Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Third Quarter 2018 Earnings Conference Call. At this time, all lines are in a listen only mode. But following the presentations, we will conduct a question and answer session. This call is being recorded on Thursday, November 8, 2018. And now would like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications.
Please go ahead.
Good morning, everyone, and thank you for joining us on our Q3 earnings call today. With me are Roger Jenkins, President and Chief Officer and David Looney, Executive Vice President and Chief Financial Officer. Please refer to the informational slides we have placed on the Investor Relations section of our website as you follow along with our webcast today. 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 2017 Annual Report on Form 10 ks 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 Roger.
Thank you, Kelly. Good morning, everyone. I have a bit of a cough today, so bear with me. Thanks for listening in today. 2018 has been an excellent year both financially and operationally for Murphy.
Our excellent third quarter results illustrate our commitment to diversified portfolio as robust production from our oil weighted onshore and offshore plays continue to drive high margin realizations. Production in the 3rd quarter averaged 169,000 barrel equivalent per day at 58% liquids. Production exceeded the high end of guidance of over 1200 barrel equivalent per day. This beat was driven by outperformance in our Onshore Canada Tupper Montney and our Offshore Sarawak Malaysia assets.
In the
Q3, we generated $94,000,000.54 per share of earnings. Our disciplined capital allocation enabled us to return 12% of our operating cash flow our shareholders. We achieved an annualized EBITDA for capital employed of 21% and maintained our balance sheet strength with $2,000,000,000 of liquidity. In the quarter, we also paid our own way while building our cash position. In early October, following the announcement of our accretive Gulf of Mexico transaction, we received an upgrade from Fitch Ratings to BB plus We view this as a step in the right direction on our path back to investment grade.
Through the cycle, we've maintained unique ability to successfully execute deepwater projects offshore. We installed the Kike Gas Lift project in offshore Malaysia as well as the Dalmatian Subsea pump in the Gulf of Mexico. We also successfully drilled the Samurai II sidetrack well and after early analysis of well logs and core data, we now believe we have approximately 90,000,000 barrels equivalent of discovered resource. In our North American onshore business, we're able to show continuous improvement in cost reductions by achieving lease operating expenses just over $6 per barrel equivalent sold. We simultaneously delivered on our growth plans while spending within cash flow and growing our Kaybob Dubeney Shale by 2.5 times year over year.
Slide 4. Subsequent to quarter end, we announced an extremely accretive Boisland transaction in the Gulf of Mexico that we will immediately provide additional free cash flow. This is accomplished by forming a JV with Petrobras, where we will ultimately own 80% of the combined company's assets for consideration of $900,000,000 subject to closing adjustments. The full details of the transaction we found in our press release issued on October 10. The deal is expected to close by the end of the month.
We continue to successfully execute on our strategy. We have returned to offshore exploration with success at Samurai Project, our low cost innovative offshore projects in Malaysia and the Gulf of Mexico are now installed and beginning to see production uplifts. Our team delivered excellent operational performance in the Q3 where we see Kaybob continuing to exceed our expectations. During the Q3, our diversified portfolio delivered a weighted average price of over $69 per barrel of oil sold. No matter the price of oil, Murphy remains advantaged to our peers.
Slide 6. Over the course of 2018, we delivered strong EBITDA per BOE from 3 core areas. These areas received premium prices, which is the key to our high margin generation and account for 70% of our total production and 70% of our annual capital. We generated solid results and EBITDA from these assets ranging from $34 to $40 per barrel. Slide 7.
We're maintaining our full year CapEx at $1,180,000,000 with annual production being in the range of 168,500,000 to 1 170,005 barrels of oil equivalent per day. Both CapEx and production do not include adjustments for the recently announced joint venture. We intend to provide those updates upon closing. 4th quarter production is expected to be in the range of 167,000 to 169,000 barrels per day equivalent. The 4th quarter is being affected by a series of temporary one off events across many of our assets.
So we've accounted for those events in our production guidance. In the Gulf of Mexico production shut in October due to the impacts of an active tropical storm and hurricane season. In May, you had a series of mechanical issues in the field and some non operated onshore facilities at lower production levels. In offshore Canada, the scheduled turnaround to non operated Hibernia field was delayed and extended into the Q4. These issues have been rectified and production been restored to previous levels.
Additionally, recent flooding across most of our Eagle Ford Shale acreage has caused shut ins due to road damage at some of our facilities. At this time, I'll turn the call over to our CFO, David Looney, for a financial update.
