Ladies and gentlemen, thank you for standing by, and welcome to the Q4 2019 Enterprise Products Partners LP 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 Please be advised that today's conference is being recorded. 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 Q4 2019 earnings. Our speakers today will be Jim Tee and Randy Fowler, Chief Executive Officers 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 and 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 Valley and 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 $4,600,000,000 or $2.09 a unit, that's a 10% increase from 2018. DCF increased 11 percent to a record $6,600,000,000 and provided 1.7 times coverage.
We retained 2 point $7,000,000,000 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 reporting increased results, including 28 operating and financial records. We set 13 operational records, including almost 2,000,000 barrels per day of marine terminal export volumes, 6,700,000 barrels a day of liquid transportation volumes and 10,400,000 of barrels of oil equivalent per day total system transportation volumes.
During 2019, Enterprise completed construction and began service on approximately $5,400,000,000 of capital projects, including $2,500,000,000 that were completed in the 4th quarter. In addition, we have another $7,700,000,000 of projects underway. Substantially, all of 20 nineteen's major projects were completed on time and on budget. In addition, we're in discussions with potential JV partners in projects that beat our downstream value chain. I'd like to give a shout out to operations for successfully commissioning 5 major new assets from late September to the end of Q4: LPG export expansion, IBDH, our Mentone gas processing plant, our Panola Bulldog gas processing plant and Phase 1 of our ethylene export terminal.
Frankly, we should have built the Panola Bulldog plant 5 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 5 years ago was as complete and large gathering system as we have today. Supporting that project at 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 as a joint venture partner got me over the hump, but I think Chris Deanna and his team, along with the Navigator team, went on a mission to prove me wrong. They are on the verge of executing a 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 1 of the largest producers in the Delaware Basin.
A few words about gathering and processing. There are essentially 2 types of gathering and processing contracts that we enter into. The first is demand fee or said another way, tech or pay contracts where a producer commits to a volume at a fee that is paid whether the volume is there and is delivered or not. The second type is an acreage dedication. That's where a producer dedicates everything he produces from a defined acreage up to a set maximum daily quantity and that or MDQ, and that's the amount that we have to provide services 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 is 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 $300,000,000 a day take or pay contract with a large investment grade producer. These type
of clawback options allow
us to maximize the allow us to maximize the use of our capacity and, in this case, defer capital as much as 2 years. Our IBDH start up in December started up in December. As a result, our beef plant and our high purity isobutylene plants are running at capacity and our anchor customers taking their contracted volume. Because there's a ramp for our 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 Q3. We have contracted that terminal to a targeted level and through efficient scheduling 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 4 crude oil pipelines out of the Permian. One of these pipelines, M2E3, is a 36 inches pipeline we are building that upon completion of construction will be jointly owned by M2E3 and Wink to Webster. We will own as an undivided joint interest 29% of Wink to Webster.
The project should be complete to our Echo terminal by August and to Webster by the end of the year. I don't expect more than 200000 to 300000 barrels a day to flow until the Webster leg is complete. If you think about it, in those 4 pipelines, with just our contracted volume and a 0 terminal value, they will deliver a mid teen IRR to enterprise. Our upsides are the additional fees we collect for storage and for exports and any marketing activities. PDH-two is underway, the 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 PDH2 is up, we will produce more than £11,000,000,000 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 are spreads, they're not as robust as they were last year. That said, we expect spreads to the water to grow in LPG, in crude oil and in petro chemicals, 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 $500,000,000 I look at our footprint and I see other opportunities backwardation, contango, cross product, as I said, to the water on all hydrocarbons. We have RGP to PGP.
We have normal butane to isobutane, and 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 Chris Wade and let him shutter as I've got unscripted comments to make. We issued a 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 be will remain a part of the Office of the Chairman with Randa and Hank Bachman, and we will also stay on the Board. Randy and I don't compete with each other, we complement each other. We're truly a team and we've been together for over 20 years, so we are friends and we respect what each other brings to the table. The other announcements we made today are senior management team that is accomplished with complementary 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 a damn tall he has a presence.
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 Neely has a style that is disarming and a work ethic second to none.
Bob Sanders, well, Bob is 40 years with us and he's our go to guy. He knows where every piece of steel is. Not mentioned was Tony Chovanik, who has built so much credibility that everyone wants his group's forecast. Then we have Penny, 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 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 a friend, Randy Pallor. 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 Q4. Net income attributable to limited partners for the Q4 of 2019 was $1,100,000,000 or $0.50 per unit on a fully diluted basis. Net income for the Q4 of 2019 included a non cash impairment and related charges of approximately $82,000,000 This is primarily related to our non cash mark to market losses of 25,000,000 noncash mark to market losses of $25,000,000 Together, these noncash charges were approximately $0.05 on a fully diluted unit. Net income for 2018 included noncash impairment and related charges of approximately $29,000,000 and a noncash mark to market gain of $237,000,000 or a combined $0.10 fully diluted unit.
Excluding these non cash items, EPU for the Q4 of 2019 increased by 13% compared to the same period in 2018. Moving on to cash flows. Cash flows from operations was $1,700,000,000 for the Q4 of 2019 versus $1,900,000,000 for the Q4 2018. Excluding changes in working capital accounts, cash flow from operations for the Q4 of 2019 was 11% higher than the Q4 of 2018. Free cash flow, which we define as we use the Bloomberg definition, cash flow from operations minus investing activities and then we add back joint venture contributions or contributions from joint venture partners was $2,500,000,000 for the full year 2019, which was 24% higher than free cash flow for 2018.
We define 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 Q4 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 9 months of 2019, Enterprise's 59% payout ratio is the 4th highest compared to the median payout ratios for the S and P 5010 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 15th percentile of all S and P 500s for a percent of cash flow returned to equity investors. In terms of total payout ratio, Enterprise ranked in the 41st percentile of all S and 500 Companies. Our total capital investments for the Q4 2019 were $1,200,000,000 including $1,100,000,000 of growth capital investments and $93,000,000 of sustaining capital expenditures. Total investments for 2019 were $4,700,000,000 which includes $4,300,000,000 of growth capital investments, which is reduced to $3,700,000,000 after subtracting contributions from our JV partners. Sustaining CapEx for 2019 was 325,000,000 dollars For 2020, we currently expect our growth capital expenditures will be in the range of $3,000,000,000 to 4 and sustaining capital expenditures will be approximately $400,000,000 For 2021, we currently expect growth expect growth capital expenditures will be in the range of $2,000,000,000 to $3,000,000,000 One of our most important goals 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 $4,900,000,000 at December 31, 2019, which included available borrowing capacity under our credit facilities and unrestricted cash of about $300,000,000 Adjusted EBITDA for the trailing 12 months ended December 31, 2019, was $8,100,000,000 and our consolidated leverage was 3.25 times after adjusting debt for the partial equity credit that we receive for the hybrid debt securities by the rating agencies and also reduced by unrestricted cash. If we normalize adjusted EBITDA for $500,000,000 of spread opportunities in 2019 that we believe were wider than normal, we estimate that our leverage ratio would have been 3.5 times for 2019, which is at the midpoint of our range for our targeted leverage. On January 6, we priced an aggregate $3,000,000,000 of senior unsecured notes comprised of $1,000,000,000 of 10 year notes at a 2.8 percent coupon, dollars 1,000,000,000 of 31 year notes at 3.7 percent and $1,000,000,000 of 40 year notes at 3.95%. We'd like to say thank you to the strong support from our fixed income investors.
After adjusting for the proceeds from our $3,000,000,000 notes offering and the maturity of $500,000,000 of 5.25 percent notes tomorrow, our total debt principal outstanding would be approximately $30,000,000,000 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 $1,500,000,000 of total debt maturing, including the $500,000,000 that matures tomorrow. That leaves the remaining $1,500,000,000 of proceeds from the debt offering available to fund approximately Moving on to distribution payments and the distribution Moving on to distribution payments and the distribution reinvestment plan.
Our distribution declared with respect to the Q4 of 2019 is $0.445 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 $0.25 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 $0.01765 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're 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 is higher, one of the things that we can also consider is again the potential for higher buybacks. Beginning with our August 2019 distribution payment, the delivery of common units under the dividend distribution reinvestment plan and our employee program are satisfied through open market purchases instead of issuance of common units. Affiliates of our general partner purchased approximately 2,200,000 units in the open market, for $58,000,000 in December.
In total, during the Q4, between open market purchases by the distribution reinvestment plan, our employee plan and affiliates of our general partner, approximately $95,000,000 or 3.6 1,000,000 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 our acquisition of Oil Tanking Partners in 2014. This agreement was filed with the SEC on August 1, 2014, and I refer you to that document for more detail. Marquard and Ball's, I'll call M and B, owned its interest in oil tanking through a U.
S. Corporation named Oil Tanking Holdings, which I will call OTA. OTA owns 50 owns the 54,800,000 EPD units that were issued as consideration in the transaction. By our estimates, OTA currently has a deferred tax liability of approximately $500,000,000 associated with those units. Under the terms of the liquidity option agreement, MMV has the option to put 100 percent 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 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's 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 54,800,000 EPD units and if Enterprise settled the acquisition of the common stock of OTA by issuing 54,800,000 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 54,800,000 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's 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, a 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 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 $510,000,000 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 2 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 54,800,000 EPD units owned by OTA will range from $0 to $20,000,000 per year, and we believe in 2020, it would be 0. With that, Randy, I think we're ready to open it up for questions.
Okay, Dylan. We're ready to take questions from our audience.
Thank you, sir. I show our first question comes from Shuni 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 a 2 quick questions here. Just 2 quick questions here. I'm going to avoid the oil tanking 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 3.25 versus 3.50 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 Q4 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. Now some of that to the extent that we're benefiting from some spread opportunities that 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 a contract last night with a pretty big producer that grant 65000, 75000 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 rates than than typical.
Like if you can sort of talk about what it would be like to negotiate a 3 year contract today versus let's say a year ago, what it would be like to contract a 3 year type contract? Would it be at a higher rate? And would it be now for 4 years or even 5 years? So just wondering if you can sort of talk about how it's changed the dynamic of the contract?
We're fully contracted for next year. By definition and by design, we chose to do shorter terms because the fees were lower. We had a targeted level. We chose to leave some available for spot, which frankly was a good thing. And we think as time goes on and volumes grow, having 1 to 2 year contracts at the fees we were getting is a smart thing because we think those spreads will widen over time as volumes grow.
Brett?
I mean, I think fees that we have out there right now and the fees that we're talking to customers, the fact of the matter is those fees work for us. And why they work for us is because we have expansions in brownfield projects that frankly are at 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 2 year, 3 year, 4 year type contracts, the fact of the 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.
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. 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'd use approximately 2% of the cash flow from operations. And some of that is, 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 $500,000,000 showed back up, it would be 2% of the $500,000,000
dollars 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's 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?
I mean, I don't this is Brent. I mean, there's 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 how I mean, look, it's never going to be 100%. Ship's got to move. It's just I mean, I mean, look, it's never going to be 100%.
Ship's got to move. It's just not the most efficient movement. But in terms of trying to get 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 off-site crude terminals to enhance that. It's about trying to optimize around the channels 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 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 you can 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 or in 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 births. We make sure that we got ships sitting there. And Justin has come up with some creative contracting ideas that work effectively for us.
Thank you. Our next question comes from Spiro Dounis from Credit Suisse. Please go
ahead. Hey, good morning everyone. Maybe just starting off with the CapEx guidance for 2021, that $2,000,000,000 to $3,000,000,000 range. Could you guys give us a sense of what ultimately is going to drive you to the high or 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 'twenty one?
Yes. You're correct that the offshore terminal is not included in that. That. That's still in the application phase and the approval phase with MARAD. And frankly, we don't look for the earliest that, that project could be approved by MARAD is probably the second half of this year.
We have and then on spot, I could I still think we could be in the range of $2,000,000,000 to $3,000,000,000 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 $2,000,000,000 to $3,000,000,000 even with spot included in that number.
And with spot, I think in order to get people on spot, I think they're going to want equity, Brent. And we're not driven to own 100% of spot. If you 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.
It's very helpful. And then
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. There's no the other partners have no idea whose barrels are on that pipe. 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. The only thing I'd add on that is when it's undivided joint interest or pipe within a pipe, 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 and the way you've formally defined the target for repurchases morning. Can you share your thoughts on defining this repurchase target on a regular basis, whether it 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 $3,000,000,000 to $4,000,000,000 of growth CapEx. Then when we come in and look at 2021 at $2,000,000,000 to $3,000,000,000 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 we if our leverage is where we're comfortable with it being and we continue to see the business perform the way it does, growth CapEx in that $2,000,000,000 to $3,000,000,000 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 a whole new period of flexibility and where if 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 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 volumes sequentially in the quarter and how we should think about kind of general trajectory there?
Doug, you want to take it and then I'll Ed jump in.
Yes, sure. This is Doug Hanley. With respect to Shin Oak, it's part of our entire system in the Permian, integrates with our Maple system, our Seminole pipelines or Chaparral pipelines. So there's some seasonality associated with the volumes. For example, Conway to Mont Belvieu could impact flows on Shin Oak.
With 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 full.
How much you're flowing on Shannon?
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 backfilled that. As I said in my script, the best supply you can have are full processing plants, and we're going to have full processing plants on a go forward basis.
In addition, Doug'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 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. 1, we don't have a whole lot of contracts rolling off for a good period of time. But even when we go in and talk to producers, I think the market is normalized. I think we were in a bit of an abnormal market for 2018 2019. The market is normalized on contract rates, normalizing on term, but we still see a healthy appetite for producers to take out frac space.
Are you full?
We are more than full.
So you're overflowing Louisiana? Overflow in Louisiana, overflow in the storage, every frac
in our 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 to everyone on their new positions. 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 production continues to slow and we seem to be over capacitized on Permian Crude and in Geo Heights. So beyond the spot project, are 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 is obviously slowing, but production is not slowing. And when we take a long term look currently, let's say, out to 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. 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 I mean, that's what I see us 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 we're using that as leverage to do more up stream.
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 volumes even when ethane prices move 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, 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 spend to receive it is not small dollars to ship it, is not small dollars. So I think it evolves. We said when we put that project in that this was not going to be like LPG. It's going to be a point to point milk run type of a deal and that's what it is.
And order to grow that, 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're
going to 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. Hi, good morning. This is Charlie. First question just on project timing. I noticed frac 10 and 11 slipped a bit, also didn't see ATEC expansion on there more.
Just wanted your thoughts there.
We've just our exact.
Yes, we did see them slip slightly. I think we had a pretty aggressive schedule to start with. But from an impact to enterprise, we're still taking all the product that was contracted for 10 and 11. Got a best in class storage facility. And so those all that Y grade is going there and our producers don't even know.
So once they get up, we'll frac it all out of stores.
And ATEX?
Yes, we're still moving this is Tug. We're still moving forward with ATEX expansion. It's going to be sometime in 2022 early 2022.
Okay. And then, just on buybacks, when thinking about the 2%, is this before or after working capital changes, just thinking about newer projects coming into service that 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 and P sectors, it is the GAAP 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 given kind of the price reaction we saw last December after the conference and the 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 vaults.
Okay. Thank you. Thank you.
Our next question comes from Pierce 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 2 back to NGL service and just curious what the latest was on that?
The latest is staying in crude service for the foreseeable future, but we have the option to always it's kind of a neat option. We can take it out of crude service and put it in the NGL service, and then we can take it out of NGL service and put it back in crude service. It's called an option, isn't it, Brent?
That's what I call it.
Great. And then as a
follow-up, one theme 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 your outlook is for the segment for 2020?
This is Chris, Dan. Overall, our demand still remains fairly strong. We've seen some weakness at the end of Q4 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 $3,000,000,000 debt offering, $1,500,000,000 maturities and then you said the remaining $1,500,000,000 could fund about 50% of growth CapEx give or take. It seemed like I think 2019 you did at least $2,500,000,000 of DCF above the distribution. So just 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 Keith, right now, we're just seeing how the year progresses.
Keith, right now, we're just seeing how the year progresses. But again, we've got $3,000,000,000 to $4,000,000,000 of growth CapEx. And even if you come in and you say we're at the midpoint of that range of $3,500,000,000 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. I was
just 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's one of the reasons we're talking about coming in 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 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, ME3 is still a separate pipeline or expansion project for you that's distinct from Wink to Webster at this point?
ME3 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 wanted 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, we're intending to do this year is to intending to use 2% of cash flow from operations to come in and do buybacks. Now we'll do that opportunistically during the year. So 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. 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 spot volumes. I think you mentioned the cost of using DRA were as high as $2 per barrel.
Has that abated now that there's a bit more capacity moving those valves 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 last $2 was the last incremental barrel and we watched that very closely and we've done some things.
You're not doing $2
a barrel? No, we're not doing $2 now.
I think one of the things that and Brent can jump in, we're going to have 4 pipelines out of there. When we optimize those four pipelines, we're probably moving 1,300,000, 1,400,000 barrels a day Brent. And that's optimizing it. So you're getting the lowest cost possible. But if you if the spread is there, we can probably take that to 1,800,000 barrels a day at a cost using DRA.
Yes. That assumes Seminole is 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 the executive announcements. I hate to ask this one it's obviously very unfortunate and very scary globally. But are you seeing in January at all an impact in the export markets yet for either crude or NGLs, given 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 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 it's 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 the people who are the least cost efficient start turning off or start decreasing volumes and will 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. 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 In terms of how the economics work on that, my personal opinion, I think ship owners 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 Juvein from BMO Capital Markets. Please go ahead.
Good morning. Thank you for squeezing me in. One question on Coherity here. How are you guys thinking about the buyback relative to the 2% of CFFO if you take out the oil tanking units in cash versus equity. Does that change that calculus for you?
Yes. I mean, in our mind, that would be applying I mean, you could come in and say that's applying 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 you. That's it for me. Thank you.
Thank you. Dylan, if you would, would you give our listeners the replay information?
Sure. Thank you, sir. This call is available for replay starting today, 30, 1 p. M. Through February 6 at 11:59 p.
M. To access the replay, you will need to dial 1-eight hundred- 585-eight thousand three hundred and sixty seven and enter the replay code 9,596,106. Again, the dial in number is 800-585-8367, replay code 9,596,106.
Thank you. We'd like to thank everyone for joining us today and that ends the call. Have a good day.