Kelly L. Whitley - Murphy Oil Corp. John W. Eckart - Murphy Oil Corp. Roger W. Jenkins - Murphy Oil Corp..

Arun Jayaram - JPMorgan Securities LLC Ben Wyatt - Stephens, Inc. Paul Cheng - Barclays Capital, Inc. Muhammed Ghulam - Raymond James & Associates, Inc..

Good day and welcome to the Murphy Oil Corporation's Second Quarter 2017 Earnings Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Kelly Whitley, Vice President, Investor Relations & Communications. Please go ahead..

Good morning, Andrew. Good morning, everyone, and thank you for joining our call today. With me are Roger Jenkins, President and Chief Executive Officer; and John Eckart, Executive Vice President and Chief Financial Officer.

Please refer to the informational slides that we have placed on the Investor Relations section of our website as you follow along with our webcast today.

John will begin the call by providing a review of the second quarter financial results highlighting our balance sheet and strong liquidity position, followed by Roger with second quarter highlights and operational update, of which questions will be asked afterwards.

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 2016 annual report on Form 10-K on file with the SEC. Murphy takes no duty to publically update or revise any forward-looking statements. I will now turn the call over to John for his comments..

Thank you, Kelly, and good day to everyone. Murphy Oil's consolidated results in the second quarter of 2017 were a loss of $17.6 million, $0.10 per diluted share. That compares to net income of $2.9 million, $0.02 per diluted share, in the same quarter a year ago.

Excluding discontinued operations, our continuing operations had a loss in the second quarter of 2017 of $17.4 million, also $0.10 per diluted share. Our adjusted loss, which adjust our GAAP numbers for various items that affect comparability of results between periods, was a loss of $19.1 million, $0.11 per share, in the second quarter of 2017.

Our schedule of adjusted loss is included as part of our earnings release and the amounts in this schedule are recorded on an after tax basis. Our balance sheet continues to show low leverage with ample liquidity and manageable debt maturities.

At June 30, 2017, our total debt was $2.9 billion, or 37% of total capital employed, while net debt was 27% of capital employed and amounted to $1.83 billion. At the end of the second quarter, we had no outstanding borrowings under our $1.1 billion revolving credit facility, and cash and invested cash balances totaled $1.1 billion at quarter end.

Following the December 2017 bond maturity of $550 million, Murphy does not have further debt maturities until 2022. Our oil and natural gas revenue for the quarter totaled $509 million. That's a 24% increase from the same quarter in 2016.

In order to underpin our cash flow, we hedge a portion of our oil and forward sell a part of our natural gas production. At the end of the quarter, we had 22,000 barrels per day of oil hedged at $50.41 per barrel WTI for the second half of 2017.

On the natural gas side, we had 124 million cubic feet per day forward sold at AECO at CAD 2.97 per MCF for the balance of this year, and as well we had 59 million cubic feet per day at AECO at CAD 2.81 per MCF for 2018 through 2020.

We have also contracts for 20 million cubic feet per day at Chicago City Gate priced at $3.51 per MCF for the period from November 2017 to March of 2018. That concludes my comments. And I will now – Roger will now present a review of the company's operations..

Thank you, John. Good morning, everybody, and thanks for listening to our call today. In second quarter we produced 163,000 barrel equivalent per day comprised of balanced mix between onshore and offshore production, with our onshore business producing 51% liquids and our offshore business producing 71% liquids.

For the quarter, the company invested $201 million in capital projects, in line with our 2017 capital budget of $890 million. A conservative balance sheet management, ample liquidity, and cash on hand will continue to build positive financial momentum as we progress through the year.

Our diverse asset base provides a competitive margin, near $18 EBITDA per BOE for the second quarter. We're continuing to maintain our top quartile dividend yield in this challenging commodity price environment, while paying our way and living within our cash flow. Operationally, we're successfully accomplishing all of our 2017 goals.

