider those very good.

It allows us to take a pause in the real expensive deep exploration wells for a while until those costs come down further; allows the regrouping of our partnering and our data and our total review of that business. I like these opportunities a lot. They are very accretive economically to us.

But we have seen a lot of success here with the Medusa subsea expansion. We're going to have a nice success at Kodiak from an entry we made into that project, and Dalmatian has been successful. So these have been around and we have allocated capital to some exploration.

Now we are reviewing that and putting our capital into these projects that fit in well with a low price environment in my view..

Okay. I guess you outlined your exploration commitment in 2016; we have got some obligation wells and your deepwater rigs are going to roll off I guess in February and November. You threw out the dollar number in 2017, $4 million.

Is there a dollar number for 2016 on exploration?.

It's on our slide in our deck today. I think it's a little over $100 million today for the wells that we need to drill with national oil companies. Some of these are very nice wells to drill in shallow water Sarawak Malaysia. There are some further commitment wells in Block H where we've been very, very successful.

There are some commitment wells further in Brunei, where we have had success. So I don't consider it a very high-risk program at this time. It gives us a lot of flexibility in our CapEx 2016 and enormous flexibility in 2017..

And our next question comes from Guy Baber with Simmons & Company..

Thanks for taking my question and good afternoon, everybody. Roger, you made an interesting comment that you see improved returns ahead in the deepwater.

I believe you'd mentioned before that you hadn't been seeing a lot of deflation offshore, so I was just hoping for an update on the deflation side and then some more detail behind your comments calling for better returns.

How much of that is due to self-help and Murphy getting more efficient? How much is due to what you are seeing on the macro side from a deflationary perspective? And then does that change the way you plan to allocate capital at all?.

Like I was saying, from a capital allocation exploration perspective we have these wells that were just asked about by Leo here, about some lower breakeven price wells that we can take a pause in exploration, which I think is nice especially when rig rates are high. I am a deepwater person. I've been in deepwater my whole career.

I understand the business fairly well. It's really a day’s business more than a vendor cost-reduction business, where the onshore there's a lot about vendor time and efficiency. But offshore is a day business. I wasn't a big believer in these big sixth-generation rigs. I thought they were too complex, too big, too much going on. I visited the one we had.

It's one of the best wells I've ever seen in my career. And if we get that kind of performance to reduce these days with all the subsea handling and the off-line work that these rigs can do, and you put that with lower day rates for these rigs, I'm absolutely certain that's going to lead to better returns.

That's going to fit in better with our pause in exploration and the kind of wells we can get into out in the 2017-2018 time frame after we have the appropriate recalibration of our work in that effort..

Okay, great. Very helpful. Then I had a couple CapEx questions.

But you all have done a great job in keeping the CapEx down obviously, and then with the lower pace of completions in the Eagle Ford over the back half of the year, I am just wanting to understand if there is perhaps downside to the existing capital spending guidance for this year, or if we're missing something and perhaps there are increases internationally or elsewhere that we are not fully appreciating.

Then as you think about 2016, understanding that it's early and that the macro environment is fluid, can you help us just understand the framework as we try to gauge our expectations for 2016 CapEx? Perhaps what the moving parts are, if there's anything going on internationally moving one way or the other, and how you are thinking about Eagle Ford and the four-rig program going into 2016..

complex and timely oriented to repatriate that money, but gives us optionality. We are allowed to maintain our dividend, lower CapEx, below this year, and survive at a $50 world without changing really almost the debt levels that Murphy has today. So happy about that, and I'm really not offering a lot more color than that at this time..

And our next question comes from Ed Westlake with Credit Suisse..

CapEx is a key issue for everyone as you go into next year, but I will wait for your update and we will see what prices do. You mentioned midstream assets, EBITDA for those, and how you would monetize it..

I don't have it -- I have it but I'm not talking about the EBITDA right now with you, Ed. I mean, it would be a similar multiple that you would see; but I've seen nice multiples in that business. And when you see nice multiples and things happening, Murphy -- if you see other people doing things with multiples we have it too here.

We have a very nice gas plant situation in Montney and great infrastructure there. It's a very high uptime, incredible asset. We also have many more facilities in the Eagle Ford Shale, and we are contacted from time to time for our spars and pipelines that we own in the Gulf of Mexico.

So those typical multiples you would see across other things would be similar to us. And we are intrigued by this and are reviewing it..

where do you reckon your acreage in the Montney now compete in terms of gas price? Breakevens..

