Q2 2019 Earnings Call
Following today's presentation, there will be an opportunity to ask questions.
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Please note this event is being recorded.
I would now like to turn the conference over to Brad Whitmarsh. Please go ahead.
Thank you Allison and I appreciate all of you joining us for our second quarter Conference call.
I Hope Youve had a chance to review the news release and presentation deck that we published this morning.
These materials are available on the investors page of our website.
And they highlight continued strong operational performance for the business.
Later today, we plan to file our Form 10-Q with the FCC.
I want to remind everyone that today's discussion contains projections and forward looking statements.
As well as certain non-GAAP financial measures you should read our full disclosures in our latest news releases and FCC filings for a discussion of those items.
Following our prepared remarks, we'll hold a question and answer session.
I would ask that analysts limit themselves to one primary and one follow up.
Our planned comments this morning will come from Dave Stover, Chairman and CEO as well as Brent Smolik, President and COO.
Ken Fisher SVP and CFO .
Hodge Walker SVP of onshore and Keith Elliott SVP of offshore are here to participate in the Q and a session.
With that I'll turn the call over to Dave.
Good morning, everyone and thanks for joining us.
And it started out as a volatile earnings season for the industry, but we're glad to have the time. This morning to Sarah Noble's accomplishments and why we are excited about our future.
For us the summer days have been very active.
We're close to bringing Leviathan online and realizing that transformational impact we've been pointing to for several years.
It's thrilling to be just a few months away from startup.
Across our portfolio, we have created more certainty and visibility throughout our business this year.
The Olin sanction DJ inventory of permits.
In our development mode in the Delaware, all contribute to a sustainable future for noble energy.
Onshore execution and Leviathan started up establish the foundation for performance than 2020 and beyond.
Noble is positioned to distinguish itself through three key factors.
One the positive rate of change heading into 2020 from decreasing capital and significantly increasing cash flow and volume.
To the move to an even lower annual corporate volume decline rate from the low 20% range.
And three a global inventory that includes substantial discovered resources that can use existing infrastructure to generate significant returns.
As the market continues to experience volatility we remain intensely focused on generating free cash flow.
Improving corporate returns.
Protecting the balance sheet.
And returning significant amounts of capital to investors.
Through the first half of the year or our organization has made tremendous progress and I'm proud to share our accomplishments.
For the fourth quarter in a row, our total capital came in below expectations.
This was driven by onshore U.S., well cost and facility savings and offshore activity timing.
Brent will highlight how we are exceeding our original capital reduction targets year to date.
And this is a step change that provides the framework for a long term sustainable decrease in our capital intensity.
With our accomplishments to date and our confidence in our outlook for the remainder of the year, we are lowering our full year 2019 capital guidance by $100 million.
We delivered a strong operational second quarter. Some specific results that really stood out included.
Capital expenditures and operating cash cost per barrel were more than 10% below plan for the quarter.
And sales volumes were 10000 barrels equivalent per day above the midpoint of expectation with oil volumes toward the high end of guidance.
These factors contributed to an improvement in cash flow per share versus consensus.
It also highlighted the organization's success in managing controllable items.
During the quarter, we actively managed our commodity price exposure through market diversification and hedging.
We added some new oil hedges and are now approximately two thirds covered for 2019 and above 40% for 2020.
With a floor of at least $58.
Earlier this year, we also proactively hedged 70% to 75% of our Wahab basis exposure through 2020.
Our operational performance and efficiency is accelerated the number of wells to first production through faster drilling and completion timing.
And our onshore activity in the second quarter will drive a pronounced third quarter volume increase while onshore capital spending trends lower in the back half of the year.
Along with the high demand season in Israel and strong performance in West Africa. The entire company is undergoing a material uplift this quarter.
Our third quarter volume guidance reflects 8% total company sequential growth at the midpoint of our range.
With oil up over 10%.
We're well on our way to delivering the outlook.
This outlook with strong performance in July .
Year to date results along with our outlook for the second half provides confidence that our full year volumes will be towards the upper half of our original guidance range.
In the DJ Basin, our performance continues to deliver to the upside.
Led by development of the Mustang asset.
It's amazing to think of the progress the team has made to efficiently design and set up the asset for long term development.
And the results are proving the success.
Looking to the future I'm pleased to announce that we have submitted the application for an additional comprehensive drilling plan or CDP.
For the North Wells Ranch area, where we can build upon the accomplishment seen at our Mustang position.
Through our long term strategic planning.
We have years of high return activity in the DJ giving the company line of sight to execute on its multiyear plan and to build upon our industry leading returns in the basin.
In the Delaware, we've delivered significant well cost reductions operating cost improvements and increased production meaningfully.
The team has executed well this year and brought online our first row developments during the second quarter.
In support of these basins noble Midstream partners has continued to ensure efficient in basin gathering as we bring wells online ahead of schedule and plan.
Our strategic review of the midstream business is ongoing and we will update the market when appropriate.
Providing diversification to our us business. The international assets are comprised of material low cost low decline discovered resources.
These resources have the economic benefit of taking advantage of existing infrastructure to develop them efficiently.
The first half of the year as brought Leviathan closer to production.
And saw the sanction of Arlon gas monetization project in West Africa.
These projects provide a unique opportunity to access global natural gas markets with premium pricing.
Noble's rate of change story is really exemplified by our Leviathan project, which creates a huge net cash flow swing from completing the project in 2019.
To the first full year of production in 2020.
Leviathan represents the largest discovery in our company's history and warm up one of the largest ever infrastructure projects in Israel.
With 33 trillion cubic feet of gas in place in 22 trillion cubic feet recoverable.
The project will continue to provide energy independence for Israel and transform the country into a significant energy exporter for the first time in its history.
The construction of Leviathan project production decks is finished and the project is now nearly 90% complete.
The production decks that sale for Israel in early July and you can see a video of the launch on our website.