We're progressing our Kaybob Duvernay appraisal plan, and we're pleased with our above plan early results. In Eagle Ford Shale play we continue to cost effectively capture additional resource for using our Cube multibench completion design.

And our Tupper Montney asset, we're committed to bring forward value by accelerating long-term growth through additional takeaway commitments. In our offshore assets we continue to execute on highly economic, production optimization projects, and enhance our exploration portfolio.

In Malaysia, we're achieving stable, high margin production implementing innovative projects, such as surface jet pumps and Dry Tree Unit gas lift subsea equipment. In Vietnam, we drilled a discovery well in the Nam Con Son Basin.

In the Gulf of Mexico, we continue to progress evaluation of our Mexico Deepwater Block 5, which is near a recently announced major discovery. I'll now look at the second quarter in more detail. Production in the third quarter is expected to be in the range of 156,000 to 158,000 equivalents per day.

Third quarter production guidance is below our second quarter actuals due to pre-planned downtime work at our Sarawak oil and gas fields and our non-operated Terra Nova field in Eastern Canada, as well as the loss of the non-operated Kodiak well in the Gulf of Mexico, which is awaiting repair work.

There's also planned downtime at Keyera processing plant in Kaybob Duvernay. These temporary production outages are approximately 10,000 barrel equivalents per day are partially offset by new wells we're planning to bring on in our North American Onshore business and better performance in offshore totaling approximately 4,000 equivalents per day.

The annual 2017 capital budget is being maintained at $890 million.

The full-year 2017 production guidance is being tightened to 163,000 to 167,000 equivalents per day, with North American Onshore production expected to increase by over 15% from fourth quarter 2016 to fourth quarter 2017 as a result of continued ramp-up of activity in our onshore unconventional business as we progress through the year.

Our teams continue to be focused on creating substantial cost efficiencies that have and will continue to lead toward lower operating expenses, and data analytics is one of the tools that helps us do that. Our use of data management is one of the reasons we see the lowest level of quarterly operating expenses per BOE in over a decade.

In our offshore operations, we have (07:59) platforms in Sarawak which utilize high frequency data capture, curation, and visualization. This enables remote natural gas platform operation from an offshore central facility, which minimizes operating complexity, manning requirements, and costs.

The use of data analytics allow value decisions to be made regarding procurement quality, specifications, volumes, and chemical management. In our Eagle Ford Shale business, we've established a 24-hour remote operating center in Houston. We've had this center for some time that enables us to monitor every well and facility in real time.

It moves the data-driven pipeline management systems, which utilizes data and dashboard, incorporate real-time information that enables intelligent decision-making and specific key performance indicators for monitoring of pipeline operations.

Optimizing activities based on database analytics has aided in lowering OpEx at Eagle Ford Shale over 15% from past year. We've also reduced downtime by 50% over the 18 months using this 24-hour data operating center.

Now, offshore business, it produced 77,000 equivalents in the second quarter with 71% liquids, and our offshore Malaysia business, Block K and Sarawak, produced over 34,000 barrels equivalents per day during the quarter, with natural gas production from Sarawak averaging 113 million per day.

Our Malaysia assets are very steady cash flow-generating business and we continue to make great strides in lowering operating expenses in that region. The Malaysia business delivered almost $112 million of free cash flow this quarter.

In the Gulf of Mexico and East Coast Canada, production for the second quarter averaged over 22,000 equivalents per day with 91% liquids. Our Kodiak field has been shut-in since early June due to an issue with the downhaul tubing string component and we expect it to come back online prior to year-end.

In Vietnam, we drilled an oil discovery at the CT-1X well in Block 11-2, and we're evaluating this discovery with our partner. (10:01) discovery, the second exploration well in the block was delayed in order to plan for a location to further test the interval discovered in the CT-1X well.

The second well in the plan, named CM-1X, will be drilled later in this quarter. In Cuu Long Basin, we are working with our operator on Block 15-1 LDV discovery for sanction next year, as well as planning an additional exploration well.