Thank you, Roger. I'll be starting on Slide 8. Consolidated results in the Q3 of 2018 included net income of $96,000,000 or $0.55 per diluted share compared to a loss of $66,000,000 which is a loss of $0.38 per diluted share in the same quarter 1 year ago. Our adjusted income was a profit of $61,000,000 or $0.35 per diluted share in the Q3 of 2018 versus a loss of $6,000,000 in the comparable quarter last year. The adjusted income varies from our net income due to the following after tax items.
Number 1, an unrealized mark to market gain on crude oil derivative contracts of $21,000,000 2, proceeds from an Ecuador arbitration settlement of $21,000,000 The Ecuador arbitration settlement relates to a change in fiscal terms for a block previously owned by the company. Number 3, a prior period net income adjustment of $9,000,000 for the reconciliation associated with the unitization of the Gamusut Kokop field and Brunei working interest income. This settlement, which was signed in 2017, relates to the reconciliation of accounts amongst the Malaysia and Brunei parties. It is important to note that there was no change in the quarter to Murphy's working interest in the Gamusu to Kok Hop field. And finally, a loss on foreign exchange of $18,000,000 At September 30, Murphy's total debt amounted to $2,800,000,000 excluding capital leases or 38 percent of total capital, while net debt to total capital was 30%.
At the end of 3rd quarter, we had no outstanding borrowings under our $1,100,000,000 revolving credit facility and cash and equivalents were approaching $950,000,000 at quarter end. Moving to Slide 9. One of the hallmarks of Murphy over the years has been our disciplined approach to capital spending within our cash flow. As Slide 9 indicates, we're once again leading our peer group in this area as Murphy is currently one of only 2 companies in our 17 company peer group to generate free cash flow every quarter this year. Additionally, as the graph indicates, our free cash flow yield calculated by annualizing our 9 month free cash flow and dividing by our equity capitalization at ninethirty ranked us 1st in this metric among the peer group.
As you can see, while many others talk about free cash flow, we at Murphy are delivering. This is really nothing new for Murphy as we have always been focused on disciplined free cash flow generation and strong execution. We're not simply growing for growth sake, but rather with the goal of operating each of our assets as a free cash flow generating entity. At present, among our primary assets, only the Kaybob Duvernay is expected to be free cash flow negative for the year, which is not at all unusual for an early innings shale play such as this. By employing this approach at the individual asset level, we generate free cash flow as a company, which we then allocate in a shareholder friendly way.
This disciplined capital allocation approach leads to predictable consistent execution quarter in and quarter out. With that, I'll turn it over to Roger to review the company's operations.
Thank you, David. Let me start on Slide 11. Malaysia assets continue to be a reliable free cash flow generating business. Our Kikei DTU Gas Lift project is now complete. In the Q3, we achieved a milestone with the Kikei FPSO, completing over 600 liftings since we started production at that asset.
In Sarawak and South Axis, we completed an infield 3 well drilling campaign with the wells now in line. Sheryl White, we completed a 9 well gas recompletion project that allowed for continued gas livability up to 300,000,000 cubic feet per day gross. Our Block H Roton FLNG project remains on track with manufacturing completed for flexible flow lines and dynamic riser section. In Vietnam, our LDV development team continues to progress the field development plan and progressing approvals aiming to declare commerciality by year end. In the Gulf of Mexico, we commenced installation of the Dalmatian Subsea pump late in the quarter.
Early in Q4, the installation was completed and is currently delivering incremental production of 7,000 barrels a day equivalent gross with rates exceeding 11,000 barrels equivalent per day gross, this increase of 2 50% from prior quarter production. Also, this pump installation sets a record, its longest umbilical use in subsea pumps at over 22 miles. This again is example that sets Murphy apart, another industry first as we implemented a technology we believe we can use long term in the Gulf of Mexico, including our new joint venture fields. Slide 12 on Eagle Ford Shale. During the quarter, we brought 9 wells online in Eagle Ford, all in Catarina.
In the Q4, we plan on bringing additional 4 Catarina Aerie wells online. Eagle Ford Shale team continues to lower drilling costs while maintaining completion costs in spite of service cost inflation. We continue to see cost per foot improvements with 2018 year to date below last year. We continue to lower completion costs as our 2018 meter date is now approaching levels from 2015 with the backdrop of overall cost inflation and performance driven sand per foot increases during this timeframe. This is all from continued outstanding execution and procurement work.
For the 9 months ended September 30, this asset has generated $140,000,000 of free cash flow. Slide 13. The Tupper Montney continues to deliver reliable well performance and free cash flow with operating expenses below $0.60 this quarter, U. S. For the 9 months ended September 30, the assets generated $12,000,000 of free cash flow in this gas price environment.
