Q4 2019 Earnings Call

[music].

He 19 Onest earnings call. Today's conference is being recorded at this time I would like to turn the conference over to Andrew dialects. Please go ahead Sir.

Thank you and good morning, and welcome to one Oaks fourth quarter and yearend earnings call.

This call speaks gets cast lives and a replay will be made available.

After our prepared remarks will be available to take your questions.

A reminder, that statements made during this call the might include one oaks expectations or predictions.

Should be considered forward looking statements and are covered by the safe Harbor provision of the Securities Act 1933 34.

Actual results could differ materially from those projected in forward looking statements for discussion of factors that could cause actual results to differ please refer to our SEC filings.

Our first speaker this morning, as Terry Spencer, President and Chief Executive Officer, Jerry Thanks, Andrew Good morning, and thank you all for joining US today as always we appreciate your continued trust and investment in one okay.

Joining me on today's call is Walt Hulse, Chief Financial Officer, and Executive Vice President strategic planning in corporate Affairs, and Kevin Burdick, Executive Vice President and Chief operating Officer.

Also available to answer your questions are Sheridan swords, senior Vice President natural gas liquids, and Chuck Kelly Senior Vice President natural gas.

2019 was an outstanding year, a year of project execution and record setting safety performance for one oak.

Positioning ourselves for exceptional growth in 2020 and 2021.

Yesterday, we announced fourth quarter and full year 2019 results announced our 2020 guidance and provided a 2021 outlook.

We also announced three expansion projects that will further strengthen one oaks position in the Williston and Permian basins and increase the needed natural gas processing and NGL transportation capacity for customers. It is important to point out that these high return projects build off of our existing.

Assets. These projects include the Demicks Lake three plant in the Williston Basin.

The full expansion of the help treat pipeline to 400000 barrels per day.

And the fourth expansion of the West, Texas LPG pipeline since October 2017.

Our gross program, just providing critical natural gas and NGL infrastructure to our customers, including assets to help significantly reduce natural gas flaring in the Williston basin and provide increased connectivity all the way to the Texas Gulf Coast.

Upon completion, our announced projects will expand the backbone of our NGL business and we'll add processing capacity to further strengthen our position as a leading midstream service provider.

As for project updates, we announced that L. Creek was completed in mid December.

Demicks like one and two were completed in October 2019, and January 2020, respectively.

And the first phase of the M. before fractionator was completed in late December.

Kevin will provide more color on the projects that are slated for completion here in the first quarter.

Our last earnings call in late October I made a comment that 2021 is setting up to be another year of double digits growth.

With many of our projects being completed this year and into next year, we're confident in our 2020 earnings outlook.

Adjusted EBITDA, increasing approximately 20% compared to our 2020 guidance midpoint.

With that and I will turn call over to Walt.

Thank you Gerry.

One of those 2019 net income totaled $1.28 billion were $3.07 per share.

And 11% increase compared with 2018.

In 2019, adjusted EBITDA told it totaled 2.58 billion applied for 60% increase year over year.

Natural gas liquids and natural gas volume growth.

Higher average fee rates and increased transportation capacity contracted all contributed to a strong 2019 performance.

The natural gas gathering and processing and natural gas pipeline segments ended the year with adjusted EBITDA increases of 11% and 12% respectively compared with 2018.

Exceeding the high end of the 2019 guidance range in both segments.

The natural gas liquids segment, adjusted EBITDA increased 2% compared with 2018 about 4% below.

Below the low end of the 2019 guidance range due primarily to narrower than expected NGL price differentials.

Distributable cash flow for 2019 was $2.02 billion up 11% compared to 2018.

With a healthy full year dividend coverage of 1.38 times, we also generated nearly $560 million of distributable cash flow in excess of dividends paid in 2019.

[noise], our annual dividends paid during 2019 were $3.53 per share.

10% increase compared with 2018 inline with our previously stated guidance.

And in January the board of directors declared a dividend of 93, and a half sense or $3.74 per share on an annualized basis.

Also an increase of 9% compared with the first quarter of 2018.

Our December 31, net debt to EBITDA on an annualized run rate basis was 4.8 times, we continue to expects to be at four times debt to EBITDA run rate in late 2020, or early 2021 with de leveraging continuing thereafter as volumes.

An additional projects come online.

We ended the year, having no borrowings outstanding on our $2.5 billion credit facility and $220 million of commercial paper outstanding.

[noise] as Jerry mentioned with yesterday's earnings announcement, we provided detailed 2020 financial and volume guidance and a 2021 outlook.

2020 guidance includes increases in our earnings per share, an adjusted EBITDA midpoints of 16% and 25% respectively compared with 2019.

We expect double digit year over year earnings growth in our natural gas liquids, and our natural gas gathering and processing segments of 15% and 11% respectively.

Our natural gas pipelines segment had a strong 2019, and we expect another solid year of performance for the segment in 2020.

Key drivers to achieving our 2020 financial guidance expectations include volume growth expected from the old Creek pipeline and the Demicks Lake processing plants.

And John to abuse funds from the Arbuckle two pipeline the M. before fractionator and the second West, Texas LPG expansion.

All projects that we expect to be completed here in the first quarter.

