Q3 2019 Earnings Call
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At this time, all participants are any listen only mode.
This call is being recorded I'd now like to turn the call over to Mr., Scott Cootey, Vice President of Investor Relations. Sir you may begin.
Thank you and good morning last night, we issued our earnings release operations report and forward looking guidance.
Those documents can be found on our website, Devon energy Dot com.
Joining joining me today on the color, Dave Hager, our president and CEO , David Harris, Our executive Vice President of exploration and production and Jeff written our our Chief Financial Officer.
Comments on the call today will contain plants forecasts and estimates that are forward looking statements under U.S. Securities law.
These comments are subject to assumptions risks and uncertainties that could cause actual results to differ from are forward looking statements. Please take note of the cautionary language and risk factors provided in our SEC filings and earnings materials with that I will turn the call over today.
Like Scott and good morning, everyone.
The third quarter is another one of exceptional execution for Devon across all aspects of our business.
Both strategy, we announced earlier this year to transform to a high quality multi basin U.S. oil company is working and is working quite well.
By sharpening our focus on our very best U.S. oil assets, the operating teams Devon or do webern results that are exceeding expectations.
Capital appreciation in cost of capital efficiency and cost reduction targets by a wide.
This trend up actually launches now well established over multiple quarters and evidenced by several noteworthy accomplishments year to date.
First our returns oriented focus and strong operational execution is translating into attractive rates of return.
Year to date, the fully burden rate of return on our capital program has exceeded 25%.
The cash return on total capital employed is also strong trendy well above 20%.
You are attractive returns we have delivered year to date are a function of the learnings we attain from appraisal work in prior years.
Deploying these warnings tour highway focus development program and 29 team, we've made substantial improvements in drawing and completion designs reduce cycle times and increased well productivity through enhanced subsurface target selection.
This step change improvement in execution has allowed us to raise our oil growth outlet outlook three times this year, while lowering our capital spending gardens.
We have also acted with a sense of urgency to materially improve our cost structure.
Our multiyear cost savings initiatives are now on pace to achieve more than 80% of our targeted $780 million an annual cost reductions by yearend.
Importantly, our operational performance and cost reductions yourselves have allowed us to generate free cash flow at levels that are ahead of plan.
Coupled with asset sales were now on track to generate more than $3 billion of excess cash this year.
With this abundant cash flow, we're delivering on our promise to reduce leverage and return capital to shareholders.
Our balance sheet is exceptionally strong one times net debt to EBITDA, we have increased our dividend by 13% or <unk> and are on track to reduce our share count or approximately 30% by yearend.
As you can see from these highlights Devon is executing as a at a very high level on every strategic objective underpinning our strategy.
Our unwavering focus on what we couldn't <unk> country can control is delivering compelling <unk> financial and operational results.
There are demonstrating a positive rate of change unique among our competitors.
Clearly, we have accomplished quite a bit issue year to date and there is plenty of excitement left in 2019 as our upcoming fourth quarter full of catalyst Richard events.
The Delaware a set to attain another meaningful step up in oil production due to several high impact projects coming online in Q4 headlined by our cat scratch fever 2.0 project.
You're also several good things happening in a powder River basin, we're raising our oil exit target right exit rate target and our Niobrara appraisal work is unlocking a new resource play for us.
The Eagle Ford will also be worth watching as Weve officially reestablished operational momentum with our new partner and expect to bring online more than 25 high rate wells in the fourth quarter.
And lastly, with regard to our Burnett sale process, the Bidrin and we continue to advance to process with interested parties, we expect to exit the Barnett by year end at a price is consistent with our view of the in terms of the intrinsic value of the asset.
Looking ahead to 2020, we have conviction in our multiyear plan and expect to progress the operational scale of our business in the highest return areas more portfolio, while delivering growth and free cash flow.
With a significant improvements in capital of patients, who we efficiency we have experienced across our asset portfolio. We believe we can achieve this strategic objectives of our multiyear plan was substantially lower capital requirements compare to the original projection. We wait we laid out in February of this year.
However, before I get into details of our 2020 outlook I want to share with investors our capital allocation priorities for the upcoming year.
As always devins top priority will be to fund maintenance capital requirements in a quarterly dividend.
Once this objective as Matt the next step in our capital allocation process is to selectively deploy capital at a high return projects. It was officially expand the cash for the business.
Importantly, our plan meets all these capital allocation priorities at a low breakeven funding price of $48 W.T.I. into 50, Henry hub pricing.
This ultra low breakeven pricing point provides us with a substantial margin of safety to execute on our capital program or navigating through the inevitable commodity price volatility we will encounter.
Sure this volatility dry prices higher we will remain disciplined and the benefits of any pricing windfall above our considerably base planning scenario will manifest itself in higher levels of free cash flow for shareholders not higher capital spending.
Conversely should we see price volatility to the downside we've designed our operating and plan to have the flexibility and agility to are appropriately react to changes in a macro environment.
Although we're still finalizing the details of our 2020 operating plan I can tell you. We're directionally planning on a capital program and a range of $1.7 billion to $1.9 billion.