We really look forward to their arrival later this quarter before final commissioning and first gas sales by year end.
Additionally, we continue to progress marketing and transport discussions.
Technical work on the EMG pipeline was performed during the quarter to test its integrity.
Our teams are extremely pleased with the condition of the pipe, we anticipate closing on the acquisition in the third quarter.
With a bias and starting up at the end of this year and a land in the first half of 2021, I'm really excited about the cash flow impact and sustainability of cash flows that we're adding from our offshore major projects over the next couple of years.
In addition to our robust discovered resource base, we have some material exploration opportunities that we're looking forward to testing in 2020.
Our plan includes the handful of onshore unconventional wells in Wyoming.
Along with an offshore Colombia prospect test next year.
Overall, I'm extremely pleased with our progress and how we're executing for the future.
To be clear next years capital program is expected to be significantly lower than this years.
At the same time cash flow and volumes will grow substantially.
As we move into this transformational 2020, we will be managing our capital expenditures to ensure we generate organic free cash flow that can be returned to shareholders, while strengthening our balance sheet and improving corporate returns.
We've set ambitious goals to recalibrate, our business through a laser focus on cost efficiencies and a moderate growth profile.
Along with a lower capital intensity, we are focused on improving our overall cost structure through reductions in operating DNA and noncash costs.
Now I will turn the call over to Brent Smolik, our president and COO to talk about how we are lowering the long term capital needs for the company and generating high margin growth and returns through innovation and continuous improvement.
Good morning, everyone.
Thanks, Dave.
I Echo your comments on the dramatic rate of change in the.
Significant inflection point that we're experiencing.
As evidenced the U.S. onshore business delivered a very strong second quarter as highlighted on slide four.
Production was above plan and capital and operating cost were lower than forecast.
For Q3, we expect total USL production to be up nearly 10% for both oil and equivalents.
And capital to be down about $75 million sequentially.
This is a reflection of the good work our teams have done to improve capital efficiencies and reduce cost.
Coupled with the acceleration of our turn in line schedule all positive for improving cash flows.
In Q2, yes, so well costs were down nearly 20% from fourth quarter 2018 levels.
On slide five you can see that we are exceeding the planned cost reductions of 500000 to a million dollars per well in the DJ basin and it may in two main at $5 per well in the Delaware.
Currently our costs are about half a million dollars lower than the budgeted cost through a combination of improved well designs better execution efficiencies in supply chain savings.
Some examples of the Q2 Q2 execution included record drilling times, and both the DJ and Delaware basins.
Several of our 9500 foot laterals in DJ were drilled in less than five days.
A recent well in the Delaware with about a 10000 foot lateral was drilled in less than 17 days and it wasn't that long ago that we were averaging over 22 days for the long lateral wells in the Permian. So I'm very pleased with the progress made by our drilling teams.
On the completion side pump hours per day continue to trend higher through the road development and execution improvements.
We've also worked with our service providers to incentivize, even higher pumping hours per day, which benefits both us and them.
We've continued to refine our completion designs, including in some cases, lower proppant concentrations and fluid volumes.
Reducing those frac fluid volumes creates benefits on multiple fronts, including lower capital cost reduction in source water and water disposal and acceleration of first production.
We've also continued to attack operating expenses unit production costs were down significantly in the quarter as we focused on workover optimization streamlining chemical programs in fuel cost savings.
And we're certainly not done we've got continuous improvement initiatives underway for further expense reductions.
Before jumping into some of the asset specifics also wanted to highlight a couple of new all marketing arrangements.
This should improve netback pricing.
In the Delaware initial flows on the epic pipeline will commence shortly and we'll be moving barrels to the Gulf coast, a very attractive tariff rates.
Reported GDP will increase with the transaction, however increased realizations were more than offset the cost.
As we have as we migrate our Permian.
Permian oil sales to Gulf coast pricing arrangements.
During Q2, we also finalized an agreement with existing Saddlehorn pipeline to transport additional quantities of crude from the DJ basin to Cushing at lower tariff rates.
The noble marketing team and noble midstream have done a very nice job of improving the value of our equity barrels and both arrangements will contribute to further margin growth.
Let's take a little closer look at the DJ Basin, we delivered a strong quarter of execution and the asset continued to fund growth, while generating free cash flow.
In the quarter, we initiated production on 36 wells in the basin with 20 for Mustang Road too.
The Mustang area continues to perform very well the gross production from rose one and two is grown from zero to over 55000 barrels of oil equivalent per day and less than a year.
That performance is highlighted on slide eight along with DPP four away, which is one of the development plans on road too.
The Mustang Faraway DP has 24 wells 12 of which were pumped with lower fluid design and 12 with our previous design.
Reducing fluid volume sustainably reduces cycle time and well cost.
The DJ efficiency gains to result in a few more wells this year than planned in the second half of the year, we expect to tail over 50 of over 50 more wells primarily in Mustang in Q3 and wells Ranch in Q4.
Before leaving the DJ its important to mention the gas processing expansion that's underway.
Dcps O'connor to plant is expected to restart shortly and ramp up during the third quarter.
As a reminder, we utilize several gas processing alternatives, if needed which has helped position noble differentials in the basin.
Turning to the Permian.
The Delaware Basin production reached a quarterly record of 64000 barrels of oil equivalent per day.
The production benefited from strong base, and new well performance, including the acceleration of seven tils into the quarter.
As displayed on slide nine we initiated production on wells across our acreage position in Q2, including our first real road developments.
Well costs are significantly lower than we budgeted and well performance was in line with our expectations.
The calamity Jane development in the northeast portion of the acreage showcases our initial full section row development.
These 10 wells peaked at approximately 20000 barrels of oil equivalent per day with all percentages in the 50% to 60% range as expected in this part of the field.
The benefits of ROE development include reduction in parent child interactions improvement in the consistency of well performance and significant operational gains.