It's still a tough business for us. It's an incredible operated facility and managed facility. We've doubled our sanctioned BCFs there per well. It's gone very well for us from that perspective, very disciplined. I guess AECO today is CAD2.40, CAD2.50 Canadian. That's that at our breakeven 10% return.

You get caught in a situation where if you do not drill some level of wells you're allowed the production goes down, and down impacts in OpEx. We do have some of our production sold, for lack of a better word, to others that use our facility.

That's the kind of economics we are in and that's why this sale of a midstream would add return on capital employed to a situation of that where you'd swap DD&A for OpEx commitment, if you will, and bring that EBITDA forward. Also though on a macro basis, we do still have LNG around the United States and exporting.

What will that do to the big gas picture? What will happen to the LN [indiscernible] off the West Coast there on both Canadian and U.S. sides? Then from a long-term macro perspective, when I first went to Malaysia in 1999 I was told we would never sell gas in the gas system to Petronas. And I think we sold them 304 million a day today there.

So this is a big LNG machine there that's being built. They don't have everything organized on it; but will that be an optionality for us one day? You never know, Ed..

Okay. Then a small question around the Eagle Ford. Obviously running four rigs you can see from your charts that you would build a bit of inventory towards year-end.

But what sort of -- if you ran level through next year, what kind of production do you think you would get from the Eagle Ford?.

We're just not ready to say. We originally thought we'd have to go to six rigs to maintain it. It's probably a little less than that now. Probably with the prices that they are we won't be able to do that. Some would say we should cut back some of our rigs now and protect CapEx there.

But I feel that a four-rig two-spread deal is really, really working well for us, and there's some level of size to be in the game to continue with the incredible efficiency. So that's where we are now and see how many of these inventory wells we drill, see what our options are.

I'm a little early in the game to say production Eagle Ford in August, Ed..

We’ll go next to Evan Calio with Morgan Stanley..

My first question, you guys decided to retain the second frac crew in the Eagle Ford.

Is that a function of a higher number of wells drilled due to drilling efficiencies and a desire not to build DUCs? Is that what drove that retention?.

No, our CapEx there has been a little over $800 million all year. Our efficiencies are growing very well. Just got off the phone here with Ed; we're just building up a little higher inventory than we normally keep, and that's even with the two frac spreads. So the drilling is growing really well for us there. We have different parts of the play.

Some drill faster than others, all of which are coming down below $5 million for D&C cost normalized across the field. Just maintaining our CapEx and having slightly higher production for the year, I think that's a good story. I think I have some worry about dropping things and losing the efficiency gains that I had.

And as I've said far back earlier in the questions here today, I think the offshore business is a day’s business, but they've been enormous savings from vendors in the onshore business.

So the cost for that equipment is cheaper of course than it was last year and the year before, and I just feel real comfortable with our team makeup and size and efficiency and the machine we've got rolling down there right now..

Great, that makes sense.

In the Eagle Ford, do you have any kind of breakdown on the economics on your 2,000 locations? Are they -- would you consider them economic on the strip? Or any kind of breakdown as you think about that?.

Going forward economics, you've got no trouble in today's prices in Eagle Ford Shale on anything we have because we're an oil player, not an NGL player at all, not a gas player or a condensate player there. So that's not the issue.

I think to get full on in income across all your G&A and your amortization of leases, etc., etc., it's in the above $55 level. We're not far away from there, but the costs are getting better.

We're starting to have some very high rates come out of some wells with these larger completions, even with our choking techniques that we have, which should lead to some higher EUR in some of the layers and lowering DD&A. And we have this Austin Chalk opportunity. So just kind of a macro thing, looking pretty good.

The main point is if you think everybody else is looking good, mine is looking good too..

That's right. That was just a question across all locations, if that was the case..

I'm not worried so much about that today..

Sounds good. Just one other question if I could. You guys completed the accelerated buyback in the quarter for $250 million; you've got more authorized; ample balance sheet.

Can you just talk about your decision-making process there for further buybacks as you look at the different opportunities you have as well as your funding?.

Well, we do have another $250 million available to us. It is sometimes nice in my mind to take some off the table at these low prices, especially when it gets down below some recent announced M&A; and we all know what those M&A deals are, in onshore especially, which are heavy P2-related and we're a heavy oil BOE outfit.

It is a nice thing to do occasionally, and it's one of the things we are considering as we maintain our CapEx this year and get into next year. Do we want to do that? And we do have an ample balance sheet to do it, you're absolutely correct, and it is something that is constantly reviewed with our Board here at Murphy and my executive team..