This level of activity is expected to generate oil growth of 7% to 9% compared to 2019 on a retained asset basis.
We you account for the benefits of our ongoing share repurchase program oil growth rates jump into the mid to high teens on a per share basis.
As I've already emphasized our 2020 plan is designed to completely pound or capital requirements had an ultra low WT, our breakeven price of $48.
Furthermore, this conservative plan provides significant talk to the upside as we can generate free cash flow of $400 million at $55 WT pricing.
With our updated outlook I hope this one key message resonates debits capital efficiency continues to trend meaningfully ahead of our multiyear plan.
This is evidenced by our cumulative capital spending in 2019, and 2020, which is projected to declined by approximately 400 million or 10% less than the original plan. We outlined this February .
Importantly, our oil growth outlook over the same to your timeframe remains on track with the original plan.
Well. This is a great result, we're not content with a substantial progress we've made the management team in Devon is laser focused on optimizing returns and driving capital efficiency for our shareholders I expect to have more policy of updates on this topic in the near future.
And <unk> I'd like to address as a recent political rhetoric regarding drilling and fracking moratoriums on federal lands.
Although we believe substantial options go obstacles exists for such an idea to be enacted into law I do want to highlighted only 20% of our total company wide leasehold resides on federal land.
Within our core focus areas, our largest federal acreage holding resides in a powder River basin, which accounts for nearly 60% of our leasehold and that operating area.
In the Delaware basin, roughly half of our acreage as Pedro and our staff Eagle Ford and stack assets reduced reside almost entirely on private lands.
Regardless of how the politics of this issue will ultimately be resolved I do want to improve emphasize that we've been building a deep inventory of federal drilling permits in our highest confidence development areas within the Delaware in powder River basin.
Furthermore, our diversified multi basin portfolio provides the flexibility and the depth of inventory within each of our core basins to be nimble and quickly pivot drilling activity to private leasehold is highly economic and well positioned on the cost curve.
While our diversified portfolio positions us well to adapt to a scenario such as this we fundamentally believe that a basic notion of such campaign rhetoric as fraught with serious economic ramifications.
This proposal would unfairly harm the communities that financially benefit from our business activity as well as impact a broader U.S. economy from an inevitable spike in energy cost it would unnecessarily limit GDP growth.
That concludes my prepared remarks, I'd now like to turn introduce and turn the call over to David Harris.
David was recently appointed executive Vice President of exploration and production, replacing my good friend, Tony Vaughn, who is retiring from Devon after 20 years of service.
Many of you know David but for those of you who do not David has been a devon for more than a decade and is a seasoned and trusted leader who has been instrumental and strengthening Devin ended a world class used oil company. It is today.
David.
Thank you for the introduction, Dave together with our talented operating teams here Devin I look forward to continuing to execute on the operating strategy that will drive the net.
Financial growth and strong returns for the company.
Given our third quarter results and outlook, we continue to hit on all cylinders for my prepared remarks today I will cover the asset specific highlights that are driving this enterprise level success.
Beginning with our friends asset in the Delaware production continue to rapidly increase in the third quarter growing 59% on a year over year basis.
This strong production result was driven by a Leonard shale oriented program in the quarter, which accounted for roughly half of the 34, new wells that commenced production.
Based on learnings from prior projects, our operating teams have refined lender development spacing at around six wells per drilling unit, primarily targeting the leonard be interval.
Execution of these Leonard developments was excellent.
Results have exceeded type curve expectations with 30 day rates, averaging 2200 Boe per day of which 70% was oil.
At an average cost of center and a half million dollars a well the returns from this leonard activity rank among the very best projects, we have executed this year.
Looking ahead to set up for the Delaware Basin in the fourth quarter is very strong.
Our diversified development activity across all five of our core areas in the Stateline area continues to progress right on plan positioning the Delaware for another quarter of strong oil growth.
In the aggregate, we expect to bring online more than 30 wells in the fourth quarter with a top catalyst being our 10, well catch scratch fever 2.0 project.
Catch scratch 2.0 directly offsets the record setting phase one project immediately to the southeast in our World class taught area.
While geologic mapping indicates that this then spot ends a bit to the east we do expect catch scratched 2.0 to be special and more prolific than the typical second bone spring project.
Lastly in the Delaware another noteworthy trend I would like to highlight as our improving capital efficiency.
In the most recent quarter, our drilled and completed feet per day metrics in the Wolfcamp improved 45% and 65% year over year, respectively.
This positive trend is very important as we expect the majority of our drilling activity to target the Wolfcamp formation next year.
Steadily improving cycle times and costs will provide capital efficiency momentum heading into 2020.
The next asset I would like to discuss is the powder River basin, one of the top emerging oil growth opportunities in North America.
In the third quarter are fulfilled field development activity targeting the Turner Parkman, and teapot formations and our Super Mario area drove oil production, 25% higher year over year.
