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Enterprise Products Partners LP
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Ladies and gentlemen, thank you for standing by, and welcome to the Q4 2019 Enterprise Products Partners L.P., Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions]
I would now like to hand the conference over to your speaker today, Randy Burkhalter, Vice President of Investor Relations. Thank you. Please go ahead, sir.
Okay. Thank you, Dylan. Good morning, everyone, and welcome to the Enterprise Products Partners conference call to discuss fourth quarter 2019 earnings. Our speakers today will be Jim Teague and Randy Fowler, Chief Executive Officer of our Enterprise's General Partner. Other members of our senior management team are also in attendance for the call today.
During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 based on the beliefs of the Company as well as assumptions made by and information currently available to Enterprise's management team.
Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call.
And so with that, I'll turn it over to Jim.
Thank you, Randy. Frankie Valli & The Four Seasons, back in the day had a song, “Oh, What a Night” to paraphrase where 2019 is concerned. Oh, What a Year. Enterprise reported record net income for the full-year of 2019 of $4.6 billion or $2.09 a unit. That's a 10% increase from 2018. DCF increased 11% to a record $6.6 billion and provided 1.7x coverage.
We retained $2.7 billion of DCF, a 24% increase compared to 2018. The record cash flow we generated in 2019 allowed us to increase the distribution paid to our partners for the 21st consecutive year, while self-funding the equity portion of our growth capital investments. We again completed 2019 with a lot of financial flexibility and a very strong balance sheet.
In addition to the financial highlights, we ended the decade with record performance in 2019 with all of our business segments reporting increased results, including 28 operating and financial records. We set 13 operational records, including almost 2 million barrels per day of marine terminal export volumes, 6.7 million barrels a day of liquid transportation volumes, and 10.4 million of barrels of oil equivalent per day of total system transportation volumes.
During 2019, Enterprise completed construction and began service on approximately $5.4 billion of capital projects, including $2.5 billion that were completed in the fourth quarter. In addition, we have another $7.7 billion of projects underway. Substantially, all of 2019s major projects were completed on time and on budget. In addition, we are in discussions with potential JV partners and projects that beat our downstream value chain.
I’d like to give a shout out to operations for successfully commissioning five new major new assets from late September to the end of the fourth quarter. LPG export expansion, iBDH, Mentone gas processing plant, our Panola Bulldog gas processing plant, and Phase I of our ethylene export terminal.
Frankly, we should have built the Panola Bulldog plant five years ago, my bad. But we finally did build it, it's full and it's feeding our Panola pipeline and our Mont Belvieu complex. What we didn't have five years ago was this complete and large gathering system as we have today, supporting that project – that gas plant is a gathering system that goes from Northwest Louisiana to deep East Texas.
Our ethylene export project was not a project I embraced in the beginning. Bringing in navigator, a joint venture partner got me over the hump, but I think Chris D'Anna and his team along with the navigator team went on a mission to prove me wrong. They are on the verge of executing the contract that will result in a sign being hung on that terminal that says sold out. Mentone is our latest addition to our Permian processing system. Mentone is fully contracted with one of the largest producers in the Delaware Basin.
A few words about gathering and processing. There are essentially two types of gathering and processing contracts that we enter into. The first is demand fee or said another way, take-or-pay contracts, where a producer commits to a volume at a fee that is paid, whether the volume is there is delivered or not. The second type is an acreage dedication. That's where producer dedicates everything he produces from a defined acreage up to a set maximum daily quantity, and that are MDQ and that's the amount that we have to provide service thus for.
If the producer does not meet that maximum daily quantity threshold, then we have the right to reduce the MDQ and sell that capacity to another producer. In many cases, even though the MDQ has reduced their acreage dedication remains the same. We've had some underperformance at our Orla complex and consequently have reduced the MDQ of at least one producer.
Natalie Gayden and Lowell Moore's team have successfully backfilled that capacity with a long-term $300 million a day take-or-pay contract with a large investment grade producer. These type of clawback options allow us to maximize the use of our capacity. And in this case, defer capital as much as two years.
Our iBDH started up in December. As a result, our [Bay plant] and our high-purity isobutylene plants are running at capacity, and our anchored customers taking their contracted volume. Because there is a ramp for anchor customer, we have spot volumes to sell. I was somewhat concerned about placing those volumes, but again, Chris and his team proved me wrong as there's been a healthy appetite from the refining industry.
Our LPG export expansion was up and running throughout the third quarter. We have contracted that terminal to a targeted level and through efficient scheduling, we have been able to increase our dock utilization to share in a wider spread internationally. In the first half of next year, we expect to have four crude oil pipelines out of the Permian.
One of these pipelines, M2E 3 is a 36-inch pipeline we are building that upon completion of construction will be jointly owned by M2E 3 and Wink to Webster. We will own as an undivided joint interest 29% of Wink to Webster. The project should be complete, our ECHO terminal by August and to Webster by the end of the year. I don't expect more than 200,000 to 300,000 barrels a day to flow until the Webster leg is complete.