During the second quarter, we signed an application for 35% working interest in the adjacent 15-2 block as operator, where we will ultimately target a feature similar to our successful LDV project in adjoining block. In Australia, we're positioned in two promising exploration areas, the Ceduna and Vulcan basins.

We view our Ceduna acreage as having significant exploration recoverable resource potential with five Tier 1 leads of over 300 million barrels equivalent indentified and 50 leads overall. We have no remaining commitments on our block.

We are pleased to see the nearby leaseholders reorganize their well commitments to facilitate drilling in this exciting untested basin. In the Vulcan Basin, we're maturing multiple leads in the Murphy-developed Jurassic Play Fairway. We believe that this shallow-water high-margin prospects hold up to 200 million barrels equivalent on each location.

In the Deepwater of Mexico Block 5, we continue to progress through the drilling approval process, the plans to spud our first exploration well in late 2018 and early 2019. We'll continue to mature multiple leads and we've seen prospectivity of up to 1 billion barrels of equivalent oil potential on our block.

We're particularly encouraged by the shallow water Zama discovery recently announced by Talos, Premier, Sierra. This discovery well is located approximately 15 miles south of our Deepwater Block 5 with prospective Miocene section in Zama mapped on to our block.

These are examples of high impact exploration opportunities allow us to take advantage of our considerable in-house offshore expertise. We believe in maintaining global exploration and replenishing our portfolio as we are now an exploration sweet spot at the bottom of this extended cycle.

In Eagle Ford Shale, second quarter production averaged near 46,000 equivalents per day at 87% liquids. There were 19 new wells brought online, of which two in Austin Chalk, one in Upper Eagle Ford Shale, and 16 in Lower Eagle Ford Shale, primarily in our Tilden area.

During the second quarter, we completed 11 wells using new slick water completion style with tighter cluster spacing, higher concentrations of finer mesh sand, we call it Generation 5.0. Of these 11 wells, 8 outperformed their pre-drill IP30 estimates by over 30%.

As a result of these positive outcome, we will continue to use this completion style more widely across the field, which should lead to additional resource recovery over the long-term. In the third quarter, we plan to bring 24 Eagle Ford Shale wells online, of which 14 in our Karnes and 10 in our Catarina area.

These additional wells are in our core areas and will drive production increases to year-end. We continue to operate the Eagle Ford Shale very efficiently with improving operating costs and continuation of drilling pacesetter wells in the play. Stacked pay potential exists across majority of our Eagle Ford acreage.

We're progressing our new development optimization program called Cube design with a four- to five-well pad layout. Each well that's drilled would target either Lower Eagle Ford, Upper Eagle Ford, or Austin Chalk. We expect to gain efficiencies employing this Cube design by minimizing our offset frac heads and enabling us to accelerate production.

For example, in Karnes, we implemented the Cube-style development in four different pads in the second quarter, and they would successfully test down spacing of our Lower Eagle Ford well to 250 feet. For the second half of this year, we will further test down spacing, now focusing in the Catarina area.

We continue to be pleased with our Austin Chalk execution for two new wells we brought online in the quarter. One well is drilling in the conventional landing zone, while the other was drilled in a higher landing zone.

The well that was drilled in the higher zone outperformed pre-drill estimates by over 45% as compared to the other well that utilized the conventional landing zone and performed in line with pre-drill expectations, signing three additional Austin Chalk wells over the rest of the year.

In Canada, our Tupper Montney asset produced 204 million a day for the second quarter. Early in the quarter, we bought five wells online, three in Upper Montney, two in Middle. All the wells are exceeding expectations, with projected ultimate produce recoveries on trend to be an 18 Bcf per well-type curve.

Our new 10,000-foot lateral high sand concentration wells continue to validate outstanding subsurface performance in our multibench Montney asset. Our development plan has been to drill to fuel strategy that will allow growth with additional available processing capacity of 80 million a day by late 2019.