With this drill bit success, we're raising our 2019 oil exit rate growth target in the powder river to more than 70% compared to 2018 up from our previous target of greater than 50%.
This strong growth is accompanied by structural improvements to our capital efficiency as we attain operating scale in the play.
Specifically with the Turner formation, our top development target in 2019, we have achieved capital savings of greater than a million dollars per well or nearly 20% compared to last year.
Another critically important initiative underway in the powder River is the delineation of our Niobrara shale potential in the basin.
Our 200000 net acre Niobrara position in the core of the oil fairway possesses repeatable resource play characteristics with the potential to be an important growth platform for Devon in 2020 and beyond.
Over the past year industry permitting has accelerated more than 30, new Niobrara wells have been brought online around our acreage position in converse and Campbell counties.
Specifically for Devon, we are methodically focusing our delineation efforts in the southwest quadrant of our acreage called Atlas West, which has delivered the top oil rates in the basin.
To date, we have brought online eight operated wells that have averaged 30 day rates as high as 1500 Boe per day with a 90% oil mix.
Further progressing our confidence in this play our two spacing test we commenced production on during the quarter an Atlas west.
Spacing tests have shown positive results for the commercial potential of three Niobrara wells per section and the ability to develop the niobrara independently of the deeper Turner interval.
By the time of our next call February we expect to have several more appraisal wells online further delineating our Atlas west acreage position.
With positive operating results, we've obtained to date, coupled with several encouraging industry data points. It is likely that the Niobrara will compete for increased capital allocation in 2020 with potential for us to double our drilling activity.
And finally, our Eagle Ford and stacked assets are successfully fulfilling their respective roles in our portfolio, providing more than $600 million or free cash flow over the past year.
In the Eagle Ford play the key message I want to convey is that we have officially reestablished operational momentum with our new partner in the play.
With peak completion activity for the year occurring in the third quarter. We expect a strong production response in Q4 with more than 25 Eagle Ford Wells scheduled to come online.
The impact from these high quality wells is projected to increase our Eagle Ford net production to between 50 and 55000 Boe per day in the fourth quarter.
We're still working on details for the 2020 plan with our partner, but our intent is to target an average of three to four rig lines.
This level of activity would maintain our base production profile and advance our infill and redevelopment work in the lower and upper Eagle Ford, while generating meaningful levels of free cash flow for the company.
And lastly in the stack our infill development program continues to deliver strong operational results.
Our recent Meramec development spaced at four to six wells per unit or exceeding type curve expectations, and we have lowered well costs by as much as 30%.
We still have a deep drilling inventory in the Overpressured oil window of the play given recent weakness in gas and NGL prices, we continue to reduce activity in the stack.
In fact, we recently dropped to zero rigs in the play as higher returns currently exists within other oilier projects in our portfolio.
Well stack activity may be down it is not indefinitely out we're actively working to rejuvenate returns in the play to more competitive levels within our portfolio by lowering our DNC costs and through evaluation of partnership and Drillco structures.
Well I have nothing specific to announce today I can confirm that we're encouraged by ongoing discussions that are taking place with well capitalized counterparties.
And with that I'll now turn the call over to Jeff.
Thanks, David I'll spend my time today discussing the progress we've made advancing our financial strategy and detailing the future benefits of our plan.
Good place to start is by highlighting our financial performance in the quarter were Devon earnings from continuing operations totaled 35 cents per share exceeding consensus estimates operating cash flow for the quarter was $597 million, a 22% increase compared to the year ago period, Despite lower benchmark pricing.
This level of cash flow exceeded capital spending resulted in free cash flow a $56 million for the quarter. This strong financial performance was underpinned by oil production that exceeded the top end of our guidance per unit LOE, we cost improving by 19% year over year, DNA and financing cost that were reduced by more than 25% versus the.
Previous year and capital efficiencies that are trending well ahead of our plan.
Turning to the balance sheet over the past three months, we've made significant progress strengthening our investment grade financial position.
In the quarter. We retired 1.5 billion of senior notes, reducing our total debt to 4.3 billion and net financing costs by 25% year over year strategically this debt reduction activity focused on near term maturities to completely clear devins debt maturity runway until late 2025.
We are carefully evaluating Nick next steps in our debt reduction program as we keep a close watch on interest rates in credit spreads overall, we are well on our way to achieving the 3 billion dollar debt reduction target.
Strip prices, where they are today, we expect our net debt to EBITDA ratio to trend towards the low end of our one to one and a half times targeted range as we execute on our multiyear plan.
In the third quarter. We're also very active with our share repurchase program completing 550 million of share repurchases in the period. Since the program began in 2018, we've repurchased 147 million shares at a total cost of $4.8 billion and we're on pace to reduce our outstanding share count 30%.
By year end.
In addition to our share repurchase activity. We're also returning cash directly to our shareholders through our quarterly dividend, which we've increased by 50% since 2018.
Year to date share repurchases in dividends totaled over $1.7 billion, representing a cash yield to shareholders of 20% when compared to our current market capitalization. This follows. This follows repurchases in dividends in 2018 totaling $3.2 billion worth 35% yield to shareholders.