Our 2020 growth capital guidance range of 2.25 billion to 2.73 billion is a significant decrease compared with our peak capex spend in 2019 and incorporates the projects we announced yesterday.

As a reminder, what we call routine growth capital such as well connections and plant connections is included in this number.

Our 2021 outlook of an approximate 20% increase in adjusted EBITDA compared with the 2020 guidance midpoint is driven by continued volume growth on L. Creek, resulting from increased volumes from plants conducted in 2020.

The Bakken NGL pipeline extension.

There are three expansion.

Volume growth in the Permian basin in the Gulf Coast from the completion of the M.B. five fractionator in the third and fourth expansions on West, Texas LPG pipeline will also contribute to the 2021 increase.

These project completions. This year in early next year total capital expenditures are expected to decrease significantly in 2021 relative to 2020.

I'll now turn the call over to Kevin for a closer look at each of our operating segments.

Thank you all 2019 was an impressive year with strong producer activity across our operations driving NGL raw feed throughput and natural gas processed volume increases of 7% compared with 2018.

We expect volumes to continue to increase in 2020, and our earnings to remain more than 90% fee based as Terry said, we completed our Demicks Lake to plant in the Williston Basin in January and expect to complete three additional NGL projects by the end of the first quarter.

Overall, our projects are on time and on budget positioning us well for continued growth as volumes on these projects ramp up.

Let's start with a Rocky Mountain region, which includes the Williston and powder River basins.

Producer activity remains strong in both the Williston and powder River basins, North Dakota continues to see natural gas production of more than 3 billion cubic feet per day in the basin wide rig count remains in the 50 to 55 range with approximately 25 rigs on our dedicated acreage.

Rig counts have remains consistent in this 50 to 55 dollar W.T.I. crude oil price environment, which we expect to continue.

[noise] natural gas volumes processed in the Rocky Mountain region increased 11% in both the fourth quarter and full year 2019, compared with the same periods in 2018.

Processed volumes averaged 1.05 billion cubic feet per day for 2019 above the midpoint of our volume guidance range.

We expect processed volumes from this region to increase more than 25% compared with 2019 due to the completion of the Demicks Lake plants as we significantly reduced gas currently being flared.

We connected 526 wells and the Rocky Mountain region in 2019.

Better than expected well performance and higher gas to oil ratios contributed to volume growth, even with producers temporarily delaying well completions until our Demicks Lake plants came online.

We expect to connect between 575 and 625 wells in 2020.

Our 200 million cubic feet per day, Demicks Lake one natural gas processing plant that was placed in service in the fourth quarter is expected to be full by the end of the first quarter.

We expect our Demicks lake to plant to ramp to full capacity over the next 12 to 18 months.

With the latest reported natural gas flaring data of approximately 500 million cubic feet per day in the basin and approximately 300 million at that on one Oaks dedicated acreage. We now have to capacity available to capture a significant portion of this flared gas.

[noise], our bear Creek plant remains on schedule to be completed early in the first quarter 2021.

Which will provide much needed processing capacity to the highly productive geographically isolated Dunn county area, where we have substantial acreage dedications. The Demicks Lake expansion will provide an additional 200 million cubic feet per day of processing capacity. When it is completed in the third quarter.

2021.

With the completion of these two facilities one oak will have approximately 1.9 billion cubic feet per day and processing capacity in the Williston basin.

NGL raw feed throughput volumes in the Rocky Mountain region, which consists of L. Creek and the Bakken NGL pipeline increased 9% compared with the third quarter, 2019, and 23% compared with the full year 2018.

We expect our Rocky Mountain NGL volumes to continue to increase as approximately 850 million cubic feet per day of processing capacity from one oak and third party plants has come online since the third quarter 2019.

We recently reached more than 230000 barrels per day of raw feed throughput on Elk Creek, and the Bakken NGL pipeline combined and continue to expect to exit the first quarter 2020 with more than 240000 barrels per day.

Yesterday, we announced an expansion of the Oak Creek pipeline to its full capacity of 400000 barrels per day.

The expansion is supported by well over 240000 barrels per day of long term dedicated production from one oak and third party plants, excluding any incremental last night.

The 160000 barrels per day expansion approximately 60000 barrels per day of the capacity is expected to be available in early 2021, and the remaining 100000 barrels per day by the third quarter 2021.

[noise]. We also see continued to see growth in the powder River basin as production results remain strong benefiting both our natural gas gathering and processing and natural gas liquids segments.

Moving on to the mid continent.

Natural gas volumes processed increased 3% year over year above the midpoint of our guidance range connecting 117 wells to our gathering and processing system.

Based on recent discussions with our customers, we expect our natural gas volumes processed in the mid continent region to decrease approximately 10% this year compared with 2019 and expect to connect 40 to 60 wells.

Total NGL raw feed throughput in the mid continent region for the fourth quarter decreased slightly compared with the third quarter due primarily to spot volumes in the third quarter that did not carry over to the fourth quarter.

Outside of ethane rejection, we expect relatively flat mid continent volumes on our system in 2020, compared with the fourth quarter 2019.

During 2019, we connected five new third party processing plants to our natural gas liquid system in the region.

In two previously connected third party plants on our system more expanded.