If you think about it in those four pipelines, with just our contracted volume and a zero terminal value, they will deliver a mid-teen IRR to Enterprise. Our upsides are the additional fees we collect for storage and for export and any marketing activities. PDH 2 is underway to construction. We have a high quality petrochemical customer as the anchor and are in negotiations for the remaining capacity and potentially a joint venture partner.
We are one of the largest producers of PGP in the world, and it's a world that is short PGP. Once PDH 2 is up, we will produce more than 11 billion pounds a year of propylene. So 2019 was a record year and I want you to know that Enterprise we celebrated for about an hour and a half before turning our attention to 2020. The New Year poses new challenges and headwinds. Those headwinds are primarily spreads from Waha to the Gulf Coast and natural gas, Mid-Continent to Mont Belvieu in liquids and Midland to Houston in crude. While there were spreads, they're not as robust as they were last year.
That said, we expect spreads to the Waha to grow in LPG, in crude oil and in petrochemicals, and we have assets that we put into service in 2019 that will have a full-year of earnings. While our folks have forecast that the spreads we had in 2019 on the assets that produced those spreads could be down $500 million. I look at our footprint and I see other opportunities, backwardation, contango, gross product, as I said, to the water on all hydrocarbons. We have RGP to PGP. We have normal butane to isobutane. We have product upgrades and the list goes on.
I've been here a long time and when I look at our system, I see a system that in my 20 years has always delivered above our contracted fees. It's never the same asset. It is the same integrated system. So I expect 2020 to be a strong year. It's hard to set new records every year, but with our people and our footprint, I'd be real careful betting against us. And now I'm going to look at a Chris Wade and let him shutter as I've got unscripted comments to make.
We should have press release this morning that we were going to a Co-CEO structure with Randy sharing this title with me. Frankly, all we're doing is formalizing how we've always run the Company. Randy and I will remain a part of the office of the Chairman with Randa and Hank Bachmann and we will also stay on the Board.
Randy and I don't compete with each other. We compliment each other. We're a truly obtain and we've been together for over 20 years. So we are friends and we respect what other brings to the table. The other announcements we made today are senior management team that is accomplished with complimentary skills and they truly work as a team.
Brent Secrest, our Chief Commercial Officer has one of the best value minds I've ever seen and he's so damn tall. He has a present. Graham Bacon, our Chief Operating Officer is on top of operations and engineering such that we sleep well at night.
Daniel Boss has some commercial time. He ran our regulated business that makes him one of the more well rounded people we've ever had to run our accounting group and other responsibilities he's taking on. He also had the initiative, even though it wasn't required to get his CPA once he took that job.
Chris Nelly has a style that is disarming and a work ethic second to none. Bob Sanders, well, Bob is 40 years with us and he is our go to guys. He knows where every piece of steel is. Not mentioned was Tony Chovanec, who is built so much credibility that everyone wants his group's forecast and we have Bany and we have John Jordan.
Let me tell you what this is not. Enterprise has never been a job for me. It's a calling. This is not a transition to Jim's quote on retirement as far as I'm concerned, I'm not going anywhere. And as good as I feel and as excited as I am about our future, I'm really not convinced that my runway isn't as long as Randy's. Be that as it may, there's no one I'd rather share this title with than Randy Fowler.
And with that, I'll turn it over to our Co-CEO Randy Fowler.
Thank you, Jim, and good morning, everyone. Let me start with some of the income statement items for the fourth quarter. Net income attributable to limited partners for the fourth quarter of 2019 was $1.1 billion or $0.50 per unit on a fully diluted basis. A net income for the fourth quarter of 2019 included a non-cash impairment and related charges of approximately $82 million. This is primarily related to our investment in the Centennial liquids pipeline that we co-owned with marathon.
The fourth quarter of 2019 also included non-cash mark-to-market losses of $25 million. Together these non-cash charges were approximately $0.05 on a fully diluted unit. Net income for 2018 included non-cash impairment and related charges of approximately $29 million and a non-cash mark-to-market gain of $237 million or a combined $0.10 per fully diluted unit. Excluding these non-cash items, EPU for the fourth quarter of 2019 increased by 13% compared to the same period in 2018.
Moving on to cash flows. Cash flows from operations was $1.7 billion for the fourth quarter of 2019 versus $1.9 billion for the fourth quarter 2018, excluding changes in working capital accounts, cash flow from operations for the fourth quarter of 2019 was 11% higher than the fourth quarter of 2018.
Free cash flow, which we defined is – we use the Bloomberg definition, cash flow from operations minus investing activities. And then we add back joint venture contributions from joint venture partners was $2.5 billion for the full-year 2019, which was 24% higher than free cash flow for 2018.