Yes. Maybe I could slip one more if I could. I know you guys recently had bid in the shallow round for Mexico with partner. Any color on how that process and opportunity played out? Are there any read-throughs as you think about an eventual deepwater round? Or is that related to your reduction comments on offshore before? I will leave it at that..

We are, like I said, taking a pause from the real deep subsalt Miocene expensive wells in the Gulf post what we have committed to right now. Of course this Solomon well we committed to took many, many months to negotiate with our partner there, which we are pleased with that outcome.

We were looking at shallow water Mexico and thought of it like a shallow water Malaysia play. It's very underexplored. Nice place to work. We're trying to focus back into Houston with lower G&A and less West Africa, less international farm. That of course is international being run out of Houston. We participated.

It was a situation there where you did various work programs and economic parts of the bid. As part of that, the government then didn't release their minimum government take after the bids are submitted and we were slightly below what they requested. So therefore our bid didn't work out, and it didn't work out. There are many bid rounds ahead there.

There's deepwater coming. I think it's a very underexplored nice place to work. If you are concentrating people and costs into the Gulf of Mexico, it would something out in time for well commitments for us, where we have virtually zero. So it wouldn't be a big issue to capital if oil prices were to stay down lower longer.

So I liked the timing of it, liked the underexplored nature of it, but it didn't work out that time. And we're going to review it going forward like we do other low-cost drilling opportunities internationally..

Understood, guys. Thanks for your comments..

And we’ll go next to Roger Read with Wells Fargo..

I guess I would like to ask you a little more on the acquisition front. Back about this time last year when the sale of the Malaysian assets was announced, expectation was a redeployment. And I recognize quite a lot of things have changed since this time last year.

You mentioned South of Oklahoma, but maybe you could talk a little bit about just how things are moving from a bid-ask spread standpoint with this double-dip move here in crude prices..

Well, I mean you're right. We have looked at a lot of opportunities here, and we look at three or four all the time in both offshore and onshore all the time here. So we have a big team working on this. We are very interested in it. We monitor it very closely.

And the way to think about Murphy in that world is we have a strip price rate of return minimum we would like, and we have a full price recovery rate of return we would like. If we can't get that strip price rate of return we like, then we are going to be unsuccessful. I think that early on just a timing issue.

We had a very nice hedging of oil for our shareholders at Murphy with the selldown in Malaysia, then we come into a collapse in prices accumulating last Thanksgiving. And then we never saw the bid-ask spread organized for us to participate at that time.

And here we are again with another collapse again or a lot of volatility, a lot of noise around mid-40s and things of that nature. Will that bid-ask spread be worked closer this time around? I would say yes, I hope so. But we're not interested in taking on this selldown in Malaysia and also our balance sheet, which is very strong.

We have a lot of ample room there to all of our peers. We're not interested in doing those unless we get the return we need, Roger, and that is where that is right now. But we are very active in the plays..

Thanks. I guess as a follow-up on that and Evan's question about the share repurchases, granted a large enough transaction you are probably willing to use equity as well as cash and debt.

But should we think about anything you do as putting more of the balance sheet in play and not putting equity to work at this point?.

I would hate to fence myself in on one way or another. We pride ourselves on being a Company that hasn't offered equity since our initial public offering in 1956. So not a big believer in that. I'd prefer not to do it that way. I think it matters a lot on who you are working with and on the other side of the transaction.

Are they private equity-backed and would like cash? Are they a shareholder of some type of merger; they maybe would like shares? What has happened to that as to debt or certain situations there in that onshore and both the offshore businesses. And I think each deal is different.

We'd hate to say you would never use it, but I would prefer not to, Roger..

And our next question comes from Brian Singer with Goldman Sachs..

Going back to the exploration just to summarize, do you view the exploration prospects as not where you want to be, the exploration strategy is not where you want to be, or both? I.e., is it just a matter of replenishing the prospect inventory, or is it bigger than that?.

We have to take a pause and replenish our portfolio into wells that are moving up. We have a detailed capital allocation process here where we rank every opportunity in the breakeven oil pricing, NPV-over-I, etc., risk NPV and net gain.

We need to take another look at all the technical work that we have done and all the prospects that we have and farm-in opportunities, our data sets, and take a pause in the Gulf of Mexico. Because today with the rigs that we have the wells are very expensive, and we haven't done well like we need to do. And we have to take a break in that business.

We at Murphy though have a very diverse portfolio and business. We have some very low-cost wells. This discovery in Block H Malaysia probably cost $15 million gross or something like that. You can drill $40 million deepwater wells in Malaysia where we've been very successful.