Moving forward, we expect additional cash returns for our shareholders as our multiyear plan builds momentum we will continue to use it the dividend and share repurchases to deliver free cash flow to our investors as Dave touched on in his opening remarks. Our 2020 plan is set up for attractive per share growth and free cash flow generation of 400 million dollar.
There is at a 55 dollar Debbie T.I. price deck to put this in the context the free cash flow, we expect to generate in 2020 is equivalent to 5% of our current market capitalization. We believe this free cash flow yield is very competitive with other sectors in the broader S&P 500 index that possess valuation multiples far in excess of death.
And supporting the continuation of our share repurchases into the future and with that I'll turn the call back over to Scott. Thanks, Jeff will now open the call to queuing <unk>. Please limit yourself to one question and a follow up this allows us to get to more of your questions on the call today with that operator, we'll take our first question.
As a reminder to ask a question you will need to press star one of your telephone.
And your first question comes from the line of or in General from JP Morgan. Your line is open.
Good morning, I was wondering if you could discuss.
Your plans in the Delaware Basin for 2020, I think this year, you're going to be placing underproduction about 117 wells I wanted to see if you get some thoughts on some the program next year lateral lengths and.
A number of wells and where do you see well costs on a per lateral foot basis in the Delaware.
I'll start this offering it's a bit premature for us to provide any specific guidance as far as a the amount of wells or even the cadence of the wells for 2020, we'll keep it to the preliminary guy that we provided at a high level in our earnings materials, but that being said with regards to our allocation to the Delaware, It's certainly going to be our top funded asset by a wide margin.
Fortunately you would probably directionally expect that level funding to be similar to what you're seeing this year.
And obviously the the PRB in the.
Eagle Ford to be a top funded assets as well within our portfolio and as always with the extended reach laterals, we continue to push towards.
Having longer laterals every year and if you saw for recent operations report.
We're pushing towards 10000 in virtually every area that we operate so that's that's a good news story, where the capital efficiency continues to.
Improved.
Were earned as Dave I May just make one more comment on just the.
The capital efficiency or the cost reduction side. If you go to obviously sard 16 into and operations reported.
It really shows how we're continuing to get.
Drawing to completion efficiencies. So we think that are leading the industry and cost per foot drilling and completion costs per foot, but we're not done and I can tell you the way, we've guided and built into our 2020 guidance.
We are still saying that we think there's opportunity to do even better and we're working on some things and I have an early results at back that up.
Great and just my follow up.
On slide five you guys present here at your updated guidance on the cost structure.
Maybe for you Jeff I was wondering if you could give us a sense of how you expect the cost structure to trend for the new Devon and 2020 and maybe also provides some thoughts on how do you think realizations are differentials will trend for the three main the product groups.
For the new Devon.
Yeah, you bet, Yeah, I would say generally speaking we continue to expect per unit costs to trend lower as we move into 2020 really across the board on from an L. OE in a DNA standpoint, obviously the financing cost piece is going to be depended on the timing of our of our debt repurchase but again, that's another area, where we would see.
You know continued reduction in our in our cost structure as we move into 2020 as it relates to the realizations I.
I would as a general statement I would say, we'd expected to look a little bit like like this year. There is obviously it looks like there is going to be continued pressure on wahab pricing coming out of the Delaware, but with the hedges that we haven't place as well as some of that the takeaway options. We have there we think we're going to mitigate that to some degree.
Oil pricing you know coming out of the Delaware with a really good about theres, obviously plenty of pipeline capacity there to to move the product.
And we generally have a pretty balanced approach they are getting about 50% of our production is exposed to Gulf coast pricing and the remainder would get exposed to that Midland area pricing, which right now looks pretty positive it's actually trading at a premium.
Relative to Wi Fi.
Great. Thanks, a lot.
Your next question comes from the line of Jeanine ways from Barclays. Your line is open.
Hi, good morning, everyone.
Morning Genie.
So my question is on tiny tiny capital efficiency in the corporate breakeven.
Reported pretty low 2020, corporate breakeven of $48 Debbie.
And I believe the original 2018 breakeven was around 46.
That was that higher gas and NGL prices. So I'm, just trying to get a sense of the year over year change and capital efficiency on an apples to apples basis. So if you were to normalize for pricing what's the change in the corporate breakeven in 2020 relative to this year.
Well I don't know if I have an absolute number normalize for pricing I think the easiest way to think about it is look at slide nine and ADAC, where we're saying we're delivering all of the.
Oil growth that we had originally planned over the two year timeframe, but yet.
We're doing it for $400 million less capital versus our original plan Im. So obviously on a normalized basis. If we went back to the original prior said.
It would be below 46, I don't know we have an exact number what that may be yesterday. This is Jeff I actually don't have the absolute number but Dave described it well and obviously the biggest driver that as the capital efficiency that were seen in the Delaware and really across the board in each of our different areas, but the Delaware. Obviously is the biggest component of our cap.