Murphy's taking the first step in bringing forward additional value in our Montney asset by committing to a long-term volume expansion of TransCanada for an additional 200 million capacity we expect to be available in late 2020.

Implement this expansion, we executed a FEED contract with Enbridge for additional processing capacity, planning for the project to be sanctioned in the first quarter of 2018. The project will have full cycle returns upward of 30%, bring values forward in this low cost, long-life asset with solid subsurface deliverability (15:44).

A full cycle breakeven economics remain below CAD 2 per MCF AECO with current royalties of approximately 3% to 5%. On our Kaybob Duvernay asset, production for the quarter averaged over 3,500 equivalents, which is an increase of 24% from the previous quarter with 58% liquids. We brought two new wells online at the 04-32 pad in the oil window.

They are significantly outperforming pre-drill expectations. We also brought three new wells online early in the third quarter at the 11-18 pad. These wells are on the boundary of the oil and condensate window. These five wells are the first wells drilled and completed employing Murphy well design at this time.

As part of our ongoing dynamic field appraisal, each of these five wells was completed with different completion designs and flowback parameters in order to help us determine the best forward path for our play development. We are pleased with our progress in delineating and appraising the play.

Similar to the Montney, we also have lower royalties in the Duvernay, which are now near 5%. The low royalty with low cost entry will allow for very low full cycle royalty economics. The 04-32 two well pad in the oil window was brought online in the second quarter.

The 04-32C well was drilled with a lateral length of over 7,400 feet, and it's been treated with slick water frac at 3,000 pounds per foot sand concentration. The well is significantly outperforming its type curve with a peak rate of 2,000 barrel equivalents per day and an IP30 of approximately 1,800 equivalents per day with 75% liquids.

In the view of current public data, the well appears to be the best well in this region. 04-32D was drilled with a lateral length of over 8,000 feet was completed with gel frac at 2,000 pounds per foot sand concentration. This well is also outperforming its type curve with an IP30 of over 800 barrel equivalents with 75% liquids.

The 05-29 pad also continues to flow on trend with its pre-drill type curve 665 equivalents with 70% liquids. This well was stimulated with only 1,000 pounds per foot of sand in the gel and slick water treatment, with much larger cluster and stage spacings compared to our current well plan. This well was (18:03) to plan for over four months.

This year we'll drill 16 wells and complete 10 in the Duvernay. As we progress through our 2017 plan, we've shifted our well sequencing. We expect to bring the wells online in Kaybob West and then drill wells closer to existing infrastructure and processing capacity at Simonette and Saxon. We're progressing our 2017 plan.

I remain pleased with our execution. We're executing our top quartile EBITDA per BOE metrics, which is a benefit of our diverse asset base. With conservative balance sheet management and ample liquidity, we're building positive financial momentum.

Our onshore assets continue to outperform as we employ higher sand concentration fracs to longer lateral wells. We're progressing our Kaybob Duvernay appraisal plan and we are encouraged by the strong early results. In our offshore assets, we continue to execute on high economic production optimization projects and enhance our exploration portfolio.

We remain focused on evaluating both onshore and offshore opportunities as we position the company to grow long term. This concludes our remarks today. I'd like to open up the phones line now for your questions. Thank you..

Thank you. Our first question comes from Arun Jayaram with JPMorgan. Please go ahead..

Good morning, Arun..

Good morning, Roger. I was wondering if you could either help us think about your – initial read of your Duvernay results. Looks like some of the wells are outperforming your type curves. I just wanted to – maybe if you could give us some baseline on where D&C costs are today.

What kind of EURs do you need to see that – where is your hurdle away kind of EUR and what do you think these most recent – or your early completions are tracking towards in terms of EUR basis? Pardon me..