The calamity well Jane wells realized an improvement of 15% and drilling and completion cycle time.
And through our continued focus on capital efficiencies, we've been able to further improve upon this success.
This quarter, we expect until an incremental 15 wells and expect our Delaware basin production to continue to grow in the second half of the year.
We've also meaningfully reduced lease operating expenses in the Permian unit Ela, we costs were down approximately 20% sequentially and are expected to trend lower as we move through the year.
The Eagle Ford asset continues to perform very well, providing cash flow to the business. We brought on line 16 ducs in the quarter.
Many of those deals were late in Q2, so we expect to see a big production step up in the third quarter and then declined in Q4.
And we won't be adding any new wells in the second half of the year in Eagle Ford. Therefore, our teams will be heavily focused on on budget base production management, including testing a refrac concept in Q3.
Our offshore poke focuses is really three pronged our teams continue to be very focused on reservoir management and base production optimization.
We are advancing near term development projects, primarily Leviathan in Atlanta.
While planning for future monetization of World class low cost discovered resources and the eastern Med in West Africa.
So I'll begin with Israel Tomorrow produced 950 million cubic feet equivalent per day in Q2, which was better than expected.
And the third quarter remember is typically the highest quarter of the year based on seasonal demand and we expect the asset to average over a bcf per day in Q3.
As Dave mentioned, the Leviathan project is now nearly 90% complete.
And I commend our project in our operational teams and our our many partners around the world that are supporting the project and delivered an exceptionally well managed major project.
We also discuss the competitive advantages of Leviathan will deliver to the company.
But it bears repeating our total company production decline rate pre Leviathan is in the low 30% per year range.
As Leviathan comes online that annual decline rate improves to the low twentys.
Leviathan itself Rimmer has essentially no decline and we expect production and Leviathan to grow with market demand over the first couple of years without any additional capital.
This kind of high quality asset reduces volatility it provides more cash flow certainty it creates more capital allocation flexibility across the portfolio.
Since it requires less capital to maintain the base production.
And that's an important differentiator for us.
As Leviathan commences production will begin moving significant quantities of gas to Jordan Egypt.
Representing a new area era of energy exports for Israel.
Leviathan gas sales of receive some some positive press in the last few weeks.
We're in conversations with our primary Egyptian customer to firm up quantities from Leviathan and tomorrow.
You may have seen in the news, we'll keep you updated as negotiation progresses, and we can track for increase in gas sales into the growing regional market.
Our view for Leviathan in 2020 hasn't changed we're expecting gross production to average about 800 million cubic feet per day below that average in the first half of the year and closer to a bcf per day at the end of 2020.
As Dave mentioned to highlight for the quarter was the completion of the technical due diligence on the EMG pipeline.
We have now confirmed the physical integrity of the pipe with an inline inspection and pressure test and we've demonstrated the ability to transport natural gas into Egypt.
Over the next few weeks, we'll be working with partners to verify the integrity of the downstream pipelines and completed sustain flows test flow flow test of gas into the gypsum grid.
The flow test is the final critical path item to closing the Mg pipeline acquisition, which we expect by the end of the third quarter.
We also remain focused on longer term market and transport options to monetize additional gas, including expansion of the regional pipeline infrastructure.
You May have also seen this week that we are evaluating a floating LNG project, which has the potential to deliver gas in the global markets at a competitive slack supply costs.
That data that project would require minimal near term capital as it would be required and the concepts that we're reviewing.
For our West Africa assets continue to be a stable supply of cash flow with exist from existing developments and additional high return projects.
We're currently drilling the horizontal portion of the pit is saying six fee will be moving to the completion phase within the next few weeks.
Well is expected to be online early in the fourth quarter gross production is expected to be approximately 10000 barrels of oil per day, which will result in about a 60% increase in current field production.
Well returns clearly benefit from the use of the assessing infrastructure.
Our land team has done an exceptional job of identifying opportunities to increase condensate rates in the field and as a result, Q2 production was above budget.
The gas monetization project in land that we announced in Q2 represents another opportunity to add production and cash flow in 2021.
Like Leviathan Lynn will have a growing production profile for several years without the need for additional capital.
We've updated guidance on slide 18.
Capital expenditures for the third quarter estimated to be in the range of $600 million to $675 million with the majority of the capital spend in the us onshore and eastern med regions onshore will be down sequentially and offshore will be up largely due to the leviathan installation enhancing well.
We have lowered our full year capital range by $100 million.
When and we anticipate meaningfully lower capital in the fourth quarter with lower onshore completion activity and lower Leviathan capital as the project starts up.
By the end of the year.
Weve also lowered our full year unit production expenses and DDNA ranges and raised our full year production outlook.
Q3 will be our largest volume quarter for the year as all business units are expected to be up with the U.S. and within the U.S. oil should be up about 10000 barrels of oil per day in the third quarter with modern all growth in the fourth quarter.
At this point everything we can control is moving in the right direction.
As we move to Q and I want to leave you with three thoughts one we're delivering on expectations across the company and are ahead of plan.
Our strong execution in the first half of 2019 positions us well for the second half of the year for 2020 and for the longer term planning horizon.
Two we are nearing an at the huge inflection point for the company.
The rate of change is being led by the capital efficiency improvements in our us onshore business and the massive swing in net cash flows from Leviathan, which is now which is now just a few months away.
And three we have a sustainable long term outlook.
Our portfolio quality and reduced maintenance capital requirements position us extremely well for long term sustainable free cash flow, increasing corporate returns and the ability to return more capital to our investors.
Operator that completes our prepared remarks, please open the call for questions.
Thank you.
We will now begin the question and answer session.
You ask a question you May press Star then one on your Touchtone phone.
If you are using a speakerphone please pick up your handset before pressing the keys.
Did withdraw your question. Please press Star then too.
At this time, we will pause for a moment to assemble our roster.