I will spend and that's the biggest driver of that capital efficiency that we're seeing on a multi year basis.
Okay, and then my follow up if I could just dig into your last comment about on the improvement you mentioned, it's mostly getting driven by the end Delaware, but how much of it is also on for 2020, driven by just taking capital out of the stack versus any well cost reductions there any cyclical factors and I'm not sure.
I think your clever breakeven is on a hedge basis.
Well.
Yes, Ginnie Thats correct. It does include the benefit of hedges, which for 2020 is relatively minor at this point, David Harris I figure answer that yeah, Geneva in terms of capital efficiency to Jeff's point, we're seeing a lot of progress across the board.
In the Delaware specifically.
On the drilling side, we're we've changed our Wellbore design, we have gone to a slim whole design that we've modified.
To a slightly larger whole, that's that's allowing much faster drilling times.
On the completion side, we continue to relentlessly attack nonproductive time, and flat time, mobing equipment around and when we're doing zipper fracs and as we talk to you about before on the facility side of the move from from more complex and customize facilities to more standardized and modular designs as driving a real.
Driven a real step change in our performance there.
These improvements really aren't just limited to the Delaware, though.
The Rockies, we continue to see.
Cost reductions and expected to see material further cost reductions as we've highlighted in the Turner.
We've had a 20% improvement year over year.
And continue to believe that we're going to see similar rate a change in the Niobrara as we continue to de risk that position and move more into development mode.
In the stack, we're seeing capital efficiency improvements from.
More efficient infill spacing results and improve stimulation designs just on the completion side alone we've seen a 15% decrease in our costs since the beginning of the year.
So we're really encouraged by that and then obviously working with the new partner in the Eagle Ford.
You saw the ops report, we've driven somewhere around $1 million per well out.
As we de bundled.
Services and worked with more efficient vendors and applied best practices from other parts of our asset base to that asset go forward. So we feel good about the capital efficiencies, we're seeing across the entire portfolio.
And really want to make sure you had appreciate it's not just limited to what we're doing in the Delaware, you're the only thing I'd add Janine as we are allocating.
Significant amount of capital to the Delaware and last to the stack, but don't count to stack out.
I see some work to we're doing internally in the stack, we're driving down to well costs. We are doing in some outstanding technical work in there and it's just because of the high quality of our portfolio that we are allocating more to the Delaware, but the stack is still there has not far away from getting funding.
And it's going to be a significant part of our portfolio for a long time ago, you're going to see capital allocated to stack in future years, and there's going to be good strong returns.
Interesting. Thank you I appreciate the detail just fine.
Your next question comes from the line of Bryan singer from Goldman Sachs. Your line is open.
Thank you good morning.
Good morning, Brian .
Philosophically when you think about production growth of 7% to 9% to what you would see as a more normal oil growth rate of current commodity prices hold or do you see acceleration piggybacking on some of your comments on further cost reduction three allocation to stack or or other areas.
Well I think the main thing to understand as a we have the capability and a resource that we can deploy capital and generate strong returns at various growth rates. So we aren't really limited.
By the amount of resource that amount of opportunities with the amount of growth. It is really trying to maximize the capital efficiency of our program as well as to generate.
Competitive growth along with competitive free cash flow yield and so we're trying to balance all of those variables given that we think as a as a kind of need is appropriate for us to target a high single digit growth rates and mid single digit free cash flow yields and that allows us.
To invest in very high return opportunities. So we think at this point that's the right decision.
Obviously were opened a feedback.
From our shareholders on whether they think that's appropriate as well.
But we think we think it's a strong program. This underpinned by very high return projects and we do again, how the flexibility to grow at.
Higher or lower rates, but we have no shortage of opportunities due to do that for a long time.
Great. Thanks, and then my follow up is on your Ops report the slide number 18, you talk about the visibility of several hundred.
Inventory locations in the Todd area, you talked to catch great Cat scratch fever, 2.0, and prepared remarks can you talk to the characteristics of how the costs any oil you are from that broader inventory compare versus what you drilled in 2019, and what you expect to drill in 2020.
Brian This is David I think we expected to continue to be an important growth driver for the foreseeable future. You've obviously got a highly charged reservoir there with stacked pay you as we've highlighted on cat scratch 2.0.
We do see the pace in a bit to the east and so we wouldn't expect.
Copycat results all the way across it but we think these are going to be some of the most compelling projects.
In the lower 48 for the foreseeable future.
And can you remind the spacing assumptions that you have built in and in that area.
Yes.
Brian we're going to hand, this over to John rains, who heads up our Delaware Basin business unit.
Yes, Brian for the Todd area will start in the Leonard So we're just delineate the Leonard at this point.
Moving from appraisal into development.
In other parts of the basin, we've seen six wells per section and that's what we started with here, but we've got a line of sight upside to potentially eight wells per section in the winter.
Moving to the second bone.
Historically, we've developed this on four wells per section and that's what we've done from central Todd going East.
This is a bit of the geologically complex area as we move west in southwest and Todd.