But the wells in the Gulf of Mexico are very expensive, and we are not having the results I would like. I think it's a replenishment, total relook at staff, processes, and data and where we are more than just where our prospects are, Brian..

Okay, thanks. Then on the Eagle Ford, as a percent of the total you have some of the most oilier Eagle Ford out there. One thing we have noticed is that the percent oil from a very, very high base has been coming down slightly.

Just wondered, particularly as the rig count falls, if you have any projections or what you are thinking about the oiliness, and if it goes back to the 80%, 82% range or if it keeps coming down..

Well, it's only because we are gathering and capturing more gas. We had a lot of gas flaring when we started as per emission standards in the State of Texas. We now have hardly any gas flaring across all that play with hundreds and hundreds of wells. It's so oily, Brian, that even you are going to have to start liking it..

That's great. One of the questions certainly is, does the gas rate in the mix start to go up over time? But your point is that you're not seeing it and you're not expecting it..

No, and Brian, we've got a long way to go to get some of your favorites..

Yes. Great, thank you..

And we’ll go next to Ryan Todd with Deutsche Bank..

Maybe a high-level one on strategy. You mentioned in the presentation that there are remaining levers or levers that remain on the portfolio adjustment. If you take a high look at your current portfolio, you have done a great job executing on the current assets.

But when you look at the portfolio in a moderate crude world, is that portfolio what it needs to be or what you want it to be? What levers outside of a potential acquisition is there? Or is there a larger restructuring or something that needs to take place to be competitive in a low to moderate crude price environment?.

Well, we're a Company that is doing okay in that environment. Our balance sheet and our oily nature, our cash flow per BOE is very good. A real misnomer about Murphy is our R-over-P collapses without exploration. That's not true. It's flat for a long, long time.

It's never going to be the leader, but it's very, very highly acceptable from a cash flow BOE basis. As you look at our onshore business for example you would find things that would be an outlier, primarily in Canada; and indeed we want to look at some of those assets. I've talked about some of that before publicly.

But when you have another price collapse and two in a few months, it's difficult. The bid-ask spread for selling is as difficult as the bid-ask spread for buying. So I think that we have to continue to execute and look at what we have and take on the opportunities when opportunities come with our balance sheet.

And we need to then do things post that to get the portfolio in a more concentrated pure-play basis I think would be best. But again, not interested in just doing that for the sake of doing it at this time and probably won't. So I guess that answers your question, Ryan..

Okay, that's helpful. Then maybe one more on the Eagle Ford. You guys have had great performance up to this point. You've been beating numbers.

Is the outperformance that we've seen up to this point, is it largely a function of additional completions? Is it better well performance, some combination of both? Maybe could you talk a little bit more in terms of potential for what you see in unimproved well performance and some of the potential for additional resource and stacked plays and stuff?.

Well, we're hitting on all cylinders there. We are very pleased with -- our EUR per wells is probably looking to increase in certain areas if we just get data on these new completions. Higher sand concentration completions are basically what they are, no matter what the fancy name is.

More sand concentrate is allowing us to open the well a little more aggressive than we have in the past, and we have a methodology around doing that with our folks there in Houston.

And to maintain the same type of reservoir performance with the larger sand concentration is allowing us to have for the first time some really name brand type of rate without having the well in massive decline as you can see from some of our peers. That's supported by this two-year production data advantage that Murphy carries forward.

So we are pleased with that. I think that is something that -- our new data on our new fracs are just coming in. We are obviously doing very well in the upper Eagle Ford situation there. We, like all players in that massive field, have data that shows upper wells going along with lower wells. We have all those slides. We have that too.

It's going well for us. Our Catarina areas are flatter longer than we originally thought; very cheap drilling out in that part. Very -- from a capital allocation just up there with Karnes. Totally different type of EUR shape, but very economic. So doing really well there, upper Eagle Ford, lower Eagle Ford, stacked on top of each other.

New completion design. Another new completion design coming. Really doing well down there, Ryan..

That's great.

Are you guys testing spacing at all? Or do you feel like you have down-spaced about as far as you potentially can at this point?.

No. When you are across a big play like us, you're an oil player like us, and you have various things to invest there, we haven't gotten below the 40s. We consider 40 pretty standard, and I think there's a lot of data around 40s.

We are in that type of development mode, and I guess you would say it's 20s if you have 40s on top of each other, and we have some of that going on; not a lot. But when we do, the wells produce as you anticipate, and we are pleased with those results. We don't have a negative pulldown of any kind going on in the Eagle Ford..