We continue to mitigate our AECO spot exposure to hedges and off AECO sales with 40% of our tougher Montney natural gas exposed to daily spot. In the 3rd quarter, we realized CAD 2.25 per Mcf for our gas. Slide 14. An active quarter in the Kaybob Duvernay bringing 10 wells online. At this time, we feel that our appraisal plan is complete, with the exception of the Two Creeks area, which we're drilling and executing today.
During the Q4, we plan to bring 5 wells online, which brings our total 2018 wells online to 27. With this plan, we're on track to deliver 4th quarter exit rate of more than 11,000 barrels equivalent per day in this field. Slide 15. We continue to have strong well performance at Duvernay. Production increases 36% from 2nd quarter, exceeding 10,000 barrels equivalent per day with 61% liquids.
We continue to drill longer, faster and cheaper wells. We drilled our longest well lateral in the play exceeding 11,400 feet in the Kaybob West area. The fastest and least expensive wells drilled were in the Seminad area where we drilled the well in 18 days for $3,000,000 Our lease operating expenses continue to trend down, achieved an all time low of $7.29 per barrel equivalent in the quarter, which is outstanding considering we've only operated here for 2 years and delineating across all areas of our acreage. Murphy has only executed 36 new wells into play since becoming operator, proving again outstanding execution. On Slide 15, we're showing some of the results from the 4 well pads that we executed this year, clearly illustrating value creation as we move to full development mode with outstanding IP30 rates and cumulative production volumes.
17. I'm pleased with our early results and our new focused exploration strategy. Our Samurai-two well, where we were able to find contiguous sands that were hydrostatically connected to up dip pay zones. With the Samurai II sidetrack, we maintained an adjacent block in Green Canyon 476, but we have proven oil accumulations extending across 3 sands of the pay. As we analyze the well logs and core samples from the sidetrack, we feel confident in increasing the pre drill resource estimate from 75,000,000 barrels equivalent to over 90,000,000 barrels equivalent, while targeting cycle IRR of 30%.
We're currently working on development plans and look forward to bringing you more information on how Samurai success plays out in the New Year. Drilling the Kinkake prospect, Slide 18. Today in the Gulf of Mexico, we will spud the Murphy operated Kinkake well with a 31.5% working interest. The amplitude supported prospect is testing the same intervals as the gunpoint discovery nearby with primary objectives in the middle Miocene. Murphy's net well cost is expected to be around $25,000,000 The mean gross resource potential is 50,000,000 barrels equivalent with an upside potential of 100,000,000 barrels equivalent.
With this mean resource size, we again see full cycle breakeven of $40 per barrel or less and successful cycle IRR of over 30%. Look forward to updating you all on the King K well in our Q4 call next year. Slide 19. A quick update to 2 other important exploration wells. The Cholula prospect formerly known as the Cutting Cane well in Mexico received exploration plan approval from the regulators and we're now awaiting approval of the drilling plant.
We plan to spud this well now in early 2019. Vietnam expect to spud the LDT prospect in 15-105 in the Q1 of 2019 also. As you look back on 2018 and forward to 2019, we plan to drill our exploration wells in Mexico and Vietnam very early plus 2 additional wells in Gulf of Mexico. These exploration wells are exciting and allow for continued growth in oil reserves upon success. In our non operated offshore Brazil acreage in Sergipe, Alagoza basin, the 3 d seismic survey is completed.
We'll have the fast track data to work in our offices in the Q1 of 2019. We continue to add to our Gulf of Mexico exploration inventory with the recent award of the High Garden prospect in Green Canyon Block 852. In closing, we're delivering on our 2018 plan. I'm especially proud to be one of the few companies with free cash flow yield and returning significant cash to our shareholders. This is enhanced by our exciting new joint venture in the Gulf of Mexico that immediately delivers additional free cash flow.
And we have the unique ability to create upside for our shareholders with continued success in our exploration strategy. Plus, we're executing well in North America Onshore and our Global Offshore businesses. Finally, I'd like to, as usual, thank all of our dedicated employees who work diligently each day executing our strategy. I appreciate your time today and I will open up for calls at this time.
Thank you, sir.
Arun, good morning.
Good morning, Roger. I heard the word free cash flow mentioned a number of times in the commentary, which is encouraging, but post the Petrobras deal, in our model, we see over $800,000,000 of free cash flow generation for Murphy at a recent price deck. So I guess the question we have is, what are your thoughts on deploying that free cash flow, how to buybacks debt reduction, what is your thought process behind free cash flow in 2019?
Well, we want to use a portion of that cash flow and get CapEx into the Eagle Ford. You can tell in our call today, we still have pretty good results there. But delivering 4 wells a quarter just won't make it in an oil rich play like that that's low entry cost, working well and executing well. So I want to get a lot of CapEx into that next year and increase the CapEx for that, I would say, just to get the budget type things behind us here. We're going to release that in late January, which is not so far away from now.