Our first question today will come from Aaron So Yara of JP Morgan. Please go ahead.
Yeah. Good morning, Brent maybe this one is for you I was wondering if you could talk a little bit about the sustainability of the well cost savings that you outlined in slide five and how the ROE development strategy.
Is helping you achieve some of those well cost savings.
Yes, Thanks and great question.
The the things that we're doing that are that are most sustainable.
On the completion side of the business, we've been able to fairly significantly improve the pumping hours per day and the number of stages that we're able to get done per day.
And we've we've actually added some incentives into the contracts with our with our service providers to push those numbers up even further.
And a lot of it is just.
Better day to day execution, and taken out waste in and downtime and the operations that part's very sticky and very sustainable the other parts of it that are design related are changing how we do our business and so the the best example to point to is the lower fluid frac designs in the DJ.
Those have a lot of benefits because.
Today, we get lower cost for the Frac fluids, the freshwater food to start with.
We shortened the pump times and get more stages done per day, we increased the decrease the cycle time and get well on production quicker and we have less disposal costs on the backside.
And those kinds of design changes along with a lot of others are sticky even if we get back into an inflationary environment and then we we we have a number of things that we're working on them to continue to.
To continue to manage the supply chain side of our business, but I think I think most of what we're doing and do your ROE development point is ROE development only only.
Only improves the probability of being able to get all those efficiency gains.
So I'm really happy with the progress we've made so far on on getting faster.
And then those lower fluid designs, what can you speak to in terms of productivity there.
So far so good.
Remember that we've got.
Some of the highest productive wells up the DJ and we continue to see high productivity per well.
Returns are.
Better because of lower capital cost and higher efficiencies. So hopefully we'll get the we'll get the.
Benefit of both top numerator and denominator.
Great and my follow up Dave perhaps for you.
The N. bialek strategic alternatives process, we've gotten some questions given the departure of NB Alexis CFO quite recently.
Our analysis suggest that it's a relatively short cut to well over $2 billion and total value kind of net to noble, but could you provide us an update on the process and maybe some of the pros and cons of potentially.
Monetizing a portion of your interest here.
Yeah, not not really anything to elaborate on I'd go back to my prepared comments around that when when there is something we'll tell you I think you you do bring up a good point, though and that's the value of the Npls business itself. I mean, you look at the.
The release they sent out this morning, there hitting on all cylinders also in the second quarter, they've got some transformative things coming up like the epic pipelines coming up they're focused just as Brent talked about on decreasing costs and their overall business. So it is just the very valuable business.
Great. Thanks, a lot.
Our next question today will come from Brian singer of Goldman Sachs. Please go ahead.
Thank you good morning.
Hi, Brian Hi, you highlighted on Leviathan expectations for gross volume is in 2020, the average, but about 800 million a day.
Can you talk more about how that ramp up looks over the course of the year or if it is consistent for the year. How much you expect to go to domestic versus international markets and then whether you see Tim are cycling down or whether the 800 is fully incremental.
Yes, I think what we're saying is what we'll have truly incremental volume here and what Brent I think alluded to in his comments was that you ought to expect the first half of the year will be under that average in the second half of the year will be overdone set ourselves up nicely to exit the year around that Bcf a day or so so the the whole outlook I think is similar to what we've been saying, but we're continuing to firm up contracts were seeing the demand continue to increase folks wanting to firm up more demand you're seeing in Israel.
The discussion around accelerating coal conversion. So I think as just as somewhat we expected as leviathans coming closer and closer to coming online is becoming more real for folks and its firming up what our outlook can be in that.
Even the potential upside could be when you look beyond 2020.
Great. So the Bcf a day by the end of the year is fully incremental no cycling down not.
Or or decline that tomorrow.
Right I think theres going to be enough. When you look at internally in Israel and the regional capacity that they will be wanting everything deliver from phase one a leviathan everything we can deliver from tomorrow, especially as you get towards the end of 20 and beyond.
Great and then the second question is with regards to the Delaware Basin and well productivity can you just talk to as you continue to bring on more of the ROE development for what your expectations are for the.
For how productivity goes from here and then how you see if at all oil rates evolving relative to that kind of 50% to 60%.
Yes.
Primary thing, we're seeing from the ROE developments as we have less between well interference and more consistency.
In the well performance so we we get less of the.
The the the parent child kind of interference that causes a lot of scatter in the results and I think thats, a positive and it averages up our total returns.
In the in the.
In the field, our best performance is still Wolfcamp, a and the third bone, which where it's been in most of our program and most of our capital on this year and and those results are good and you can see that even in the.
And the.
So if our test rates that we released.
So I think I think that all feels like it's on track to us where we are but we've been intermittently spending a lot of time on come on a capital efficiency.
And we talk a lot about it in the first half of the year and the results are compelling.
But weve also continued in the background to work on improving well productivity.
Hopefully overtime, we'll be talking more about those those improvements.
Great. Thank you.
The next question will come from Doug Leggate of Bank of America. Please go ahead.
Thanks, Good morning, everybody.
Guys I Wonder if I could circle back to Israel for a second.
Yes, as you pointed out theres been some.
Noise in the press around the Egyptian contract some particular, but I'm just curious about when you talk about little capital required for material growth can you just walk us through what the current ridden the what the redundant capacity would be both tomorrow.
On Leviathan, let's say once both online and.
Any kind of reasonable guide that you think are idea that you think is to how quickly you could see that tight capacity utilized with no material incremental capital I've got a follow up please.
I think that's good I think the simplest way to think about it is that you know that we've guided to about 800 million a day average gross production from Leviathan for 2020.
And without additional capital into the facility and wells will be capable of about 1.2 Bcf a day.
And we can ramp that up over that first two to three year period, depending on market with no additional capital. So it's kind of inclining based production from 800 to 1.2.