Our next question comes from Paul Cheng with Barclays..

Several quick questions. Sounds to me in your exploration program you are just taking a pause and you still believe the Company at the core is an international explorer.

Is that a fair characterization of the Company?.

That's fair, Paul. But I believe today that we will be continuing to focus now more in the Gulf of Mexico, East Coast Canada where we would have tax benefits from international exploration; a very big focus area between Sarawak and Sabah Malaysia all the way to Vietnam. Have a big office in KL and have advantage on G&A and cost of exploration.

I think you will consider a major pause in the real expensive wells in the Gulf as we recalibrate going forward and a continuing focus down, knowing more about less areas. And in the past I felt that we knew less about more areas, and we're getting totally away from that concept. So what you say, yes, but in a different way..

what is the right split on the capital allocation between the short-cycle and the long-cycle projects or assets? Roger, where do you stand on that? What are you thinking is the proper split for Murphy?.

Well, this year we have been about $2.3 billion CapEx, or $800 million, close to $900 million in Eagle Ford. And we had about $300 million for exploration, I suppose. The rest has to do with timing of various offshore projects in Malaysia and offshore Gulf. I would say it would be a step down from that, with less exploration next year.

And if we get in a $50 price where we have very limited exploration next year, because like I said we are taking a pause in that in some of the higher-cost areas. So I would say that split's about the same. We are a 50-50 onshore/offshore player. We do have continued development work in Malaysia in shallow water, where we have been very successful.

Our Eagle Ford is doing really well. I think it's a good story to have $800-million-plus CapEx there and maintain production there. So I don't have some big significant split out and things changing there, Paul..

In Eagle Ford just curious, Roger. You clearly have tremendous success in the efficiency gains and everything, and they're showing in the data.

Do you think that Murphy is alone or that it's way ahead of the industry trend? Or that you are seeing your peers also have that kind of success? Because it certainly makes a big difference in terms of what the resiliency of the US oil production may look like..

That is true. Sometimes I feel like we are part of the problem, we are so successful. I do see a flattening in US onshore production the last couple of months, which I think is positive for the long-term situation there. I know that when we cut back our completed wells we do see a decline. It is strictly from that.

It's not to do with our well performance. So if the oil price continues here and people do have that, I see how it impacts Murphy. And we are very, very proud of our acreage, very happy with the results. It will cause less production even though there has been efficiency. I think that we are a top-quartile player in onshore.

I think it shows that we have built this team from scratch and can deliver. We are a very operationally focused Company and very proud of that. I am an operation-focused person. We have been successful in that play, and I think we are as good as anyone in that play.

I think the misnomer because we are not just an onshore player that we are not a very good executor in the onshore, Paul..

Okay, final question. Based on the comments -- two final questions.

One, can you share with us how much is the capital you invest in the infrastructure in Eagle Ford?.

I don't have that number off the top of my head right now, Paul, to be honest with you..

Is that something that you would be willing to share or maybe have Kelli to give me a -- send me an email? I know you are not ready to talk about EBITDA, that kind of things, but want to see if [multiple speakers]..

No, I'm not against getting that number for you, and you can get it from her this afternoon..

Okay. Second one is that for 2016 I know it's too early for you to coming up with a CapEx number and production. But [multiple speakers]..

Why do you ask, Paul?.

No, no, just trying to understand the concept that based on what you say is that you're trying to keep it to the 2016 this cash hold neutrality, whatever is the oil price, is that the overall concept?.

I'm not going to get too much further than 2016. I will tell you and just be straightforward with you, it’s difficult for us to be cash flow/CapEx parity in a $50 world. That level of shortfall is probably not as significant as you think.

We would make enormous cuts to our budget, do so, and I've already said we are taking a pause in an expensive part of the world.

So as I said earlier, we today from a macro, high level haven't been -- it certainly hasn't been agreed with our Board -- we can keep our debt levels about within our revolver and have flexibility as to repatriation of a lot of cash we have abroad, Paul.

I think that is a pretty good situation if this thing goes $50 for the rest of the year and all of next year..

Okay, perfect. Thank you..

In the interest of time, this concludes our Q&A session. I would now like to turn the call over to Roger Jenkins for closing remarks.

Thanks, everyone, for calling in today and participating on our call. We look forward to talking to you in the fall when it's a little bit cooler. I thank everyone, and Kelli will be taking calls going forward. Again I want to thank Barry personally for all he has done for me.

It's not easy working with me on this, so I appreciate it and thank everyone and will speak to you next time..

This concludes today's call. Have a wonderful day..