Our arbuckle to pipeline remains on schedule for completion by the ended the first quarter of 2020.

Our buckle two will play an important role in transporting incremental supply from the Williston and powder River basins, the mid continent, and the Permian basin to the Gulf Coast or.

Our buckle too is the lower end of the NGL backbone and will be our fifth pipeline that can funnel supply from across our entire system to the Gulf coast markets.

[noise], finishing with the Permian basin and Gulf Coast.

NGL raw feed throughput volumes in this region increased 22% year over year and the average fee rate increased compared with the third quarter 2019.

We expect average rates to continue to increase as we bring on new volumes with bundled rates from our completed expansion projects.

We announced our fourth expansion of the West, Texas LPG system.

100000 barrel per day fully contracted expansion with long term dedicated production from third party processing plants in the region.

We now have announced approximately 260000 barrels per day of expansions on West, Texas LPG to support volume growth in the region.

[noise] our system wide NGL fractionation capacity remains highly utilized phase one of our him before fractionator, which was completed in December has increased our capacity by 75000 barrels per day.

Phase to the project, which will add the remaining 50000 barrels per day of capacity remains on schedule for completion by the ended the first quarter of 2020.

And our NB five fractionator remains on track for completion in the first quarter 2021.

Our overall NGL segment raw feed throughput volume guidance is expected to increased 15% in 2020, driven by a full year of operations about Creek and the completions of the Arbuckle two pipeline Dnbi for fractionator and the 80000 barrel per day, West, Texas LPG pipeline expense.

Engine all expected in the first quarter of 2020.

Continued growth from plant connections and expansions completed in 2019 will also contribute to higher volumes in 2020.

We expect six to nine news third party plant connections or expansions, including the connection already completed with Demicks Lake too.

Terry that concludes my remarks.

Thank you Kevin 2019 was another successful year for one oak and I'm proud of our employees, who continue to focus on safety reliability and the execution of our growth projects.

Operating our integrated network of assets in the manner for which one oak has a strong reputation remains our focus and is the foundation for all our success as we've discussed today and we'll continue to be as we move forward as we transition from this build cycle to a period of significant cash flow generation.

Thank you to all our dedicated employees for your hard work and contributions in helping us achieve another year of companywide growth in 2019, and 2020 is off to a great start as we are in the middle of many project completions and new asset operations that will position us well in the coming years that operator, we're now ready for <unk>.

Thank you ladies and gentlemen at this time, we will open the call for questions. If you would like to ask your question. Please take note by pressing star one on your telephone keypad.

Using a speakerphone. Please make sure that your mute function is turned off till now your signal to reach our equipment and again not a star one to ask a question well pause for just a moment to allow everyone an opportunity to signal for questions.

And our first question comes from Tristan Richardson with Suntrust.

Hey, good morning, guys.

Pretty good commentary on the expansions could you talk just a quick one of the difference on Capex side between Demicks three it seems like you've got a lot of efficiencies versus the first two as well as the bear Creek expansion.

The difference in costs should we think of that as an opportunity for enhance return profile for demicks three versus the others.

Yeah, Jason This is Kevin Yes, that's I mean, that's the way we think about it the reason for the lower capital. It is again kind of more expansions win is weve constructed demicks one endemics two things like power a lot of the inlet handling for the plant.

Some of the pipeline infrastructure, we're doing we're expanding existing compressor stations rather than building new compressor stations. So all those things contribute to a two that capital being lower than the previous projects.

Helpful. Thank you and then just don't meet the L. Creek expansion.

In terms of the volumes behind that should we think of that is primarily there to serve demicks three as well as bear Creek or are there.

Could you talk about the quantity of other third party plants that could be behind that the latest expansion.

Yes, I mean, that's the way to think about it is is we continue to ramp volumes with more than 240000 barrels a day now of contracted.

On the pipe we needed to expand it. We also wanted to make sure we had the ability to handle any ethane that needs to come out incrementally.

But again the the economics are really based more on just the traditional the classic C plus volume growth that we see we still have a lot of opportunities and were in late stage negotiations with several customers north of the river.

You know as we build that lateral that's going to connect over to the Hess plant. So there's still opportunities out there in front of those.

Appreciate it thank you guys very much.

Thank you.

And as a reminder, that a star one to ask a question well take our next question from Shneur Gershuni with.

Yes.

Hi, Good morning, guys. I was just wondering if we can dive into the 2021, plus 20% EBITDA guidance a little bit.

Just trying to understand what do you just fumes I guess with RBC.

With part of that is a ramp up of Bell Creek like you know how much ethane recovery are you seeing from the from the Bakken as a full ethane recovery.

Also I was wondering if you talk about kind of the margin uplift. If if if you can sort of like walk us through what is the delta between 20 and 21 in terms of what's going into your assumptions.

Sure Center this Kevin.

Clearly it's it is a buck in driven story I think you start and just kind of go down the list of projects that are coming on either late this year or early early in 21, So you've got bear creek to that expansion, which again, there's going to be some flared gas behind that facility when it's one its.

Up we've got four large well capitalized producers that are just dying to go drill down there, but they there's just no capacity currently.