And then I think Doug what you're alluding to then beyond filling up the first phase of Leviathan. That's when you start getting into the incremental capital when you get above that 1.2 Bcf a day and we can do that very efficiently as you well know we've set up the production facility to be able to incremental lies with modules up there and.
200, 400 million a day increments.
And then you are looking at each well can deliver 300 million a day. So the real piece will be holiday evolves from where you are going to flow the gas to on your phases beyond phase one.
Dave I guess, what was behind my question. Most I seem to recall you had pre bill a couple of hundred million dollars of.
The expansion capacity in your in your Leviathan budget.
Plus you have got a 600 million a day and without neo platform producing a 10th of the in Mari B.
I'm, just kind of trying to understand how you optimize.
Dol a lot of redundancy is kind of like if you build it they will come I'm wondering if having a lot of capacity available on more reliable operations. If you like if there was a latent customer base that is.
I'm going to let you to ramp quicker less kind of really what I was trying to get out and that will play itself out, especially as we get into 2020, and everything's up and running and you start to get this ramped up Leviathan ramped up and you see what that demand is then and folks start to see as we talked earlier that it's more and more real it's here. It's now you got both Leviathan and.
Tamara and they're they're very.
Low cost sources of supply and go back to how tomorrow ramped up and how it quickly it ramped up through demand once it came online.
And I think Thats a good.
Precursor if you will from both how we can say 20 and 21 playing out your point is exactly right.
Taking advantage of existing infrastructure is going to be an incremental benefit.
As we move forward here in the basin and the way Keith and his team have laid this out with their pre planning that we can take this platform from 1.2 Bcf a day to 2.1 Bcf a day and wing do it now and increments.
As it demand dictates, it's going to be a benefit so all of this infrastructure in place just continues to build on that and that's the importance of also having multiple outlets and multiple pipeline takeaway.
We think it's almost the entire value of your company right now where your share price is trading but anyway I. Let my follow up is it really a quick one just on the capital guide for next year, obviously, you're talking about material reductions I assumed the 5% to 10% X major projects is still a good number on a go forward basis associated with that decline in spending but I'm wondering if you could just give us an idea of what your sustaining capital is.
In the event the oil prices did come under pressure given all the macro stuff going on what does the sustaining capital when the device on is on right online to hold your your your exit rate. This year slot I don't know if you've got something like dogs to Honda, but some kind of ballpark would be helpful.
Well I think when we when we talked about it.
Last year, we kind of earlier this year, we laid out a a maintenance capital. If you go back to that one slide where we laid off maintenance capital and then we had two tranches above that.
And that was then probably in six or 10, one yeah 1516 type range I think that the nice part of what Brent and his team is working on what whole organizations working on improving the capital efficiency lowering our capital intensity.
And we'll see we'll see where we get to the end of the year, but I don't see it being higher than that.
Great stuff, thanks for taking my questions guys and congrats.
Thank you Doug.
The next question will come from Scott Hanold of RBC. Please go ahead.
Yeah. Thank you, but if I could just add on to that last question in as you look at these well cost reductions they were fairly significant.
So far this year, especially in the onshore and.
Now you're seeing a lot of efficiencies in how to how does this help craft your thoughts about.
You us onshore spending as you go into 2020, 2021, where you got the large projects really.
Supporting some pretty solid growth.
Well the focus than in 2020, 2021 will be delivering that free cash flow, though the the spending will fall out of that but all of this work that the team has been doing and all the progress we've been making on on lowering and improving those efficiency was just going to help.
In that regard, but I don't know Brent anything else to add there I would just say notionally, we're not thinking of higher activity levels. Scott, we're thinking of similar activity levels without finalizing a budget, which would imply lower than we previously had planned capital because of the efficiencies.
Okay, great. Thanks for that and then as my follow up if I can refer to page five a little bit more on the.
Well cost in the DJ and the Delaware and what really stands out is the marked a shift in the cost savings on well design in the DJ Basin you correct me if I'm wrong. If that's you know doing the lower fluid Fracs is that something that you are going to test soon in the Delaware is that something that could actually be another incremental saving for the Delaware wells.
Yes, it's possible.
We don't have we don't have any of them to report on yet.
But if we convinced ourselves that we can get the same productivity is in the u. ours in the DJ than it would be something it'd be transportable.
Elsewhere.
Yes, how long is it like how long does the do you need on DJ data to to make that determination is that something that could be a 2020 initiative.
Yes, yes.
Give me a 20 to even late this year, we might try to put it puts them in the ground, but did you think of it is longer term in the Delaware and I want to point out too thats not the only thing Thats included in that design change bucket.
We talk about it because it's a it's a big and noteworthy accomplishment, but we've changed the design on how we go about.
Executing on the Frac jobs and a lot of ways.
We're pumping down perforating guns faster, we're pumping down plugs faster.
We're getting.
We're.
We're changing chemistries along with the fluid volumes, there's just a lot of things that we're doing in the design changes that add up to a big number.
Okay. So is it more advanced renowned the DG is that where you're seeing a bigger step change in the DJ versus the Delaware.
I think we're seeing a bigger step change because because we've we've made more design changes in their more advanced in the Permian, we saw a bigger supply chain reductions because they had been so much inflation that we're we're caught some of that back.
Understood. Thanks.
Our next question today will come from Welles Fitzpatrick of Suntrust. Please go ahead.
Hey, good morning.
Morning Wells.
You guys talked about Saddlehorn and that that detail is great, but can you point us to where you're looking.
For relief on on the gas and the NGL side, and the DJ whether that's cheyenne or or some other projects coming up.
Yeah, I think I think what on the gas side I think we'll see some relief as soon as DCP works through.
The current the current restart of the plant the O'connor plant to a DC plan 11.
And that will happen, we think in next week it will start to ramp back up again and so the gas is going to de bottleneck in itself. I think you know by the third fourth quarter, we'll see enough NGL capacity were the constraints in the basin will get relieved.