We have a significant accretive cash flow providing business to get closed by then. I feel real good about that closing and about that change. And so our budget is going to be different from last year, but in a very positive way. We're going to be using low-60s, WTI, low-70s Brent. We're not focusing on growth, but we're going to have production growth.
We're going to have significant oil CAGR. We have probably a 50% increase in CapEx in the Eagle Ford alone. And we again will have free cash flow ahead of our dividend there. We're not putting all this free cash flow right back to work and focusing it really just on Eagle Ford Shale with the rest of our businesses being maintained and our exploration probably slightly less than this year. And those are the things we're working on.
And so it's not that we're putting all that capital to work. Our CapEx will be higher, production will be higher, oil CAGR will be higher, oil weighted production will be higher and our free cash flow yields can be higher. So it should be a very budget when we disclose it. We'd like to get this closed, go through our board and do that then. So it's a roundabout way of answering your question.
At this time, we're maintaining our dividend and having additional free cash flow yield. We have the option of paying back some of the draw on our revolver with that over the next couple of years as we see fit as oil prices behave and have a lot of optionality around that. But we're very proud about how our budget is going to look and how we're looking once we get this asset in our control here real standard brand.
All right. Two other quick ones for me. Regarding the Petrobras deal, I know it had a tenone effective date. Any estimate of how much cash that asset would generate between tenone and closing? And thoughts on maybe hedging the oil price just to reduce your overall volatility of that cash flow stream from the Petrobras deal?
It's probably $50,000,000 $60,000,000 a month kind of thing, Arun, something to that effect. Of course, you got to get to the final closing statement. This is a complex transaction involving a bunch of assets, but I feel pretty good about that number. And we're not hedged in 2019. We're using a low 60s WTI right now.
I'm still comfortable with that because I'm comfortable with the outcomes that I have in my budget as I just went through the high level budget discussion of our pillars for our budget. So we're not hedging that and we don't think we need to in our liquidity and our revolver situation, which is improving, doesn't require that in our mind. And we are hopeful that this oil price will return to more stable times after we get through everything that's been going on of late and not hedged today.
And just final question is you reported just in Q4 some kind of quarter specific items, weather, etcetera. Is there any knock on effect to some of the Q4 items that you highlighted in the press release towards 2019?
No, I wouldn't anticipate that at all.
Okay. Thanks a lot, Roger.
Thank you.
Thank you. Next question will be from Leo at Natalliance Securities. Please go ahead.
Hello, Leo. Good morning.
Hey, good morning here. Couple of questions for you guys here. On Kike, you guys obviously got that gas lift project working here. Just trying to get a sense of whether or not you actually see production uplift at KeyKay? Or is that more of a maintenance of production?
And if there is uplift, can you take a stab at quantifying that?
There is some uplift from it, probably in the $2,000 range. This is one of the sources of some mechanical issues we had. We're if we follow back on our prior calls, we were doing some an infield work over some subsea wells, and that's been flowing in. We've been doing a debottlenecking and lowering system pressure on the compressor on the platform, the main FPSO, all in and around trying to get our DTU to work. So I don't really have the uplift today because it's hurt by some water injection problems and some issues in shore with the gas plant where we sell gas.
So hasn't been a good time to get that kicked off, but it's performing very well and we're going to add, I believe, up to 5 more tubing strings between now and the end of the year. I'm anticipating kind of a 2,000 increase, but then overall maintenance type deal in the field that's produced now for 11 years.
Okay, that's helpful. And I guess, similar question around Dalmatian. You guys obviously talked about 7,000 beer per day of incremental production. Do you guys see that as sort of incremental flush production in the short term that might start declining lower than that 7,000? Or do you think that can be maintained for some periods?
How can you tell us about that?
I think it's going to be maintained for a while. This is a mechanical situation. There will be no evacuation of oil from the reservoir as we go through. We're looking in the budget today and our draft budget to drill another well out there because this is performing so exceptionally well. This is a pretty much a pressure drawdown of the long pipeline system to allow the wells to evacuate oil at a lower pressure.
It's working incredibly well. It's industry leading. It's an outstanding project executed here in our Houston office. And so I'm not seeing major decline coming out of that because it's a mechanical uplift is overriding that well into 2019.
Okay. That's helpful. And I guess you just mentioned potentially drilling another well there. I think in your prepared comments,
you talked about 2 wells in
the Gulf of Mexico in 2019. Would that be one of the wells?