We defined payout ratio as the sum of cash dividends, distributions and buybacks as a percent of cash flow from operations. Our payout ratio was approximately 58% for the fourth quarter of 2019 and 59% for the full-year 2019. For context on how we compare to the broader equity markets I refer to Page 5 of the supplemental slides that we posted based on the information available to us for the nine months of 2019, enterprises is 59% payout ratio is the fourth highest compared to the median payout ratios for the S&P 500 and 10 of its industry sectors.
We exclude its financial sector due to its volatility and outliers. In terms of distributions and dividends only Enterprise ranked in the top 15 percentile of all S&P 500 for a percent of a cash flow return to equity investors. In terms of total payout ratio, Enterprise ranked in the 41 percentile of all S&P 500 companies.
Our total capital investments for the fourth quarter of 2019 were $1.2 billion, including $1.1 billion of growth capital investments and $93 million of sustaining capital expenditures. Total investments for 2019 were $4.7 billion, which includes $4.3 billion of growth capital investments, which is reduced to $3.7 billion, after subtracting contribution from our JV partners.
Sustaining CapEx for 2019 was $325 million, or 2020 we currently expect our growth capital expenditures will be in the range of $3 billion to $4 billion and sustaining capital expenditures will be approximately $400 million. For 2021, we currently expect growth capital expenditures will be in the range of $2 billion to $3 billion. One of our most important goals is continues to be capital discipline. And I'll also add the lower CapEx in 2021 that we currently see would lead to higher free cash flow, which would provide the potential for us to consider larger buybacks.
In terms of capitalization, our consolidated liquidity was $4.9 billion at December 31 2019, which included available borrowing capacity under our credit facilities and unrestricted cash of about $300 million. Adjusted EBITDA for the trailing 12 months ended December 31, 2019 was $8.1 billion and our consolidated leverage was 3.25x after adjusting debt for the partial equity credit that we received for the hybrid debt securities by the rating agencies and also reduced by unrestricted cash.
If we normalize adjusted EBITDA for $500 million of spread opportunities in 2019 that we believe were wider than normal, we estimate that our leverage ratio would have been 3.5x for 2019, which is at the midpoint of our range for our targeted leverage.
On January 6, we priced an aggregate $3 billion of senior unsecured notes, comprised of $1 billion of tenure notes at 2.8% coupon, $1 billion of 31-year notes at 3.7% and $1 billion of 40-year notes at 3.95%. We would like to say thank you to the strong support from our fixed income investors.
After adjusting for the proceeds from our $3 billion notes offering and the maturity of $500 million of 5.25% notes tomorrow, our total debt principal outstanding would be approximately $30 billion. Assuming the first call date of the hybrids, the average maturity of our debt portfolio was 16.3 years. Assuming the final maturity date of the hybrids, the average life of our debt portfolio is 20.4 years. Our effective average cost of debt is 4.5%.
When looking at our capital needs for 2020, we have $1.5 billion of total debt maturing, including the $500 million that matures tomorrow. That leaves the remaining $1.5 billion of proceeds from the debt offering available to fund approximately 50% of our $3 billion to $4 billion of growth capital expenditures for 2020.
Moving on to distribution payments and the distribution reinvestment plan. Our distribution declared with respect to the fourth quarter of 2019 is $0.4450 per unit and will be paid February 12. This distribution represents a 2.3% increase when compared to the same quarter of 2018.
As mentioned in the press release this morning, based on current expectations, we plan to recommend to our Board to continue our $0.0025 per unit per quarter increase to our quarterly distribution rate for 2020.
This would result in aggregate distributions declared with respect to 2020 of $1.805 per unit that compares to $1.765 per unit for 2019. We also intend to use approximately 2% of our 2020 cash flow from operations to buyback our common units during 2020.
Using 2019 as a base, these proposed distribution increases and the unit buybacks would result in about a 5.6% increase in the amount of capital that we are returning to limited partners in 2020 compared to 2019 of which 60% of this increase is through buybacks.
If we are successful in retaining our spread income in 2020 at 2019 levels and if free cash flow was higher, one of the things that we can also consider again, the potential for higher buybacks.
Beginning with our August 2019 distribution payments, the delivery of common units under the dividend distribution reinvestment plan and our employee unit purchase program are satisfied through open market purchases instead of issuance of common units.
Affiliates of our general partner purchased approximately 2.2 million units in the open market for $58 million in December. In total during the fourth quarter between open market purchases by the distribution reinvestment plan, our employee plan and affiliates of our general partner, approximately $95 million or 3.6 million EPD units were purchased in the open market. Affiliates of our general partner have also expressed their intention to continue buying EPD units in the open market in 2020 on an opportunistic basis.
The last thing I'll cover today is the Liquidity Option Agreement related to our acquisition of Oiltanking Partners in 2014. This agreement was filed with the SSC on August 1, 2014 and I refer you to that document for more detail. Marquard & Bahls, I'll call, M&B owned its interest in Oiltanking through a U.S. Corporation named Oiltanking Holdings, which I will call OTA.
OTA owns the 54.8 million EPD units that were issued as consideration in the transaction. Our estimates OTA currently has a deferred tax liability of approximately $500 million associated with those units. Under the terms of the Liquidity Option Agreement, MMB has the option to put 100% of the common stock of OTA to Enterprise within a 90-day period commencing February 1, 2020. We fully expect MMB to exercise its option.
It is Enterprise's option to purchase the common stock of OTA with any combination of the EPD common units or cash. The price of the EPD units is based on the 10-day VWAP immediately prior to the exercise date.
With regard to the effect on EPD unit count upon completion of the transaction, OTA would be consolidated into EPD and the EPD units owned by OTA would be treated as treasury units with any cash payments between EPD and OTA eliminated in consolidation.
For illustrative purposes, if OTA still owns 54.8 million EPD units and if Enterprise settled the acquisition of the common stock of OTA by issuing 54.8 million EPD units, it would not have any impact to our current outstanding unit count given the offsetting nature of the new units issued to MMB with the 54.8 million EPD treasury units held by OTA.
Currently, we have not made a decision regarding how we will settle the purchase of OTA common stock if and when it put to us under the Liquidity Option Agreement. We will need to see what the 10-day VWAP is at the time of the exercise. Frankly, price based on a 10-day VWAP without a discount may not provide a great deal of incentive for a large cash component.
Finally, since 2014 we have been accruing a liquidity option liability. The primary purpose of accruing this liability was to estimate OTA’s deferred tax liability that we might assume. At December 31, 2019, the liquidity option liability accrued on EPD’s balance sheet was approximately $510 million.
At the closing of the acquisition of OTA common stock, we would eliminate the liquidity option liability on EPD’s balance sheet and replace it with the OTA deferred tax liability. Any difference between the two would be a non-cash adjustment recorded to the income statement.
Generally, OTA's deferred tax liability would continue to be deferred and not be triggered unless we sold the EPD common units owned by OTA and we have no plans to do that. Once the transaction is completed, we currently estimate the cash income taxes incurred at OTA related to the taxable income allocated to 54.8 million EPD units owned by OTA will range from zero to $20 million per year, and we believe in 2020 it would be zero.
With that Randy, I think we are ready to open it up to questions.
Dylan, we're ready to take questions from our audience.
Thank you, sir. [Operator Instructions] Our first question comes from Shneur Gershuni from UBS. Please go ahead.
Hi. Good morning, everyone. I was going to say congratulations on the promotions, but I'm going to say congratulations on answering the calling. Just two quick questions here. I'm going to avoid the Oiltanking question. I'll leave that for later. But I was wondering if we can start off with the Crude segment. Obviously, the segment has been one of the beneficiaries of tight spreads. You sort of talked about the leverage ratio being 325 versus 350 if you exit out.
With the capacity coming online, some of the frothy opportunities have come out. Can we view the new 4Q or the 4Q result is kind of the new run rate level from there to build organic growth? Or said differently, is the unit margin run rate in 4Q kind of what we should be thinking on a go-forward basis?
Yes, sure. I wouldn't necessarily use fourth quarter as a run rate because we'll have additional volumes that will be flowing under, if you would, our interest in the Wink to Webster project that would start in the second half of this year. And then also with what we're expecting under that would flow in Midland-to-ECHO 4 in 2021 as we continue to see an increase in crude volumes going through the pipe. Some of that to the extent that we're benefiting from some spread opportunities and when we saw spreads contract that would be an offset. But again, we're looking at pretty good volume growth over the next couple of years flowing through those pipes.
This is Jim. As a matter of fact, we signed the contract last night with a pretty big producer that ran 65,000 to 75,000 barrels a day with an associated dog deal. So we’ve got some pretty good – pretty strong contracts to support those pipes.
Okay. That makes total sense. And then maybe if we can just shift over to the LPG export side. I was wondering if you can talk about the status of the contracting type market at this point right now. Are you able to use the strength of the market to put in place contract terms that are even longer in nature than typical and at higher rate than typical? Like if you can sort of talk about what it would be like to negotiate a three-year contract today versus let's say a year-ago, what it would be like to contract the three-year type contract? Would it be at a higher rate? And would it be now for four years or even five years? So just wondering if you can sort of talk about how it's changed the dynamic of contract?
We're fully contracted for next year. By definition and by design, we chose to do shorter terms because these were lower. We had a targeted level, we chose to lease some available for spot, which frankly was a good thing. And we think as time goes on and volumes grow, having a one-year to two-year contracts at the fees we were getting is a smart thing because we think those spreads will widen over time as volumes grow. Brent?
I think the fees that we have out there right now and the fees that we're talking with the customers, the fact of the matter is those fees worked for us. And why they worked for us is because we have expansions in Brownfield projects that frankly are very attractive returns for what we invested over the last, call it, decades. So the opportunities for Enterprise to participate is we're going to contract such that we're comfortable operationally that we can satisfy all the contracts with customers. And if Graham and his team exceed those expectations and that creates opportunities in the spot basis. In terms of doing two-year, three-year, or four-year type contracts, the fact of matter is the levels that we're doing them right now. I think our customers, both domestically and internationally and frankly Enterprise are very happy with those numbers.
All right. That’s it for me. Those were my key questions. Thank you very much guys and congratulation.
Thank you. Our next question comes from Colton Bean from Tudor, Pickering, Holt. Please go ahead.
Good morning. Just wanted to follow-up on the discussion of buybacks. I think you mentioned if cash flow from ops comes in stronger than 2019 and you see upside there that could result in a higher buyback level. Are you still thinking about that as 2% of the incremental cash flow or would it basically be anything over and above 2019?
Okay. Colton, I'm sorry, the volume was really low. Could you repeat your question?
Yes. Sorry about that. I'm just trying to understand on the discussion around buybacks, I think you mentioned that you're at – currently thinking about 2% of cash flow from operations, and if you come in higher than that number, particularly higher than you were at in 2019, you could see the buyback number move higher. Are you still thinking it would be 2% in aggregate or basically anything over and above 2019 might be directed towards buybacks?
I think going into 2020, our thought is, that we would use approximately 2% of the cash flow from operations. And some of that as Jim mentioned, we forecasted some of those spread opportunities not continuing into 2020. If we saw some of those opportunities continue into 2020, then that's what would give us potential to come in and think about doing additional buyback.
Okay. And so the right way to interpret that is, if you had, say all $500 million should back up, it would be 2% of the $500 million?
Colton, I don't know if we would be that – I don't know if we would come in and be that limited on it.
Understood. And just to follow-up on Shneur questions around LPG, thinking a little bit more short-term in nature here. I think you all have highlighted the gross capacity versus kind of a typical operating rate, is there any opportunities you all see maybe in Q1, Q2 here to get that operating rate closer to gross capacity?
This is Brent. I mean, I feel better about it in 2Q and I feel better about it in 3Q. I mean, there's things that we can't control, whether it's something that happens in channel or fog or things of that nature that frankly first quarter it's a little tough. But I mean, look it's never going to be 100%, ships got to move, I mean it’s just not the most efficient movement.
But in terms of trying to get it above 70, 75 to the 80 type number there's things that we can do that we have control over, you guys hear us talk about using some of our offsite crude terminals to enhance that. It's about trying to optimize around the channels so that we can move vessels between docks. So I think typically as things come up, Enterprise gets better and better and we start moving more and more volume. I'm just trying to set your expectations of what you can see. And I think, if I think if we're doing somewhere, Graham and probably the 80% type number. That's a pretty good operational mode for us.
For that type of facility, but we continue to challenge ourselves to get that last increment out every day. And we'll see the results over time.
Yes, I'll jump in. I don't think anybody has a utilization rate we have. I spent a lot of time at another company and another career and we never came close to the utilization rate that we have at Enterprise. We focus on keeping that refrigeration unit running all the time. And I forget, Bob, what is our utilization on that refrigeration unit? Do you have any idea?
I don't have it off the top of my head completely, but it's going to be in the upper-80s.
And we use our lay berths. We make sure that we got ships sitting here and just – and has come up with some creative contracting ideas that work effectively for us.
Thank you. Our next question comes from Spiro Dounis from Crédit Suisse. Please go ahead.
Hey, good morning, everyone. I mean just starting off with the CapEx guidance for 2021 that $2 billion to $3 billion range. Could you guys give us a sense of what ultimately is going to drive you to the higher low end of that range? And it looks like spot is not included in that overall backlog. Is that the main driver? And how should we think about the impact that could have in 2021?
Yes. You're correct that the offshore terminal is not included in that. That's still in the application phase, in the approval phase with Myriad. And frankly, we don't look for the earliest that that project could be approved by Myriad is probably the second half of this year. And then on spot, I still think we could be in the range of $2 billion to $3 billion in 2021 even with spot. Because I think we've also had some discussions as far as with joint venture partners around spot. So I think we would still be in that $2 billion to $3 billion even with spot included in that number.
And with spot, I think in order to get people on spot, I think we're going to – they're going to own equity, Brent, and we're not driven to own 100% of spot. If you'd think about it, our value lies upstream of spot, a lot of our value and it wouldn't bother me for us not to own more than 40% of spot in the final analysis.
Got it. That's very helpful. And then just on Wink to Webster, can you maybe provide a little more color on why you decided to move forward under the UJI structure? And any more specifics on the mechanics basically how this ties into your current system? And just lastly on that, any sort of capital avoidance you can sort of expect as a result of this?
Well, it's a pipe in a pipe. So we do our own scheduling. The other partners have no idea whose barrels around that pipe. So other than turning valves, we operate the thing just like we do our other pipelines. And when you look at it on a per barrel basis, it's pretty cheap pipeline. Brent?
Yes. One thing I'd add on that is, it's undivided joint interest or pipe within a pipe. And if you look at how Enterprise optimizes assets, I mean, it's just a lot easier for us to optimize something that is 100% owned by Enterprise. So that was the thought behind it. It's a very competitive rate. Obviously, there's economies of scale when you're building a pipe that big. And then when you're building a pipe that big and just have an Enterprise to deal with in terms of how we go about our daily business, that's why it makes sense for us.
Got it. Appreciate the color. Thanks, everyone.
Thank you. Our next question comes from Tristan Richardson from SunTrust. Please go ahead.
Hey, good morning, guys. Appreciate the context and perspective on Slide 5 as it relates to payout. As it relates to returning cash in the way you've normally defined a target for repurchases this morning? Can you share your thoughts on defining this repurchase target on a regular basis, whether it would be annually or otherwise?
Tristan, we’re, to a degree, we're entering into a new phase to a degree. And with – again in 2020, we've got – we have the $3 billion to $4 billion of growth CapEx. Then when we come in and look at 2021, $2 billion to $3 billion, given that our leverage is in the middle of our target range.
And if we come in, and again the organic projects that we have, we like, we're going to be very capital disciplined in here. But we're entering in a phase that if our leverage is where if we're comfortable with it being, and we continue to see the business performed the way it does, growth CapEx in that $2 billion to $3 billion range, not only will we have free cash flow as we define it, but then we will also have additional cash flow just when you come in and even after you subtract dividends.
So we really enter into it a whole new period of flexibility and where we have the potential if we don't see compelling organic opportunities then – and the balance sheet is where we like it. I think that comes back to that you're looking to come in and return more capital to partners.
Helpful. Thank you. And then just a follow-up question, just on Shin Oak, I may have missed it in the prepared comments, but can you talk about volume sequentially in the quarter and how we should think about kind of general trajectory there?
Tug, you want to take it and then I'll jump in?
Yes, sure. This is Tug Hanley. With respect to Shin Oak, its part of our entire system in the Permian integrates with our MAPL system or Seminole Pipeline or Chaparral Pipeline. So there's some seasonality associated with the volumes. For example, Conway to Mont Belvieu could impact flows on Shin Oak. What that said, Mentone is online. We're seeing higher volumes. Presently, we're seeing around 300,000 barrels a day and we've also been successful in getting some additional contracts recently. And we're in discussions with multiple parties right now on even more contracts. So we're going to keep driving forward and get it both.
How much you’re flowing on Shin Oak?
300 a day.
Okay. So we're flowing 300 a day and that's without Alpine High doing what we expected it to do. And I spoke in my script about some underperformance in Orla. We have back-filled that as I said in my script, the best supply you can have or full processing plants and we're going to have full processing plants on a go forward basis. In addition, Tug's in some negotiations with people to get third-party movements on that pipe.
Thank you guys very much.
Thank you. Our next question comes from Jean Ann Salisbury from Bernstein. Please go ahead.
Good morning. Just one for me, a lot of frac capacity is coming online in the first half of this year? Can you just give us the latest of what you're seeing? If there's been pressure on recontracting rates because of that?
Zach, do you want to freeze up or you want to take it?
So far there's been still a good appetite when we go and look at all of our contracts. One or we don't have a whole lot of contracts rolling off a good period of time. But even when we would go in and I didn't talk to producers, I think the market is normalized. I think we were in a bit of an abnormal market for 2018 and 2019 and the market is normalized on contract rates normalizing on term, but we still see it, how the appetite for producers to take out fresh lists.
Are you full?
We are more than full.
So you're overflowing, Louisiana?
Overflowing in Louisiana, overflow in storage. Every frac their inner portfolio is full.
We're not too concerned at this point.
Cool. That's all for me. Thank you.
Thank you. Our next question comes from Christine Cho from Barclays. Please go ahead.
Good morning. I'd like to extend my congrats everyone on their new position. Starting with CapEx opportunities, post 2021, what do you see the opportunities for spending being, just as an industry we seem like we're going to be well capacitized on fractionation and LPG export front? For the next couple of years, after fourth quarter of this year, especially if production continues to slow and we seem to be over capacitized on Permian crude and NGL pipe, there'll, beyond the spot project or the opportunities just more bolt-on or does it increasingly become more Petchem oriented?
We think Petchem is a bolt-on Christine. But in terms of slowing production, what Tony tells us is what is it 500,000 to 750,000 barrels a day of growth of crude in 2020, growth will obviously slowing but production is not slowing. And when we take a long-term look, currently let's say after 2025. We expect production to continue to grow particularly in the Permian basin. It is the standout in the United States.
I'm having a hard time with 500,000 to 750,000 barrels a day being slow growth, frankly. But in terms of where we go from here, we like primary petrochemicals, so PDH 2, we like. We got one heck of anchor customer. We like creating a petrochemical midstream service business meaning storage and pipelines in both ethylene and propylene.
We like our export position. We think that grows and we're doing things as you know, to expand that. So that's what I see is doing. I don't see any big acquisitions or anything like that unless some hellacious deal comes along, but I see us continuing to go downstream and using that as leverage to do more upstream.
Okay. Helpful. Thanks. And then I know there were a lot of questions on the LPG exports, but I actually have a question on the ethane exports and demand out there? We don't seem to get that much variability in the ethane export volume, even when ethane prices moved pretty low. So is it fair to say that the markets abroad are absorbing as much ethane as possible? And if we're to see an increase here and more facilities that can take ethane as a feedstock needs to be built?
Yes, I think it's fair to say that it's a point-to-point commodity and what people have to spend to receive it as much small dollars to ship it as much small dollars. So I think it evolves we said when we put that project in that this was not going to be like LPG is going to be a point-to-point milk run type of the deal and that's what it is. And in order to grow that, and we have a lot of people talking to us, but they've got to spend money to be able to receive it.
In that context, do you think that like just given all the dynamics that LPG exports being pretty constrained, that like ethane could go methane negative this year?
Well, if it does, we'll go make a lot of money, but I don't think so personally.
Okay, great. Thank you.
Thank you. Our next question comes from Jeremy Tonet, from JPMorgan. Please go ahead.
Yes. Good morning. This is Charlie. First question just on project timing, notice frac 10 and 11 slipped the bed also didn't see ATEX expansion anymore? Just wanted your thoughts there?
Justin or Zach?
Yes. We did see him slip slightly. I think we had a pretty aggressive schedule to start with. But from the impact to Enterprise, we were still taking all the product that was contracted for 10 and 11. We've got a best-in-class storage facility and so those – all that white grade is going there and our producers don't even know. So once I get up we'll frac it all out of storage.
And ATEX?
Yes, we're still moved. This is Tug. We're still moving forward with ATEX expansion it's going to be sometime in 2022, early 2022.
Okay. And then some buybacks, when thinking about the 2%, is this before or after working capital changes? Just thinking about newer projects coming into service net impacting operating accounts?
When we think about it, and when you look at sort of – when we take it in context, as far as when we compare to the other S&P sectors, it is the gap term, cash flow from operations. And so it is after working capital changes, but working capital changes can be quite positive too.
Okay, great. And then sorry one last one and I know you guys get the question a lot, just your thoughts on C-Corp conversion just giving kind of the price reaction we saw last December after the conference in a commentary there?
Yes, really no updated thoughts around that at this point in time, something that we continue to look at, but really no update on the vault.
Okay. Thank you.
Thank you. Our next question comes from Pearce Hammond from Simmons Energy. Please go ahead.
Good morning and thanks for taking my questions. My first question is you've discussed the possibility of redirecting Midland-to-ECHO to back to NGL service. Just curious what the latest was on that?
The latest is, it’s staying in crude service for the foreseeable future, but we have the option to always – it's kind of a need option. We can take it out of crude service from putting in NGL service and then we can take it out NGL service and put it back in crude service. It's called an option, isn't it Brent?
We might call it.
Great. And then as a follow-up, one thing during the Q4 earnings season thus far has been weakness in the global chemical sector. And just curious if you're experiencing that in your Petrochemical segment and what's your outlook is for the segment for 2020?
Chris?
Hi, this is Chris D'Anna. Overall, our demand still remains fairly strong. We've seen some weakness at the end of fourth quarter in our export volumes to Europe, but that demand is picking back up again.
Great. Well thank you.
Thank you. Our next question comes from Keith Stanley from Wolfe Research. Please go ahead.
Hi. Good morning. First just wanted to revisit the sources and uses of cash for 2020. So you mentioned the $3 billion debt offering, $1.5 billion maturities, and then you said the remaining $1.5 billion could fund about 50% of growth CapEx give or take. It seem like, I think 2019 you did at least $2.5 billion of DCF above the distribution.
So it seems like you're going to have excess cash on the balance sheet above what's needed to fund CapEx this year. So can you just talk about how you would look to deploy that? Do you wait and see how CapEx shakes out? Would you pay down debt or just how you're thinking about that?
Keith, right now we're just seeing how the year progresses. But again, we've got $3 billion to $4 billion of growth CapEx, and even if you come in and you've say we're at the midpoint of that range of $3.5 billion of growth CapEx, you divide that – multiply that by 50%. That's 1.75. So that would totally consume the remaining proceeds from the debt deal then we would be coming in and using either. Again, cash flow from operations or borrowings under our credit facility to come in and fund the remainder.
Okay. It just seems like cash flow from operations and the remaining portion of the debt funding is going to be more than you need for CapEx in 2020. Is that how you see it looking out right now?
Yes. Keith, we're getting early into the year. Yes, we may exceed that, I mean some of that – one of the reasons we're talking about coming in and do it and using 2% of the cash flow from operations for a buyback.
Okay, great. And then – apologies for this. I'm not sure I'm fully understanding the Midland-to-ECHO 3. So Jim, I think you said it wouldn't run more than 200,000 to 300,000 a day before Wink to Webster starts up. So I just want to clarify, any three is still a separate pipeline or expansion project for you that's distinct from Wink to Webster at this point?
Three is a part of Wink to Webster as an undivided joint interest. So it's a pipe in a pipe.
Okay. So there's no incremental capacity that you guys are separately adding in 2020. It's just you are now partners on Wink to Webster?
That's exactly right.
Great. Thank you very much.
Thank you. Our next question comes from Ujjwal Pradhan from Bank of America. Please go ahead.
Good morning, everyone. Thanks for taking my question. Two quick ones. First, just want a bit more clarity on the buyback guidance today. Should we consider the guidance as more of a programmatic perhaps on a quarterly basis or will it be opportunistic like last year?
Again, I mean, what we're intending to do this year is intending to use 2% of cash flow from operations to come in and do buybacks. Now we'll do that opportunistically during the year. I don't know if you want to say we're going to be opportunistically programmatic or programmatically opportunistic. That's what we're intending to do.
Got it. And another quick one. I remember last year when we had the constraint in the Permian and you're moving quite a bit of a spot volumes. I think you mentioned that the cost of using DRA were as high as $2 per barrel. Has that abated now that there's been more capacity moving the barrels in the Permian?
I think we're still using some DRA. Graham?
We're still using it. We've learned to optimize it. We can get that incremental. That $2 was the last incremental barrel. And we watched that very closely and have done some things. Not doing $2 a barrel.
I think one of the things though that – and Brent can jump in. We're going to have four pipelines out there. When we optimize those four pipelines, we're probably moving 1.3 million, 1.4 million barrels a day, Brent.
Yes.
And that's optimizing it. So you're getting the lowest cost possible. But if you – if the spreads there, we can probably take that to 1.8 million barrels a day at a cost using DRA.
Yes. That assume Seminole in service, but you guys just like everybody else, I mean we have our cost of what the next tranche is.
Got it. Thanks. That helps.
Thank you. Our next question comes from Michael Lapides from Goldman Sachs. Please go ahead.
Hey guys. Thanks for taking my question and congrats everybody on executive announcements. I hate to ask this one because it's obviously very unfortunate and very scary globally, but are you seeing in January at all in impacting the export markets yet for either crude or NGLs giving what's going on in China and how it's impacting business and how it's impacting demand in China?
Can you just kind of talk about what you've seen over the last couple of weeks and how you think about the range of the impacts on – including on your guidance levels for – and your outlook levels for how you're thinking about 2020?
Yes, this is Brent. So the quick answer is we haven't seen an impact in terms of volumes. We haven't seen an impact in terms of fees at the dock. And whether its freight rates or whether it's this, I mean there's things that happen and I think that what you'll see on our system, it's no different when we pick out tranches to move from Midland-to-Houston. The people that are the most cost efficient are going to move the volumes.
And so people who are the least cost efficient start turning off or start decreasing volumes. And we'll look at different markets and look at different operators and look at different lack of integration of one owner. And my guess is those are the ones who are probably going to experience that sort of situation first. And the ones that are most cost efficient will continue to move the volumes.
Got it. Thank you. One quick follow-up. In the quarter, you talked about Midland-to-ECHO 1 a little bit in the release. Can you just give a little more detail in terms of kind of what's happening on the pricing or tariff side there relative to either the prior quarter or prior year?
This is Brent again. I mean, in terms of tariff, I mean it's not a whole lot different than the last question. I mean, the volumes don’t change, I mean that pipeline is been full every single day. In terms of how the economics work on that, my personal opinion, I think shipowners win because things get less efficient from a shipping perspective, but ultimately it's consumers or the producers of the product that ultimately bear that cost.
Got it. Thanks guys. Much appreciated. And I will obviously follow-up offline with Randy and team. Thanks.
Dylan, this is Randy Burkhalter. We have time for one more question please.
Sure. Thank you, sir. Our last question comes from Danilo Juvane from BMO Capital Markets. Please go ahead.
Good morning. Thank you for squeezing me in. One question of clarity here. How are you guys thinking about the buyback relative to the 2% of CFFO, if you take out the Oiltanking units in cash versus equity, does that change that calculates for you?
Yes. I mean, in our mind that would be a plan. I mean, you could come in and say that's a plan, some of the buyback against the OTA. In our mind to the extent that we use cash consideration on the OTA transaction, that essentially would be a buyback.
Got it. That's it for me. Thank you.
Thank you. Dylan, would you give our listeners the replay information?
Sure. Thank you, sir. This call is available for replay starting today, the 30th at 1:00 PM through February 6th at 11:59 PM. To access the replay, you will need to dial (1800) 585-8367 and enter the replay code 9596106. Again, the dial in number is (800) 585-8367, replay code 9596106.
Thank you. We'd like to thank everyone for joining us today and that ends the call. Have a good day.
Thank you. Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.