Thanks, Arun, for that question. This year we've drilled these wells, we've been very successful at understanding and managing and drilling very long lateral wells.

As a matter of fact, this week we just drilled a well almost over 9,000 feet for around US$2.5 million, so we're very successful at consistently drilling the wells below $3 million the longest laterals ever drilled up in that region.

Unfortunately, on some of our wells we've had a problem with casing failure that had to be repaired, and some of our wells had to do with some corrosion, some pipes stored inappropriately. That has caused us some setbacks in the timing of the completion.

And those costs when neutralized out, which are one-off current, as we put these costs of these wells, they're around $10 million. We've yet to have – we've pad drilled three wells together, but the completions are all extremely different. So yet to set a water management infrastructure.

We've yet to go to full pad drilling and get into a motion of manufacturing, if you will. And we feel very confident about over time lowering these costs by 30% to 40%, which we've done in all of our plays, Montney and Eagle Ford, where we've drilled thousands of wells. And we see that getting into the – our goal of $6.5 million.

We see that fully in range. I see the drilling greatly improving of late, like I said with actual data. And that's going to lead to some really nice full cycle, again, economics here, breakeven process is around $40, and this is probably due to our low cost entry, low royalty, and moving to pad development. The EURs will be various across the play.

We've proved up pretty solid to around 900 EURs in some of the volatile oil condensate regions. We're working around 600,000 EURs in our more northern part of Kaybob West. We're consistently seeing this perform – saw this 05-29 perform with a very low frac volume for a long time.

And if you look at our EURs in the Eagle Ford, this is similar that are larger than that, but the royalty is much, much less. So this is a value creating thing, low-entry, old Murphy strategy at work and the work we do, and very pleased with what we're doing..

Great. That's helpful.

My second question, Roger, is as you have now secured some midstream or takeaway in the Montney, could you talk about capital allocation to that place and where you're kind of moving capital as the Montney looks like it's going to take an increasing part of the pie on a go-forward basis?.

All of our capital plans for the last couple of years have included our drill-to-fill strategy. We have some peers that flow to some of our facilities today, both the Tupper Main and Tupper West. These two strong gas peers have – will be pulling off some of their capacity between now and late 2019.

So we're going to be replacing that and that's always been planned. The new bring-forward values to actually add on top of that original plan another $200 million a day into a situation we could continue to add $200 million increments if we choose to do so.

The cash flow from this asset with an infusion of around $100 million above the cash flow of the asset only will allow us to get to this new $200 million and can expand from then on with the cash flow provided by the asset.

And this very low AECO breakeven price with that ability of free cash to build is going to be very much accretive for us to bring forward this cash now..

Great. Thanks a lot, Roger..

Thank you..

And our next question comes from Ben Wyatt with Stephens. Please, go ahead..

Good morning, Ben..

Hey. Good morning, guys. Hey, Roger, I'll hop over to the Eagle Ford if we can..

Sure..

You guys had some commentary on the new completion design over there. Just curious if that was all tested in Tilden or if you were able to go to other assets within Eagle Ford and try that. Just trying to get a sense of how confident you are in this completion design, how affordable it is to the other Eagle Ford assets..

We see it to be real affordable. For the quarter – I'll get my sheet here. For quarter two, in quarter – let me see, I have a wrong page here. The quarter two wells we delivered. Let me just go ahead and answer your question, I'm fairly confident of the answer. It's very affordable and can be moved between Tilden and Eagle Ford Karnes pretty easily.

I'd say the wells are around – 50/50 around where we experimented both in Tilden and Karnes area, and made both of them very helpful..

Got it. Good stuff. And then maybe just now thinking kind of on the offshore international, you guys are clearly excited about that. It seems like costs are really coming down and are competitive now.

Just curious if you guys could – if we think out to maybe next year, maybe how the budget looks, how that capital is allocated maybe as a percentage of the total budget, like I said, as we think about 2018..