That would be in addition to that. That would be a well from a reservoir we have in that field. It's not an exploration well.
Okay. So it'd be 2 exploration wells potentially in the budget in the Gulf for next year?
Plus the finishing off of the Mexico and the Vietnam well, correct.
Okay. And then at Samurai, any initial thoughts on development program there? I know you guys just finished doing some appraisal of the size, but any initial thoughts on that, Michael?
Well, we're very pleased with the outcome, very pleased with this is a very nice resource size to use in the tieback system. We have to work with our partner there. We just developed our pre AFE to study various development plans, probably looking at 3 or 4 well type of development with probably 6 or 7 different completions in the various reservoirs we've discovered. We outlined in early October a series of slides that shows how a development like that would work, probably 18 months from drilling a well next year. We may not have to drill the well.
We're in the middle of deciding that now and could just drill a development well later. So looking at drilling a well late 2019, flowing oil, 2 years from that point, 18 months to 2 years from that point. And these things are going to probably on a gross production basis kind of top out in a couple of years at 30,000 gross. We're fifty-fifty and declined from there. And it's a very nice asset with outstanding economics that can compete with any capital in the world.
All right. Thanks for the color.
Thank you. Appreciate it, Leah.
Thank you. And next question will be from Mohammed at Raymond James. Please go ahead.
Hey, thanks for taking the question. So if I'm reading this correctly, Eagle Ford production is going to be down pretty significantly next quarter. What exactly is the driver behind that?
Well, we had a pretty rough start and continued into this week. We've removed hundreds of yards of segments of roads going in some of our newer pads in the Catarina and Karnes area. With water, we had to get some actual boats there to go service and turn the wells. We're afraid to leave the wells where we can't attend to them as the road is washed out. So it's put a hurt on that, not so much on completions and drilling.
We happen to be in a drier area where we're doing that. And just a very limited well count And with delivering 9 wells in 1 quarter and 4 coming up in the next in a shale play, it doesn't take much to have the production decline. So again, our focus is to get our accretive business in the Gulf in order a tax advantaged business, take that free cash flow and up our capital gain to have more consistent non front end loaded Eagle Ford business that will not allow for those type of pullbacks, primarily is the issue.
Okay. And in Mexico, so
you have a prospect there next year. Is there any risk to the timetable given the new administration coming in December?
What was that again? In what area? Mexico? No, we've had meetings. We've had we're progressing well.
We had a milestone of the exploration program approved. There are some nearby peers that are gaining approval with theirs that are slightly ahead of us, and they've been able to do it. We're communicating with them. Our relationship with the government and the quality of the permit that we turned in has helped us. We have our outstanding team that's used to working internationally here at Murphy and the quality of our work and able to get in and our relationship with them.
And we feel that we're going to get the permit in December and drill our well.
Okay. Can you remind us of the pre drill estimate cost for that well and also the one in Vietnam? You guys have it in front
of you?
It should be here. Just one second. It's on the slide that we're using this morning. I was reading, I didn't Here we go. The well in the Gulf of Mexico will be $25,000,000 for Murphy.
The well in Mexico will be $15,000,000 and the Vietnam well will be around $20,000,000 And what else is your question on that, Mohan?
Pre drill estimates, if there are any?
The Kinkade well has a gross mean of $50,000,000 or 31%. The Mexico well is 200,000,000 barrels or 30%. The Vietnam well is 35,000,000 or 40,000,000, but it hasn't and all of these have enormous upsides ranging from 100,000,000 to 250,000,000 to 500,000,000 barrel improvements. These are very big upside opportunities for us and our company.
All right. Thank you. That's all for me.
Thank you. Talk to you soon.
Thank you. Next question will be from Luke at Energy Intelligence. Please go ahead.
Hi, thanks for taking my call. I was just wondering if among the exploration wells you're planning next year, if any of that involves further appraisal at Hoth Park. I know you guys just acquired full operatorship there from Chevron. Just wondering what your plans might be for that discovery going forward?
Yes. In our current budget draft, a well to be drilled at Hauppauk Park is included and we're very excited about it.
And you got any resource estimate for that?
It'll probably be around 100,000,000 barrel prospect at this time.
Thanks.
Dean. Did you have any further questions, sir?
That's it for
me. Thank you.
There are no further phone questions at this time. I would like to turn the call back over to Roger Jenkins for any closing remarks.
Appreciate people calling in today. And we'll if you have any further questions, contact our IR team and we'll get those lined up for you. I appreciate it and we'll talk to you soon. Thank you.
Thank you, sir. Ladies and gentlemen, this does conclude your conference call for today. Once again, thank you for attending. We now ask that you please disconnect your lines.