So there's growth there we've talked about the north lateral from or on our in our NGL segment that will go connect to the Hess plant that will be completed in Q4 of this year. So we'll have a year of volumes on that.

You've got continued just core growth or in a bar existing plants you know the Demicks Lake facilities that will continue to ramp up and we'll have a little opportunity for demicks three towards the end of the year.

And then you mentioned the ethane opportunity that yes, we we do have what we would consider a modest level of ethane. If you look at the production growth that I'm just from capturing the flared gas and as these other no ours and third party plants ramp up it's it's just some math.

With that determines we're going to need to pull some ethane now.

So we've got around 25 to 40000 barrels per day.

Of ethane that we believe will come out in 21 in that a that is the result of the BG you heat content issue on northern border.

Permian Gulf Coast.

We've got the three expansions that are coming on between now and ER and the middle of 21.

That will provide additional volume growth than we have a full year of the M.B. five fractionator in 21 as well. So you pull all that together you know, we see both our NGL and GMP segments volume growth continuing to increase and it's gonna be well into double digits.

That was very helpful really do appreciate that maybe as a follow up question kind of a two parter. If you don't mind you know with your Capex activity I mean, just like the fact that you've announced these new project. It is definitely lower than where it's been.

And you sort of see slowing producer activity I was just wondering what are the opportunities for for one or two to have it and optimize on the cost side.

Are there cost that you can now strip out that you can sort of see where your businesses running and also are you able to potentially pursue an asset light strategy. When they sort of think about your L. Creek expansion as well as the West Texas LPG.

Brings a lot more volumes into Bob on the NGL side, which would suggest you would need to frac like you know given their access frac capacity out there are other ways for you to sublease, others, other fracs and sort of take advantage of that and pursue an asset light strategy.

It's sort of wondering if you can sort of talk about other ways to optimize for further earnings growth beyond 2021.

Yes, Kevin again, I I think we believe we have been doing that already I'm in a lot of ways.

The previous question about Demicks Lake Thats, a great example of a brownfield.

Expansion to where where we put it there and and again, we're able to significantly reduce the capital for that capacity.

As we think about the Fracs I think we've done that as well we have we have clear line of sight to m. before being full and significant volumes, if not MB five being full but if you remember the other thing we've done is we've announced like 65000 barrels.

Today of of again expansions at our existing facilities that our team was able to go find for much less capital than building another greenfield frac and so that is the delayed any discussion of an M.B. six because our team has been able to find the.

Those types of de bottlenecking and expansion opportunities. So I like to thank our team you know we have already we've done that and we that's part of our DNA is is we think about how we provide the capacity for our customers.

And I know you made a comment at the very beginning I would like to just did just give you my point of view and I don't I don't think we have seen slowing producer activity on <unk> on our acreage, especially when you talk about the Bakken in the Permian, Yes. The mid continent is pulled back, but we haven't seen any slowed activity in the buck and repair.

Permian at all.

No fair enough I I do appreciate that color, maybe one final question.

When do you guys expect or what is your next projection for one though to be a cash taxpayer.

Well sure we as we [noise], we've said in the best when we did the acquisition of the partnership the Bakken 17, we said we wouldn't be a taxpayer.

Through 2021.

We've built a between six and 7 billion dollars' worth of assets with bonus depreciation that we've been able to take advantage on top of that so.

We have a good runway here before we will become a taxpayer at all.

And then at some point there'll be a limitation on utilization of the and then well that was put in place with Aleks Blessed to Texas, but that would that up one full going forward, we would have kind of a 4% to 5% merging or rate somewhere else there in the future. So.

We don't see a full taxpaying situation well into the future.

Perfect. Thank you very much appreciate allogeneic guys.

Our next question comes from Christine Cho with Barclays.

Hi, everyone. If I could actually start I thought I follow up to the ethane extraction that again.

Should we think of that's not the ethane extraction that you'll potentially do next year as a temporary dynamic on file another pipeline comes on and my Canadian gas can come back a blanket the Bakken gas or do you think it will be more of a permanent thing.

[noise] Christine this is Kevin I'm I think we believe it's going to be a long term thing because if you think about new capacity any new capacity, that's going to come online in the in the Bakken. The is highly likely it's gonna have a BT you spec on it also because it's not gonna have other.

Their gas to blend down with like currently is going on on northern border. So.

So at least the various projects that we've looked at and been involved with all all of those contemplate.

You know all of those contemplate a b to use spec.

Okay, that's what I thought the fine.

And then could you give us a breakdown of where they take nine third party connection entire recently.

[noise] Kristina this shared and those are going to come in as you'd expect in the Bakken and in the Permian and the six is pretty much path on each one of 'em. The growth is going to be some plants that we will be coming on at the end of 2020 that could either be in 2020 or 2021.

Okay, and then umbrellas, primarily backing our that's also link between Permian and it's it's split.

Okay, and then can you give us an idea of that cadence and then magnitude of third party frac costs and well costs roll off in 2020.

[noise], Yeah, Christine we won't see any any third party rail cost in 2020, or we had predicted any sense. So creek coming online that has been reduced to zero.

But the third party Frac will be about the same level. It was in 2019 isn't 2020, as we get ready for M.B. five coming online.