I think I think that will clear itself up in the near term and we factor that into our updated guidance.
Yeah, I think you're also seeing some conversion going in place on NGL line with white cliffs up there too that that should be helpful. If that gets finished up here.
Okay, Okay, perfect and then for my follow up on the new propose a Colorado a Q C. C emissions rules I know you guys say pretty far ahead of that is it is it fair to say that there won't be significant incremental costs and and also could that open up any any opportunistic Andy as maybe smaller companies exit.
Yeah, no talent on Andy that it's just not something we're focusing on up there I think the main focus for us as we talked about earlier getting this next the comprehensive development.
Drawn development plan in place the CDP.
And I think that's one of the things that will enable us to stay ahead of the game up there just as the original one has.
And on the on the admission side I mean, we already enjoy low emissions.
And because we have been focused on it for some time the the biggest advantages. We have is a lot of the operation the lot of the surface facilities or are nearly tankless.
And we we are looking at designs at both reduce emissions further and reduce costs.
No, which is the best of both worlds.
Perfect. Thank you so much.
The next question today will come from Michael Hall of Heikkinen Energy Advisors. Please go ahead.
Excuse me.
Thanks, Good morning, and solid quarter.
Hi, I'm just curious on the.
Some some near term stuff on the July volumes, you posted for the U.S. onshore already tracking pretty darn close to that.
The full three Q.
It's onshore guide.
How should we think about the rest of the quarter from an activity standpoint is there.
Some sort of a hole in August so we should expect to hit back loading in the quarter or.
Have you really just curious the third quarter already pretty substantially with the July results.
Yeah. That's that's it's a little unusual for us to give you an estimate for the.
For the next quarter, but we thought it was important because enough of those tils came on late in the second quarter.
Across the company really in all areas that it has a meaningful impact on the third quarter growth and we're seeing it showing up so that was that the key message. If you look go forward.
I pointed out in the in the comments that in the Eagle Ford, we're done with drilling and completing wells this year.
We do have a refrac pilot it'll happen later in the year, but it wont be meaningful in terms of the production profile.
So, we'll see Eagle Ford decline and it will grow significantly from second to third and then decline significantly from third to fourth.
The other parts of the business DJ and Delaware will see the step up to third quarter, and then a little bit of growth into Q4.
Okay makes sense.
And then I was just curious on the.
Kind of bigger picture on the 29th in capital program, you know taking down the capex.
Obviously a positive.
You had sales a bit ahead of schedule in the first half.
Inefficiencies have been outpacing expectations.
How are you guys thinking about.
You know the potential for efficiencies to continue improving in the back half and then.
Putting it in a position where you know you're kind of continuing to put on more wells than than originally planned.
Would you like to do would you would you biased towards a frac holiday in the back half of the year or.
How would you manage capital I guess.
What I'm trying to get at is yes.
Let me kind of take in bite size pieces. If you go back to our original plan, we had always planned to be a little bit front half loaded on on a completion activity entails and back half loaded on production because of the lag when it shows up.
We have accelerated some of the deals into the second quarter due to efficiency gains.
I will add a few at the end of the year So our profile.
Front half to second half looks a lot like we budgeted and we're kind of on plan with it.
The it to the efficiency gain part of it you're talking about is the reason I signal that we've set some records recently in drilling and completions is because you know.
If we can do that once we can replicate it and we are replicating it in the programs in the second half of the year. So we do expect to continue to drive efficiencies into Q2 that could accelerate production little more.
But in regards to what the way we think about the end of the year. We're not we're not targeting a number of completions, it's more about designing designing a smooth glide path into the end of the year as we idle equipment that we'd already we always had planned to have some holidays at the end of the year and so you just want to make sure you do that as efficiently as possible, where we don't.
Stop in the middle of a pad disrupt any of our supply chain.
Stop when we don't have facilities full ride in the meat area Theres a lot of things that are important to think about as you as you ramp down and ramp back up again later and so that's what that's how we're trying to design it to be as efficient as possible. Both in how we take out cost as we are doing it in is how we slowed down.
Great that makes a lot of fence and then that glide path. It seems that kind of suggests the.
You know the 2020 rate.
On the U.S. onshore capital spend is kind of probably hitting lower relative to prior expectations is that a fair fair comment then because that bias free cash flow higher in terms of.
Relative to prior expectations on 2020.
Yeah, we haven't you.
Fully baked 2020, yet, but all things being equal.
We would expect the efficiencies to carry into 2020, and it would be up and be positive free cash flow.
Great. Thanks, guys again congrats.
Our next question will come from Irene Haas of Imperial capital. Please go ahead.
Congratulations firstly on my vitamins process than the long haul and my question is related to east Med and I think at one point you guys talk about love floating LNG and why is this coming back into the picture and what would be the incremental production you're thinking of monetizing using this sort of Oh facility and then also how much lead time do you need and how would you finance it well I can just tell you why we're even looking at it Irene and then Keith can talk to some of the other logistics of thing.
But yeah. The reason we're looking at it is for longer term say, a second or third phase of Leviathan potential and it just creates more optionality.
For us and it's we would view it on we will only do it as a low cost option to create more optionality and broaden our marketing reach.
If you will so those would be the reasons you look at it far far from doing it at this point, we'd look at it and as far as timing of how that would play out Keith any any thoughts yeah. I mean, I think just to build on Daves point Irene you as you know we've looked at it from a country before I think the thing that's different now is we see.
The ability to connect with a proven vendor who's got systems up and running in other parts of the world.
And come forth with an idea of taking a process gas stream off Leviathan that becomes a very cost competitive solution at least in the initial looks at it as far as timing or we're early days were in the feed now and so it's it's something as Dave said, that's it's a it's a second phase project. That's a few years down the road and you know this wouldn't need to compete with the other things that would be in our plan that we lay out there. So it's not a capital changes nothing different from that standpoint, it's just creating optionality and potentially broadening our market reach for long term value.