We're exploring six wells per section oxy actually offsets to the west and they've been successful at six wells per section and then we've only just begun appraisal in the Wolfcamp here.
We're testing multiple landing zones, we've actually tested three different landing zones in the upper Wolfcamp.
It's safe to assume that we feel good about two landing zones at four wells per section.
With the with the strong chance of upside to three landing zones at 12.
Great. Thank you very much.
Your next question comes from the line of Subash Chandra from Guggenheim Partners. Your line is open.
Thank you good morning, everyone.
Just wanted to clarify the return of capital commentary make sure I understood correctly, what to understand sort of how you split the buckets.
Debt.
Share buybacks and dividend growth within without the Barnett sale in particular, I think a the presentation alludes to more debt reduction by yearend.
Is that a.
Presuming the Barnett sale and then how do we split the returning capital to share buybacks beyond that point.
Yes. This is Jeff Yes, I know it does not include the Barnett proceeds. So we are we at we've already obviously executed on 1.7 billion of the 3.3 billion dollar debt target that we set earlier this year.
We've got the cash on the balance sheet today to go ahead and execute the remainder of our of our $3 billion target. However, what we've seen happened over the last several months as interest rates go lower and the cost of debt go higher.
And so we're going to be mindful of that and be opportunistic as we look to repurchase debt in the market. So we don't need those Ah Theres Barnett proceeds obviously to accomplish our debt targets going forward beyond that that will allow us to utilize the proceeds in the Barnett for additional share repurchases along with obviously the dividend that you highlighted.
And certainly the free cash flow that we expect to generate next year.
That will have the potential to be devoted to further share repurchase program.
Got you, Okay and a question that you know I think.
Operators.
Seeking to monetize water assets seems to be thing to do.
You've highlighted 40 saltwater disposal wells et cetera, I'm just curious if that is something you might do and what capacity in capacity utilization might be at the moment.
Yeah. This is Jeff that's absolutely something we've looked at and we'll continue to monitor we feel pretty good with with our set up in the Delaware today, we like having control those assets in the low cost that it brings to our <expletive> .
Our cost structure going forward.
But it's certainly something we've been monitoring and watching and and should they are right opportunity arise, it's something we would consider but but frankly, where we sit today, we feel pretty good about are set up and certainly the cost structure that we've got.
Could you share by any chance see I'm sort of the disposal capacity and the utilization levels you might be running.
Yeah, I think I think roughly 40, we've got 40 salt water disposal wells out in the space I think if you look at slide 15, we've kind of highlight some of that some of the detail there and about eight water reuse facility. So.
Capacity of 120000 barrels.
Is the throughput capacity of this facilities.
Okay terrific. Thank you.
Your next question comes from a line of Devon Mcdermott from Morgan Stanley . Your line is open.
Good morning.
Good morning, Devon.
My first question, Dave is actually following up on your response one of the questions earlier around the stack you noted that it's close to competing for additional capital and will likely receive it in future years I guess first of all as we think about 2020 with you now it's your rigs there what's envisioned in terms of.
Cap allocation there if any in the preliminary 2020 plan that you provided and then as we think about the outlook for the stack going forward, assuming no change in commodity prices gas for Ngls I guess, what would you need to see in order to make it competitive within the overall portfolio and start allocating more capital back.
Well, there's very little capital allocated in the current plan in 2020 is really more carry and capital from from 2019.
Oh, we're working to number of initiatives is not just on the price side that we.
Certainly a little bit higher gas and NGL prices would would help.
We're also oh.
Our teams are doing some outstanding work on that on the cost side on the drilling and completion costs and driving down those costs. We're also working on potential.
Joint venture type opportunities there that could bring in some capital to drive higher capital efficiency into it. So there theres several different angles at work there were working this problem in order to allocate capital into into future years, and obviously, we're being patient because we have such a strong.
Folio Oh, you know when we talk a lot about the Delaware, but I think when we need to talk about the powder also and as a success or Avenue Niobrara, and how that's going to drive more.
More capital, there and higher returns and very high returns here as well with the success, we're having so and I can tell you into in the Eagle Ford also with the or new partner BP. There are very excited about what their or BPX are very excited about.
This asset I think they see it is what are key cornerstones of the acquisition. They did from BHP into one they probably want to put a lot of capital too early on so we just have a lot of high return opportunities here.
In front of us So we're just being patient to work out some of these other issues and then.
I'm confident we're going to do it and capital come to the stock when the appropriate time comps.
Got it makes it can you comment I'm.
Sorry, just just a few more follow up specific thoughts on that I I would point out as we've talked about this quarter are lighter space until projects are performing really well exceeding both type curve and and cost expectations. We do have a significant amount of inventory remaining.
In the heart of the play so.
We we do believe we still have a lot of economic resource there to develop as Dave said, we've got a very high bar internally with the portfolio we have.
But we're going to continue to try to bring those brings value of those opportunities forward.
Got it can you comment on the production profile or decline rate you've assumed through the 2020 guidance or is it still too early to say given some of the uncertainty there for the powder, specifically I'm sorry for the stack specifically.