I would imagine exploration spending for drilling wells be like 7% to 10% of the budget, because that similar cost today, the 30% to 40% of the budget. So it's very inexpensive to participate in these opportunities. We've completely changed our exploration team over the last several years, total different strategy.

We're bidding in places that have lot of competition with lot of success. Our partner in our block is the same partner with a major successful block in Mexico. We're going to drill two to three wells next year, for sure, and targeting to drill in Mexico in late year. We're working through the permitting process they have.

And very excited about where we're working, who's following us around where we're working. Our partnership levels, our working interest not at a high working interest anymore to have more opportunities, and it's going really well for us..

Very good. Well, I appreciate the time, guys. Keep up the good work. Thanks..

Thanks, Ben. I appreciate it..

Our next question comes from Paul Cheng with Barclays. Please go ahead..

Hello Paul.

How are you doing?.

Very good. Roger, in Eagle Ford, I think your last estimate is you have about 800 million barrel of resource still remaining.

What will be the sweet spot in longer term? Are you still looking at just 50,000 barrel per day or that is going to be 60,000 or 70,000? I mean, how should we look at it longer term?.

The – of course, we're not – we're revitalizing our budget and long range plan. I'm also pleased with that. But I think you need to think about that business next year around a $47, $48 business, might get into the low 50s for 2019 and 2020, and then all in up into the high 50s in 2021, 2022, and probably staying at that level..

So it would be somewhere between $50 to $60, you believe is the sweet spot for you?.

Yeah. Yeah..

And do you actually have a preliminary outlook for 2018 CapEx and production?.

No, Paul. I mean, it's not even time for your conference yet, Paul. And I won't say it there either. Let me just make a statement about that. We're like anyone else here of late and around what we work. We have very successful wells in our onshore business too.

And we're increasing the EUR per well and doing very well with that, increasing IP30 per well, ahead of where we were a year ago in that. Our offshore assets, especially in Malaysia, are holding up better than we thought a year ago. And we're progressing our new Block H LNG project. That's coming along nicely with that situation.

So a solid long-term Sarawak gas business, it's going well for us. And with that backdrop, we're, of course, reworking our plans.

And looking at oil prices, et cetera, I'd say today at a high level, WTI in the $48 to $49 2018-2019 number, keeping our debt levels the same as they are today, and ending up around $52 in 2022, we still deliver our single-digit 7% to 10% CAGR there. Paying our dividend.

And we're happy about where that's positioned and we will have the ability to do that and we're working toward finalizing and working through those plans over the next few months..

Roger, but if we are looking at the in and out on CapEx, I mean, look like that in Duvernay you're going to spend more money, in Eagle Ford probably not, in Montney in the Canadian gas you're probably spending more money for the growth.

So should we assume that the CapEx is going to be up at least for next year maybe by a couple of hundred million dollars?.

We're working towards trying to get to $1 billion, yeah..

Okay.

On the – I just want to clarify that based on you press release, so should we assume by the – towards the end of 2020 your Canadian gas will be roughly about 500 million cubic feet today?.

That's exactly where it will be..

Okay. Two final one real quick.

Do you have a pre-drilled resource estimate you can share for CT-1X discovery and so far do you see is any different than that number?.

What we have here is a series of very small fault blocks. We probably have 10 million to 12 million barrel discovery, where we originally drilled the well we announced today. This is shallow water jack-up territory, very similar some of our Sarawak field that we put online and been very, very successful there.

And we're drilling another fault block of similar sizes, around four other of these fault block opportunities. These are around $8 million net to Murphy to drill these wells, very inexpensive, very low F&D, very low breakeven. There's another discovery by another party in the southern part of this block, a large gas discovery that goes into our block.

It's possible we would work with that party in the development or that – or sale to that party or monetizing through capital allocation where we want to do several of these small fields at this time. And we're real happy. This well had a lot of pay in it, over several hundred feet of pay in a very small fault block.