Okay. So those costs are not going to go down here.

Third party Frac costs won't go down in 2020 from 2019, Okay, great and that's baked into our guidance.

Well take our next question from Jeremy Tonet with JP Morgan.

Hi, Good morning, just wanted to follow up I guess with your conversations with producers in this environment and given how the commodity price has declined a bit here. Just wondering if you could ROI with us I guess expectations for drilling activity has that been moderating or it seems like adobe.

You know firmly baked into your guidance at this point, but anything that you can share with us I guess on on this topic.

Yes, Kevin Yeah, we're we're looking at the commodity environment very similar to our producers really were folk we focus on the crude side. We don't you know we've reduced our direct commodity exposure so significantly that.

It really it's not that big a deal just runs is when you get into the NGL prices are the Nat gas prices most of the producers our customers are telling us they're planning for a 50 dollar a crude environment and therefore, that's the activity levels were kind of assuming is the activity levels that you're seeing.

You know when the Bakken in the Permian.

You know in the current I'm in the current landscape. So that's the way we're thinking about it over the next couple of years, which we believe is very consistent with the way our customers are thinking about.

That's helpful. Thanks, and just a couple of clean up questions I guess with.

The NGL logistics side, how do you guys said on the storage side at this point do you think that there's more expansions that are needed there to kind of do what you want to do in Bellevue.

And then in the 2021 guide I guess, the Conway Belvieu spread any thoughts you could share with us on on how that went at that point.

Well just stay on the storage side that right now we are in the process. That's constructing two new storage wells and both are 1.5 million barrels and we're also putting in a three and a half million barrel brine pond. So right now we do see the need to expand our storage facilities and we are doing it and those will.

Come up I'm part one of those will come to those wells will come up this year. The next one will come up next year. So we think that puts us in a very good position on our storage side to be able to handle our growth and then on the Conway to belvieu spread as we said, but the arbuckle two pipeline coming online for sure the spreads are going to be very narrow.

And in our 2020 and 2021 guidance, we are predicting at historically low spread or very narrow spread between Conway and belvieu.

Got you great and just to confirm I think you'd said 50 to $55. That's kind of the price deck that you guys are employing when you think about this guidance going forward.

Yes from accrued activity perspective that that's the level, we're thinking about it.

That's it for me thank you.

Well take our next question from Michael Lapides with Goldman Sachs.

Hey, guys couple of questions first first of all when thinking about flaring and flaring limits just curious.

Do you think there's potential for North Dakota, tighten up flaring limits further and if so what would have to happen for that and second do you have any read through a read into the recent report put out by they are railroad Commission in Texas regarding flaring there.

Well, Michael it's Kevin I'll start and then let Chuck jump in.

The flaring the gas capture targets or the flaring targets in North Dakota do step down at the end of this year.

They stepped down from.

88% capture or step up from 88% capture to 91% capture.

So clearly that that is one step up in conversations we have with the with the state and our ore producers, obviously, we want to drive that number well below that we have experienced when you look back at 15 and 16, when we when the midstream kinda got caught up.

Are you know, we drove flaring to lower levels than that so.

So I think that's the goal as it relates to Texas, Yes, Yes, we saw the report.

I think any just from a regulatory perspective I do think you'll see continued discussions around flaring as to where that goes from a regulation standpoint.

You know I don't know that Ah you know I'd have a point of view at this point, but Chuck I mean, I guess, what I would add in North Dakota, Michael is that the a kind of interested stakeholders up there between the state to producers on the processors have been meeting fairly regularly over the layoffs, let's call. It a two quarters looking at the current.

Flaring rules flooring to exemptions held the a interested parties can work more closely together together to mitigate flaring and there are there some discussion of potentially changing some of these rules going forward, but theres nothing concrete as of yet.

Got it and then Mike <unk> <unk>.

Michael Let me just make one quick comment to that I'll follow up.

So with the Texas report.

I think it's just indicative of the fact that the heat the heat on producers is really going to be stepping up in terms of flaring and I think for midstream companies I think that actually creates obviously opportunity and in particular, we're gonna see I think a step up in terms of infrastructure getting built or or maximized and.

Order to reduce the flaring and obviously when we maximize that throughput from that rich gas, we're going to create more ngls coming out of the basin sooner rather than later, so I think that's going to I think that's really going to step up and I think the step one was the fact that the Texas Railroad Commission acknowledged.

What was happening.

I think they did some really kinda took a unique look at it in terms of intensity of flaring I think I think it really shows a picture that it's gonna have to be addressed and regulators gonna have to address it in midstream is gonna be a big part of that solution of course.

Got it and then one follow up just on the guidance that the growth Capex range is a pretty wide range to give in in February of the prompt here just curious what anchors the low in the high into that range.

Michael It's Kevin you know similar to last year, when we had an even wider range. It really comes down to timing you looked at the number of projects, we have we're expecting to come online.

In the first quarter, if if we're always looking for ways to pull those back if those get pulled back and we start realizing the EBITDA sooner, we'd love to do that but that may pull a little capital that would move you towards the high end. Conversely, if some of these things you know if.

If they if they go the other direction for whatever reason it could it could slow down some of the capital spend and 20 that would move you towards the low end. So it's really just going to come down to timing.