If I may have a follow up visit this it sounds like that this vendor what actually is going to be a leasing I'll do you have to you know how much money do you think you could put in then lastly, you know any action in Cyprus.
Yeah, I think I'd go back to my original comments.
The only way we would do it if it's a very low cost option for us compared to other things we'd be looking at that is what it would take to compete so far from far from from an anything up there, but that would be the gist of it.
Cypress.
Those discussions are ongoing there's been a lot of progress towards that that that's something that still can have tremendous value longer term, but it's it's probably.
Ill step behind Leviathan, obviously in the queue right now.
Great. Thank you.
Our next question will come from David Deckelbaum of Cowen. Please go ahead.
Morning, guys. Thanks for the time.
Got it.
Just a.
When you guys lowered your capital budget for the year is the 100 million Delta.
I guess is that entirely coming out of us onshore I guess, because I know other people have asked around eastern med spending.
But relative to the 550 to 600 budget that you laid out.
It trending a bit below that at this point, what kind of visibility do you have for the rest of the year in terms of the Leviathan budget, particularly as you US onshore comes down for the rest of the year.
Yeah, I think you should think of it right now is primarily us onshore the $100 million.
But youre right in pointing out that we're we're 90% complete and weve essentially effectively de risk some of the important phases, we've de risked them.
The sub sea wells, the subsea tie ins the umbilicals pipelines and most of the fabrication and so now we're down to install and commissioning final commissioning. So we are getting we are project is trending well you know so we're optimistic that there will be some room, but think primarily of that as the U.S. onshore it probably probably I've realized savings that weve dialed in for a better line of sight to Aldo the final Leviathan capital turn out as we get the platform said and we can get through the third quarter and then then we'll be able to give more.
Expectation around that but the Brent pointed been a well managed well run project and.
Extremely pleased with where we are.
I appreciate that.
Hi, could you said a little bit more color around the exploration targets for next year.
I guess, namely in Colombia have you identified targets already.
At what point in the calendar is there anything else.
Endeavor is going to start taking place and.
You sort of have a loose budget in mind for exploratory endeavors next year.
Yeah, I think when when you go back to what we've talked about on total exploration capital which would be.
The drilling and the other components Weve talked about 100 to 130 million or so.
I I think Colombia itself would be a one well probably the second half of the year most likely.
We.
Aspen partners working with the government are finalizing the target is pretty much set.
And again that is targeted to be hopefully an oil play that that's probably some of the the real remaining question. There. It's got a fairly high for an exploration project piece of D.
Our chances of finding hydrocarbons.
But you know.
Our teams really focused on a liquid oil play potential there and that will be exciting to get drilled.
Tested in the second half of next year.
Got it.
Thank you guys.
The next question will come from Charles Meade of Johnson Rice. Please go ahead.
Good morning, Dave brand to the rest of your team there Hey, Charles.
Dave I wanted to go back a this has been touched on a few times through the queue nave, but want to go back to your your comments in your prepared remarks about the 2020 capex outlook and I'm not trying to pin you guys down or anything, but I don't want to get a sense of what are some of the big pieces that better and play and I think that the one biggest piece will get 20 over 19 would be would be eastern med Capex and you guys guided to 550 to 600 this year and that's not going to go to zero, but there is going to be a big chunk that comes out there what are the what are the other pieces that we should be thinking about is we try to you know.
Think about.
How 20 might look well your point, it's still early we will be.
Or in a budget later this year and it's up some of the things that we know about already though obviously, you've got a land capital that will be.
Higher next year, obviously than this year, so that would be the the one increasing pace they'll still be some capital as you mentioned the eastern med as some of the feed work some of the planning that we've talked about for some of the things the.
Stay ahead of market moving forward.
And then you know the other big piece will be the year on year.
Movement in onshore and and we'll just have to see how that plays out how the efficiency than that continual momentum play out.
I think the other piece, we just touched on is exploration will be a little bit higher next year as we go back to drilling at least as it's laid out now but I mean those are just some of the components and obviously, we'll have more color as we get into the end of the year.
Got it thank you for that but Dave and then if I could ask a question about the Delaware basin in less less about what happened in the quarter, but more kind of your.
The longer trajectory there.
Where where do you guys have a blue graphic in Europe in your presentation shows the I guess the gun barrel view on on on your on your spacing there.
Can you talk about how.
How much you've reiterated maybe how close you are to two being comfortable with a kind of a final decision on what well spacing is at least at least in the 55 or $60 world in it.
If you think you provided the right development concept for the the current set of conditions or where do you see there are still more learning you have to do Charles I think the high level answer is yes, you know that we've been pretty consistent in the three wells in the.
Third bone per section and six in the Wolfcamp a.
So I think we're happy with is facing I think what you'll hear us spend more time talking about is.
Landing zone, you know getting very specific about landing zones, and then optimized completion designs. The frac designs and that's you know that's something we got to be really mindful of even as we move north South East West in the field. So those I think the spacing, we're pretty comfortable with and we're happy with it in that one example of the calamity Jane that we've got in the deck there.
Oh, thanks for the added detail Brent.
Yep.
Our next question will come from Jeanine Wai of Barclays. Please go ahead.
Hi, good morning, everyone starting today.
Good morning, My first question is on the Delaware.
You continue that just have more activity in the northern part of your acreage and results look really good.
And it looks like the south has been trending around 25% of completions in Q1 and came to this year. So just wanted to understand how you think north versus south on the tendering activity in high and Tony and if you have any HBP requirements myself that may be coming up and just overall, how much activity from the southern central gathering facility handle.
We haven't we haven't guided yet to the specifics on 2020.
But I think you should assume that we're we're a similar frame of mind that we're we're going to fill up the CGS. We've got three large ones the north we've built the superstructure.