And it made us change our drilling position to where we are today and just a small very high margin shallow water business that we've been very successful at running in Malaysia for a long time, for over 10 years..

Great.

Final one, Malaysia Block K, the floating LNG – or flexible LNG, are we still talking about 2020 startup or that has been changed?.

No, it's maintained..

Okay. Thank you..

Thank you, Paul..

We'll take our next question from Muhammed Ghulam with Raymond James. Please go ahead..

Hey. Good morning. This is Muhammed on behalf of Pavel. Thanks for taking the question. My first question is regarding Vietnam, the discovery you announced there earlier today or, I guess, last night.

How much future activity do you have anticipated before you're going to assess the resource base present within the country?.

Well, we have two blocks there, one at the Nam Con Son Basin, with the Cuu Long Basin. Nam Con Son is a block we've had for a few years. We have four to five similar size opportunities. So what we're drilling today are well – recently was a discovery in a small fault block area.

It's just a matter of tying together smaller fault blocks, which we've done very successfully before in our shallow water business. In our 15-1 business, we see this field that we've discovered as near 100 million barrel discovery gross recoverable resource. We're working with our partners towards the final clear development running (33:10) sanction.

We have very nice opportunity of an exploration well next door to that. And now new opportunity of a similar feature bleeding on to a new block that we just picked up in an application with the Petrovietnam. We have yet to hit the water level on our field that we've discovered in 15-1.

I see this as low risk, low cost exploration to be very positive for us in a region where we've been very, very successful, very, very well known for operating a building cost structurability. And so we can – I believe we can build a solid offshore business in shallow water Vietnam..

Second one is on CapEx. We've seen various operator reporting that service costs increase (33:55) over the past few months.

What are you seeing in your portfolio?.

We, of course, have seen some completion costs. I think we've made it through half the year without as much impact on that. It's coming more to bear primarily in Eagle Ford Shale. Nowhere else in our business are we seeing it, primarily around fracking, probably talking around a 20% increase in our completion costs of the wells.

Drilling is hung in there very well. We continue to do optimization and ability to drill pacesetter wells primarily in Catarina, where we're actually drilling these wells for barely $1 million in only four days, four-and-a-half days in some situations. Our total CapEx we have reflects the rest of the year.

These costs have been – completion is going up. We've managed that through CapEx efficiencies in some of our artificial lift and electrification projects and other projects that we have in the Eagle Ford.

They will stand by our CapEx for the year and actually deliver few more wells in Eagle Ford than planned, and pleased with our handling of that situation.

Canada, we're not seeing a problem with it and this is more about efficiency in Canada, lining up to do the same completion repeatedly, and we will then have a nice situation there, where our ability to lower days efficiency is just getting started..

And last one for me, can you talk about your Australian operations and what your plans for the country? And what's going on over there right now?.

Well, we have some very nice exploration blocks. We have a very small team that works on that in our company. They are true experts around these two regions. We have all of our 3D seismic shot in our Ceduna Basin fully loaded in our workstations, enormous prospects here, very large prospects.

We just need some drilling to go in the area, and we're hoping that super majors nearby will go through with their plan that they reorganizes, which is very positive for us.

Vulcan Basin, no well commitment, seismic, very inexpensive, built a very nice business there, ground floor, grassroots old-styled exploration with a very experienced team there work in this region for another major company.

And we're looking to drill there probably in the 2019 to 2020 timeframe, and will be monitoring what goes on in the Ceduna Basin during that period. So it's probably a 2020 plus kind of deal for that, but very pleased with the prospectivity we're seeing right now..

Yeah. That's all for me. Thanks..

Thank you. I appreciate it..

And it appears there are no further questions at this time. I'd like to turn the conference back over to our speakers for any additional or closing remarks..

No. We have nothing left today. It was a nice call. We appreciate everyone calling in and I look forward to talking to you later this fall. Thank you. Appreciate it..

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