Got it thank you guys much appreciated.

Thank you Michael.

Our next question comes from Colton Bean with Tudor Pickering holding company.

So just to follow up there on the 2020 capital program can you clarify how much of that is attributable to the 900 million a backlog additions yeah slated for 2021.

Yeah about half of the 900 million, we announced is is 2020 spend.

Yeah. That's helpful. And then I would Demicks Lake three now slated for 21, how you evaluating absolutely residue gas takeaway understanding that the comments earlier on he content, but just in terms of absolutely dry gas capacity.

Yeah. Colin this is Chuck what I could say I mean, obviously, you're going to new during this need residue gas take away yet we've said before sometime in 22, perhaps.

2023.

We're currently in late stage negotiations on negotiating a proceeding agreement with a with a project coming out of the Bakken.

Wander in India. So can't go into that any further however, we believe sometime in the next month or two you should you should see some information come out publicly.

Understood and just the final one for me on the outreach expansion is that effectively you know in all or nothing type process or could you add horsepower more ratably as its needed.

Well the shared and as you said it we said in our remarks that we will get some of that early in 2021 and then the later will come in later 2021. So we are ramping up that capacity as we go through through the year and if some reason we could slow down if we needed to.

I don't see that happening, but we could.

We will get we will get some as we go through the 2021. So we are ramping up the capacity.

Understood appreciate that.

Second next question from Derek Walker with Bank of America.

Hi, Good morning, guys, just a couple ones for me.

Follow up on the other growth Capex I think you talked to sort of the routine capex before it's around well connects and connect how much of the.

2020 growth Capex.

It's considered routine capex on.

Similarly, it kind of going up to 21, you mentioned the step down and growth Capex again, she always kind of think of a similar run rate for routine capex and 21 or anything of that are actually up or down.

You know over the years, we've said the that our growth or routine growth capex is somewhere between $250 million to $400 million yourself.

It varies depending on where the plants are that we have to connector. The the wells were conducting but there's always a is in that range. It's included in our guidance for 2020.

You know from a growth capex standpoint wouldn't be significantly different in 2021, but we expect a meaningful step down in capex from 2020 to 2021 or as you know in the in the range of a billion dollars less than 2021, then we will have in 2020.

Got it and then maybe I'll just ask a quick went on a dividend policy.

9%, Oh last year should we think about 9% again and 21 or.

One thing about kind of a normalized sort of rate relative to either.

The dividend aristocrats, nothing p. or perhaps larger ministry names.

Yes.

Well, we've guided the pretty regularly since 2017 that through 2021, we would the my opinion that 9% to 11% a range we've been at nine throughout the.

And we don't see anything at this point that will change the the that view through 2021, and we're not going to give you best though.

Got it thank you.

Well take our next question from Chris Sighinolfi with Jefferies.

Hey, good morning, everybody. Thanks for the I agree with all the colors.

Kinda and I just wanted to go back maybe to something Michael was asking about asking it slightly differently and that's on on flared volumes on the Rockies footprint today I believe in your January update you noted.

For November it was about 300 million cubic feet today.

To your acreage I'm, just curious I guess, the starring measure where that is today and then if we look at the growth in gathered volumes event, you've modeled or anticipated for 2020 versus what you did in fourth quarter, how much of that is like facing growth versus how much of that as flared capture.

And I ask just to better understand the walk, but also where does that sort of has a set up for where that leaves us on 21.

Yeah, Chris clearly the I mean, the latest number the we have another month. It's it was basically flat, maybe a little bit or flaring on ours was a little bit less but we're still in that 300 range.

Okay. We is we look going forward.

We sorry, there's a echo here, that's kind of messing with me, but.

As we look going forward the volumes of the flared gas capture will drive, especially as we move through the early parts of the year will drive that flaring down significantly, but again with the ducks with the rig count that still running as we kind of get.

Towards the back half of 20 and going to 21, you still got just straight production growth at the rig counts, we're currently seeing and the productivity of the wells being drilled.

And then the other again I mentioned earlier the another key volume dynamic for the growth is bear creek to that there's going to be some flared gas behind that system, because it's geographically isolated and we fully anticipate as we get capacity down there you're going to see some rig movements.

Into that region to to drill that area.

Okay. Thanks for that that's very helpful. I guess as it related point, Kevin you know for those watching I guess inlet volumes that discrete plants, Oh, we like to see volumes sort of wheel to your newer facilities for processing before the aggregate footprint you know more more broadly films that are they.

Deficiencies and having I guess, an expanded plant portfolio, where you're not you know where certain plans maybe are not isolated but.

Connected <unk> or I guess longer dated question when you start to recover ethane on the plan for 21 are we likely to see that sort of disproportionately affecting certain plants and not others I'm just asking because I know some people track individual facilities.

Yeah, we look at our system and total again with exception of Bear Creek.

Area the rest of our system, we look at it in total and absolutely.

Well see some gas move from say Garden Creek Demicks Lake in from Lonesome Creek, The Garden Creek as we.

Optimize our system will will push the gas to the plant in the facility that we believe we can get.

You know do it for the least cost and take advantage of our assets. So you will see some of that go on but it really doesn't impact ethane recovery again, it'll be a similar argument or discussion and if we start recovering or need to recover a little ethane that will ultimately come down to what.

The you know how the tariff is worded from a northern border standpoint, if there's a change there and how we want to operate our facilities.

Okay, Great. If I can ask one final question totally different he just remind me some of the drivers of outperformance for the Nat gas segment by segment and and 19 had noted in his and a modest EBITDA reduction I think you're guiding for 2020.

It looks like you remain very well.

Contracting on a capacity there so I'm just I'm just wondering if that's a rate or cost.

Sure if it's something entirely different.

Chris This is Chuck so our 2019 outperformance is really driven by.

Capturing or the excuse me the interruptible volumes that that we flow there was great demand, particularly in Texas and Oklahoma on our interruptible capacity is well within the Permian basin, there being less take away capacity alternatives and certainly we had a real strong Q3, but very very very good cooling generation.

A little too for the heat.

Generating a cooling so that was 2019 the uplift as you compare year over year, what we what we did and looking at 2020 guidance.

We typically will normalize our spring and summer electric generation load. So as you look at our midpoint in 2020, we do have some upside in there should or should there be a repeat of a good strong summer Saar interruptible volumes could help us to the upside and I might add that recently Permian Highway has indicated that.

There will be delayed until Q1 of 2021, so that potentially presents another opportunity for our Texas intrastate to capture some more ROE interoperable transport services.

That's great. Thanks for the review of that appreciate it.

I appreciate all the cool I guess.

Well take our next question from Michael Bland with Wells Fargo.

Hey, Thanks, and good morning, everyone <unk>.

Question on.

The <unk> hundred thousand barrels a day west, Texas, LPG expansion that or are they new plants that are sort of fueling those commitments or are you taking market share from their mothers.

Michael This is shared and we're doing both.

Where are you getting plants, new plants that are being connected and we're getting volume off of existing plants that are going to other pipeline.

Okay.

And.

Then just turning to the 21.

Guide and [noise].

How how much of the growth coming out of the Rocky Mountain region is contingent on powder River Basin development versus just continued growth and in the Bakken.

[noise] Michael it both segments it would be a very modest level of increase it it's not a driver the drivers the Bakken in the Permian.

But but Michael don't let that [noise].

The an indication of how we feel about the powder. Okay. We like the Patters got a lot of unrealized potential.

These that could in it and it just needs a little bit of price Hill, and we're certainly well positioned to be able to exploit that if in fact, it a the powder does get a little bit of price Hill.

Great. Thank you.

Thank you.

Well take our next question from Alex can I am with Wolfe research.

Thanks, I guess, just a follow up question with respect to a west Texas LPG.

You know with the expansion more or less said, how do you think about the timetable with respect to into your options related to you know conversion of repurchasing of that tends to legacy pipe.

Alex This is shared and we with distillates expansion that we announced we still have a little bit more expansion to do before we can free up one of the pipes to go into an alternative service.

We did contemplate making a full expansion of the pipeline to open up the legacy pipe into a different service, but what we wanted to have better clarity and better line of sight into additional volume that we predict will be coming on later before we would go and do the full Luke complete the full Lou but the west Texas.

Blind freeing up legacy system for a different service.

Got it great. Thanks.

[noise] and our next question comes from Sunil Sibal with Seaport Global Securities.

Hi, Good morning, guys. Thanks for all the clarity I got on the call late to just couple of clarifications. If your might have touched it on the leverage side. I think you mentioned that you expect to get close to Fourx leverage Oh sometime in 2020.

Is that correct and if so you know any can talk anything about.

Funding assumptions that go into that.

Well, what we said in the prepared remarks was that a the expectation that we've we've said before remains the same that we expected to be four times debt to EBITDA on a run rate basis, either in the fourth quarter of 2020 or in early 2021.

So that doesn't change and then we expect to continue to de lever a further as we go beyond that appeared and 2021 as these projects come on Capex goes down and cash flows increase so.

Nothing no change to that.

Okay got it and then when kind of broader question I think in the past you've talked about a corporate M&A and.

Industry environment, not being that conducive to that I was wondering you're not seeing anything different in the industry environment right now.

No no no no difference still tough environment from an M&A perspective, we're gonna we're going to stay focused on this organic growth strategy. If you. If we do take advantage of some M&A opportunities more be on in the area of the strategic bolt on an asset a asset type acquisition.

So saar thinking really hasn't hasn't changed.

Okay got it thanks.

You bet.

Our next question comes from Harry Mateer with Barclays.

Hi, Good morning, So first just a follow up on the last question, but you guys previously you've talked about a three and a half times Aspirationally leverage target. Then just wanted to confirm if that's still the case and have you given any consideration to making that less of an aspirational target more of an actual target meal potentially was firmer Tom guys.

Lines, just given how shaky the macro backdrop feels.

Well if you just if you just do the projections out based on the [noise].

The guidance that we've given you you'll see that we go.

Towards him through that three and a half times pretty quickly.

You know it will be set as that we've aspirationally on the going forward basis.

We would be around that three and a half as we said saw continued growth going forward. If we don't see additional growth from where we are today, we will be well below three now.

Got it Okay and then a.

Financing needs. This year, if you could just talk about what your plans might be your your next bond maturities until 2022, but you do have a 2021 term loan that's pre payable and you know you guys old outspend cash flow. This year again after all the Capex and dividends. So just curious everything about possible debt capital needs, you know, especially given that a 10 years almost at 1.3 person.

Right now.

Oh, well, obviously built some short term debt or as we finish up this construction program and you're right. We do have the Oh the term loan out there coming due in 2021 so.

Well, we'll keep our eye on the market and when we think it's appropriate Oh, we may access the doesn't market. Obviously, we have no equity financing whatsoever in her and her thought.

Got it Okay, and then last one for me just I'm, putting different parts together in terms your EBITDA growth for 21, and then you know the indication you get about 1 billion of less Capex and 21 versus 20.

Yeah. It seems like things are aligning free to be at least free cash flow neutral after growth capex and the dividend. So and there are a number of other of your large cap midstream companies are trying to get there next year as well. So is that something you know like true free cash generation that you're thinking of targeting as a matter of policy or is it really at this point still just dependent on what other projects you might find.

Well, we're not going to give forward guidance out there are a again if you do the do the math than what we've had out there yeah. It will be a reality that that's where we'll be going forward and we'll see what the future brings but we're in a position where I.

Going forward basis, the company is going to generate a very significant amount of cash well above dividends.

Got it thank you.

Yeah.

And our next question comes from the National Shibani with BMO capital markets.

Thank you and good morning, everyone. A quick question for me you guys outline what.

Price assumptions, you have to be a gathering processing business for a NGL and natural gas and grid.

Yeah.

No. This Kevin Yeah were like we mentioned, we're looking at the crude environment in that 50 55 type environment.

You know again, we're not that come up with the direct commodity exposure. We have is very limited, but we're thinking about you know nat gas prices and and NGL prices not out of the not significantly different than like we'd look at the strip over the next year. So.

I guess the your your your guidance is premised on its basically split budget for the inside of the here.

Yeah. When you look at our guidance that that's the way we're thinking about those prices.

That's it from me thank you.

Well take our final question from Craig Shere with it can be brothers.

Hi, congratulations on the new project announcements.

Color Thanks, Craig.

I was on the call a little late so if you already addressed.

But.

Any comments on Oh.

Export opportunity.

Well.

Kind of have to answer two or three questions about leverage is there a downside limit just doesn't make sense.

Issue fallen a further if you don't have.

Sufficient growth Capex.

Available appoint <unk>.

About dividends or share buyback policy.

Well as it relates to the second part of your your question. Obviously it is our debt gets paid down a two levels I was just discussing it opens up a lot of alternatives for us a you know whether it be share buybacks or dividends or or whatever but I think he is.

It will be well have the flexibility to do what we think is appropriate at the time.

And then sort of Dawson times.

I'm sorry.

Are you just willing to go under three times.

Okay, We'll cross that bridge, when we get there and see what the market environment is a but no. We're not we're not there today and so we're not going to speculate as to what the market is gonna be at that point going forward.

And there's Craig on this is Kevin on the dog.

Similar as we have been communicating you know it's still.

Part of the business, we would love to have its not something that we think we have to have but we have a team working very hard you know again were.

Very confident the you know our barrels will continue to clear we're not directly we don't have the price exposure.

To determine what the relative about what that real value of the prices on the Gulf coast, but we'll keep working that opportunity when we get the markets, where the when I say the markets on the you know the the customers that we would be selling to have a lot of conversations around the globe with them at the same time.

Having conversations with people in a in the Gulf Coast about where dock in partnership opportunities. There. So we'll keep working those and when we get it all lined up the that's when we might make an announcement.

[noise], Craig I'll just <unk>.

Hey, Craig I mean, just my one follow up comment to Paul's comment as the company has historically always manage the balance sheet in a very prudent way.

With an emphasis toward being invested investment grade I mean, that's if you want to look for some of <unk> a hard line somewhere that'll be a hard line for us and so you know she as we as we think longer term the companys always gonna do.

What makes sense and is prudent okay, and <unk> and we've we've shown the long history of doing that so that's what that's what you can hang your head on.

Okay said.

Theres must each [laughter] okay.

Just as my last follow up I was just wondering I don't know Kevin wants to come back, but if LPG thing or anything else was looking like.

The strongest horse race in terms of.

Your ideal opportunities.

[laughter] in regards to export facility.

Yes.

Okay, Yeah, it would be LP Jesus, where the significant focuses right now we're not ignoring the you know ethane opportunities that may come our way, but Ah, but I think lpgs are the ones driving the <unk>. The majority of the conversations at this point.

Thank you very much.

Thanks, Craig.

Ladies and gentlemen. This concludes today's question and answer session I would now I'll turn it back to Andrew Silo for closing remarks [noise].

[noise] are quite period for the first quarter starts will be close our books in early April and extends until we release earnings in late April will provide details for that conference call. It later day again. Thank you all for joining us and the IR team will be available throughout the day for your questions have a good rest of your day. Thank you.

[noise], ladies and gentlemen. This concludes today's teleconference. Thank you for your participation you may now disconnect your phone line.

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