Yes, and then once again will.
Refrain from providing that at this point in time, just because we saw some work to do on that front, but generally speaking the last disclosure point, we've had on the stack is on the first year PDP decline.
It was in the high 20% on a view we basis and.
As oil basis, it was high 30% range. So we'll recalibrate that number in conjunction with our.
Reserve outlook for reserve report and our activity outlook for and have more specific update for you here in February .
Got it thank you very much.
Your next question comes from a line of Neal Dingmann from Suntrust. Your line is open.
Well, thanks for taking my call Great update on the Eagle Ford My question is around that play.
On the for Q1, the 25 wells and obviously the growth you have there.
I know you don't have full 2020 out but just how are you considering that play is more of a still in the near near term than a growth driver or is it more stable production with it being more of a free cash flow generator.
Neil This is David I think the way, we think about it within the context of our portfolio is the ladder.
It is an important free cash flow generator for us and we believe we can maintain a profile there that's that's flat to some some some slight growth probably.
We're we've regained operational momentum with our partner, we're going to bring on.
A big package wells in Q4.
And then as we move into 2020, we've talked about stabilizing somewhere around a rig count a three to four years.
But we do you still have quite a bit of resource in place and at our testing and bill and redevelopment concepts.
As well as things like the Austin chalk so.
We believe there's still a lot of good work to be done in the play now just to reinforce that what we're finding there's still a lot of hydrocarbon in place in a lot of reservoir pressure there. After our initial development activities take place and so we're finding success with.
Staggered wells within the lower Eagle Ford as well a staggering them up in the upper Eagle Ford between the lower Eagle Ford completions, and so it's exciting. It's a there there is just a great resource with a lot of pressure and.
A lot of opportunity to look Cox remaining and then the Austin chalk on top of its probably a little less certainty as to how big that's going to be a at this point bore.
Changing more to a linear gel type design on our completions air from slick water and we're optimistic that that can compete also.
Well sort of sounds like led running room, and then moving over equally as positive sounds like to me I'm looking at slide, particularly on slide 20 in the now you've you've had some it really interesting spacing tests. There I'm just wondering after typically the two successful wells you've had there.
Maybe could you just talk about has your thoughts just on overall spacing or at least in that area. How that's how that's changed now after the success.
You bet Yeah, you know what are the things that we're excited about in the Niobrara is that we're seeing consistent results across a really large area. Both from our results as well as a from offset operators and you think about the 200000 acres that we talk about in our Atlas.
Great and east area.
We have currently we talked about the spacing test at three wells per section.
We have plans to test for well per section spacing, we've seen offset a industry.
Participants testing up to six and seven wells per section.
And so we're going to learn more here throughout 2020, that's going to inform.
You know with success, what we believe will be development mode begin 2021.
For the for the Niobrara for Us.
Very good thanks for the details guys.
Your next question comes from the line of Charles Meade from Johnson Rice. Your line is open.
Well, we gave to you in your your whole team there I actually I have a question for ER for Dave, but but I'm going to pick up on Nielsen would that that Niobrara.
First.
It's given us up kind of this cartoon log on on 20 and it looks like the that be section is more of a classic or carpeted versus the.
I guess the overall shale package is that the case it and does that tie in to two your spacing there, but just being your three or four across a unique.
Well you know there's a couple of what we think are a really great advantages that we have in and around our acreage position relative to.
Other areas and the powder River basin. The first is from a thermal maturity standpoint, we are clearly in the oil window throughout the geologic column here and that varies so we've done a thermal maturity mapping throughout the basin and that Verizon as you go further north with some other operators you're more in a day.
Assay window and the Niobrara.
The other thing that you're pointing out Charles is yes, you do have more of a chawki interval in this particular part of the base and within the Niobrara and the Chawki interval as well give some brittleness and that interval is developed around our acreage position.
In and around some other or some other acreage immediately around us but has not developed everywhere in the powder.
So we think that brittleness so were done exist other areas us a little more ductile and done frac as well other places it really fracs well on our acreage. So we think that and that's one caution I'd give everyone about comparing our Niobrara results everybody else's Niobrara results too because we do have these unique advantages of being in the oil window and have this choice.
Alky interval in there that.
Frankly, we think ours is going to be better because of these geological characteristics and so far as turn out to be true.
That's great detail, Dave and then I could go back to your your prepared comments about up about this this unfortunate properties you're about about federal acreage.
And I know you talked a little bit about about some of your kitchen see about being able to go onto onto private lands, but.
You might not be spreads new I agree with you it's bad idea, but.
National politics, or more more like a demolition derby were while things happen and so.
I Wonder if you could talk more about.
What are the obstacles to to implementing the off Frac banner or us a.
Cessation of permits erad.
What timeframe that would play out over in your contingency planning.
Well you can rest assured that we've done a lot of background legal work around this issue and I don't think as probably appropriate to go into the details around that work on his call, but I think that at a high level. We would say that we thinks it is really fraught with serious.
Oh legal ramifications the ability to an act that in a in a short term basis and I think even more importantly, though obviously is we just think it is going to unfairly harmed.
Communities, where we work the stage, where we work we work in and in an incredibly environmentally responsible manner.
Our own company does and our industry does and all this is going to do is.
Shift of the demand for the oil is not going to change.
It's there on a worldwide basis and all this would do is to shift the.
Production two areas of the world that where there are not as higher environmental standards followed.
And so we just think of it.
It is obviously going to be impactful very impactful to the U.S. economy.
And as well as our National defense. So we take US yes, obviously, a bad idea from a from a number of fronts and it's not good for the U.S., it's not good for the world and again I'm not going go through the details of the legal issues, but we've studied a pretty deeply and we think there's.
The significant timeframe to any do anything from a purely legal standpoint, obviously from a regulatory standpoint.
There's a possibility to slow things down, but weve, obviously been thinking through that and we have a deep inventory permit to help mitigate that.
Alright, Thanks for that artist I think the key point of all this as we have a clear path forward. If this were to take place and we've been thinking about it.
Got it.
Your next question comes from the line of Jeffrey Campbell from Tuohy Brothers. Your line is open.
Good morning, and congratulations on the quarter.
Dave I was just wondering slide 17 can you add some color on the drivers.
To your capital shift to the Wolfcamp since your lender to bone spring results consistently been so I didn't quite catch that could you repeat that Jeffrey I'm, sorry, sure on slide 17.
Can you add some color on the drivers of the multiyear capital shift to the Wolfcamp since your Leonard and bone spring results consistently been so successful.
This is David I think you were seeing great results from from all three of those those made intervals, but I think at the simple answer is really the capital efficiency, we see.
From development of the of the Wolfcamp formation.
Relative to that the depth of resource and inventory.
We have in the various landing zones of the Wolfcamp. Those two things combined I think are really the main drivers of what you're seeing.
From some of that internal shift of where you'll see that capital deployed within the Delaware.
Okay, Great. That's helpful and just I was just was wondering if you could quickly given some of the technical differences between at Eagle Ford Refrac versus a redevelopment oil.
Yeah. It's a great question actually asked the team that that the lingo is a little bit is little bit hard to follow if you think about a refrac. It's just a traditional refrac where.
Your your accessing stranded reserves there typically what we do the preferred approach we've tried a few different approaches.
But we pump a line or re frac there to go in and re stimulate near Wellbore to access.
Those stranded reserves when we talk about redevelopment those are those are new wells.
That would be drilled in the upper Eagle Ford. So if you think about what we're doing today in our primary development sections were co developing the upper Eagle Ford a with the lower Eagle Ford.
In units that were delivered prior to that shift we've got undeveloped upper Eagle Ford and so we're going back in.
And essentially in some sense kind of Infilling Upper Eagle Ford Wells and those are the wells that we talk about as redevelopment.
Okay, great. Thanks for the clarity I appreciate it.
Your next question comes from a line of Dayville, sorry, David Heikkinen from Heikkinen Energy. Your line is open.
Good morning, guys. Thanks for taking my question.
Kind of thinking through and it seems like given your higher 19 powder River basin exit rate than.
You are shifting more capital to your Oilier powder, but definitely shifting less capital to your left oily stack that.
You've really got some increase to your 2020 oil CAGR in your hip pocket.
The kind of flowed that through the model.
I'm trying to lead the witness to 7% to 9% or higher but seems like that.
That have a lay up.
Oh I don't know you know I don't know I'm guard I'm about to throw a sports analogy out your better not sure. The right. One data you know, it's it's a lay up moving over there maybe a.
Maybe a 15 foot jump shot you know how to long or if not along three pointer.
Mr. James Hardiman.
There you go quite an S lack of I'll pass, but I mean, obviously when we feel confident we've exceeded our expectations. The last few quarters, So where we feel really good about the ability to execute on that.
And then.
Just in the stack or can you remind us how much of your capital is outside operated and are you non consenting your current plan or thinking about non consenting in 2020.
Well there there's a the outs I don't have exact number the guys will have four here, but is typically run higher than it has in any and any other business units.
But do come out of the outside capital has actually are OBO capital has been declining this year significantly as other people move activity.
Outside of the.
Basin, as well and and typically we we try to find companies that are willing to participate in those projects. So we sell down our interest and knows versus non consent and so we're trying to get some return on on that falls as well and David just specifically, we had about $8 million of non up.
Capital in the third quarter in the stack and it from a year to date perspective, it's been about a 30 million or so although we have seen downward pressure on that as Dave highlighted throughout the year.
Really not that much.
And there are no further questions at this time Mr., Scott coat Cody I turn the call back over to you for some closing remarks.
Well I appreciate everyone's interest and evidenced in Devon today, and if you have any further questions. Please don't hesitate to reach out to the Investor Relations team, which consists of myself and Chris car. Thank you and have a good day.
Ladies and gentlemen, this concludes today's conference call. Thank you for participating you may now disconnect.