Infrastructure to be able to connect them. All this year. So we have a lot more operational or at least the midstream company has done that to give us operational flexibility to move volumes around.
We got capacity in the in the facility to the south.
There we have seen some you know fairly high rate wells delivered in the south and we think Thats a function of completion design and landing zone again, so we're going to continue to do some activity down there.
And so I think I think you can think of it as similar in our strategy and approach.
Okay, Great and then my follow up question I wanted to circle back on Michael's earlier question on efficiency, they're clearly going better than expected, which is good and we notice that the prior to 2018 completions guidance implied only eat in the DJ and four completions in the Delaware in the fourth quarter, but I think I heard you say in your prepared comments that you are now planning on doing more than that what overall less capex. So just wanted to clarify that to make sure we got that and I'm asking because we just want to understand how you're thinking about kind of a double edged sword at this point, given let's say with activity and growth with better than expected efficiencies and we know that yeah. The commentary out there that Tony Tony you kind of expect to have the same activity that you laid out and the prior to your plan, but potentially in lower Capex and just wanted to square your thoughts on how things are heading into the Tony Tony given the overall focus on free cash flow and the infection next year.
It's there's a lot in there.
I think the way to summarize it is that that that our thinking is really unchanged. We are delivering on what we said we were going to do this year and we're doing it more cost effectively.
And that's going to allow us to do a few more completions in primarily the DJ but a couple more in Delaware.
But it's really not a big change and then and then those efficiencies will be.
Yeah. We think are the kind of things that are sticky and so will carry them over into our activity for 2020, Yeah, and I guess Janine the main point there as we as we look to 2020 and we're not fixated on an activity level. What we're focused on is delivering the free cash flow.
Okay perfect. Thank you very much.
Our next question will come from Leo Mariani of Keybanc. Please go ahead.
[noise] hi, guys out west in the DJ just wanted to get a sense. If you guys are seeing anything incrementally on the regulatory cost side starting to flow through it all their past the the recent energy Bill there what do you guys kind of seeing on the ground there.
Probably too early to really seen anything.
With that I mean, they are still working through some of that rulemaking, Anna and I think again I'll go back to our big benefit instead of having to go for one off permit.
We're getting a lot of them done at the same time to be more efficient whether it was that original CDP or the one that's in the system now so that will be.
Thing that will make us the most cost efficient operator in the basin.
Okay, and I guess on the midstream side there in the DJ obviously, it sounds like it's de bottlenecking nicely here over the next several months and you guys have any.
Significant shut in volumes, you think might be returning and is there any way to kind of quantify that.
The only place I would point you deserve brand again, the only place I'd point you to is in that July estimate.
That we gave you that includes say seven to 10 days of.
Some of this interruption that we've seen on the DCP system, and we were still able to deliver the numbers that we that we released in July .
And I think the breadth point that highlights the work that's been done over the last year or two to provide multiple outlets and give us more flexibility in the base and then that that's always the case.
All right.
Okay. Thank you.
The next question will come from Michael scale, yet of Stifel. Nicholas. Please go ahead.
Yeah. Good morning think this year's plan originally included a $500 million to a billion of divestitures just wanted to see.
If you could talk about where that process stands.
Yeah, we're on track with that we've got multiple ways to deliver that and you know as those get firmed up we'll we'll talk about them, but feel good about being on track with the whole program.
Great and.
Right you talked about it quite a bit in terms of the the design changes you're making with.
Lower fluid and proppant.
And obviously seeing a lower cost benefit there in early rate benefit.
Just wondering is are you thinking in terms of maybe it's a trade off oh with longer term rates and.
Do you have enough data there to show that the economics are superior with the.
Though the lower intensity frac.
I think we have confidence that the returns will be higher which is the biggest driver.
No. We don't we don't have proof you had long term.
That the U. ours will be the same or higher.
But.
When we run sensitivities were still better off even if we saw a modest reduction in E U R.
Because the cost benefit yeah.
And the site and accelerated production off offset any other loss in that you are so we're happy with the with the returns that we're seeing from it.
Good thank you.
Our next question will come from Gail Nicholson Stevens. Please go ahead.
Good morning, everyone I'm, Brad and my answer to that question you that you talked about the importance going for kind of you know landing of the optimal landing zone in the Delaware. When you kind of look at the program to date, what do you think the percent of current execution has been landed and the auto optimal down and kind of how much improvement you think that you guys can achieve kind of over the next 18 months.
Oh, I don't know how to answer that percentage of wells, but we have very landing zones, even like within the Wolfcamp. A if you go back and look in time, you'll hear us talk about wolfcamp.
Upper Wolfcamp, a lower inside of that there's various bases that were that were moving around in.
And so so part of what we're doing we're doing in addition to the capital efficiency improvements is looking at all data in the basin and all operators and taking additional core data and doing some analysis of the of the core it's all designed toward.
Optimizing landing zones and completion designs.
So it's all work under and progress so I'd say that I think thats, a long way of saying, there's there's there's a additional room addition improvement to be had by narrowing down on and locking in on landing zones.
Okay, Great and my follow up is it back to the non productive time, you've mentioned you'd seen you know good improvement there can you quantify where the nonproductive time is today and where it wasn't for you and how it differs and the DJ versus Delaware.
TJ versus though they were similar.
You know in our in our.
In our in our DJ Basin, we had as much as three hours between stages in the worst case, and we've been able to get that down to you know to 30 minutes or so.
And so we had some we had similar kinds of inefficiencies in the in the Delaware program.
Those are the same kinds of things we've been chasing out in both places.
Great. Thank you.
Ladies and gentlemen, this will conclude our question and answer session. At this time I'd like to turn the conference back over to Brad Whitmarsh for any closing remarks.
Thanks, Allison again appreciate everybody joining us today should you have any follow up questions. Please don't hesitate to reach out to park camera or myself.
Hope everybody has a great weekend.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines.