Enterprise Products Partners LP (EPD) 2014 Q1 法說會逐字稿

Good morning. My name is Kyle, and I will be your conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners Q1 2014 earnings conference call.

(Operator Instructions)

Thank you. Mr. Burkhalter, you may begin your conference.

Thank you, Kyle. Good morning, everyone, and welcome to the Enterprise Products Partners conference call to discuss results for the first quarter of 2014. Our speakers today will be Mike Creel, CEO of Enterprise's General Partner; followed by Jim Teague, Chief Operating Officer; and Randy Fowler, CFO. Other members of our senior management team are also in attendance today.

During this call, we will make forward-looking statements within the meaning of Section 21-E 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.

With that, I will turn the call over to Mike.

Thanks, Randy.

We're off to a strong start in 2014, with first-quarter results that included record gross operating margin of $1.3 billion, and record adjusted EBITDA of $1.4 billion. We benefited from cash flow and volume growth associated with $4.8 billion of new assets, that began operation since the beginning of 2013. These strong results led to distributable cash flow of $1.1 billion for the first quarter of 2014, compared to $897 million for the first quarter of 2013. Included in distributable cash flow were proceeds from asset sales and insurance recoveries of $96 million this quarter, and $131 million in the first quarter of 2013. After adjusting for these items, distributable cash flow was $972 million for the quarter.

In April, we declared a $0.71 per unit cash distribution with respect to the first quarter of 2014. This distribution is 6% higher than the $0.67 per unit paid with respect to the first quarter last year. This is the 48th distribution increase since Enterprise's initial public offering in July of 1998, and the 39th consecutive quarterly increase.

Excluding proceeds from asset sales and insurance recoveries, distributable cash flow provided 1.5 times coverage of the distribution declared. We retained $418 million of distributable cash flow to reinvest in the growth of the partnership, and to reduce our reliance on the capital markets.

The NGL Pipelines & Services segment reported gross operating margin of $780 million for the first quarter of 2014. That was a record, and is 32% more than the $593 million for the first quarter of 2013. Our natural gas processing and related NGL marketing business reported a $79 million increase in gross operating margin, primarily due to higher sales margins and volumes from NGL marketing, partly related to the expansion of our LPG export terminal on the Houston Ship Channel, which was completed in March of last year.

In January of 2014, we announced another expansion of our LPG export facility that is supported by a 50-year service agreement with Oiltanking for additional dock space and related services. When this expansion is completed, which is expected to occur by the end of 2015, we will have an aggregate loading capacity in excess of 16 million barrels per month of low ethane propane and/or butane, twice the capacity that we have today. This segment also benefited from higher natural gas processing volumes, equity NGL production, and feeds from our South Texas plants. We continue to benefit from the NGL-rich production in the Eagle Ford shale.

Enterprise's natural gas processing plants had record fee-based processing volumes of 4.7 billion cubic feet per day in the first quarter of 2014, 4% higher than the first quarter of the prior year. Equity NGL production was 137,000 barrels per day this quarter, a 12% increase over the first quarter of 2013. Most of the increase in fee-based processing volumes came from our South Texas processing plants, while the increase in equity NGL production was from our Meeker and our South Texas plants.

Gross operating margin from our NGL pipelines and storage business increased $58 million or 25% to $290 million this quarter. Our ATEX ethane pipeline, which began commercial service in January of this year, generated $31 million of gross operating margin this quarter. ATEX averaged 30,000 barrels per day in the first quarter, which was below the 68,000 barrels per day of committed volumes, as certain NGL fractionation facilities in the Marcellus had unplanned outages, upstream infrastructure issues, or were still under construction and in the process of connecting to the ATEX.

These outages reduced ethane available for ATEX, as well as propane supplies available for the TE Products pipeline. The South Texas NGL pipeline system benefited from increased Eagle Ford shale production, reporting a $12 million increase in gross operating margin on a 137,000 barrel per day increase in transportation volumes. Our Mid-America and Seminole pipeline systems reported an $11 million increase in gross operating margin, primarily due to higher revenues from ship-or-pay agreements associated with the expansion of the Rocky Mountain Pipeline that began service in January of this year.

Our NGL fractionation business reported gross operating margins of $141 million this quarter, a 55% increase over the $91 million reported for the same quarter in 2013. Our NGL fractionators at Mont Belvieu generated $45 million of this increase, as fractionators 7 and 8 began commercial operations during the fourth quarter last year. Total fractionation volumes increased 12% to a record 792,000 barrels per day this quarter, compared to the same quarter in 2013.

Gross operating margin from the Onshore Natural Gas Pipelines & Services segment increased to $220 million this quarter, compared to $191 million for the same quarter of 2013. The primary reasons for the $29 million improvement were a $19 million increase from higher natural gas marketing sales, and a $10 million increase from higher transportation fees and volumes on our Texas Intrastate pipeline. Our Onshore Crude Oil Pipelines & Services segment reported gross operating margin of $160 million, down from the $236 million reported in the first quarter of 2013.

Lower margins from our crude oil marketing and related trucking activities accounted for a $111 million decrease in gross operating margins, and as we have said in the last few quarterly calls, regional price differences continue to be much lower than the record spreads we saw in first quarter of 2013. The average WTI to LLS spread was a little less than $6 per barrel this quarter, compared to almost $20 a barrel in the first quarter of 2013.

Partially offsetting the decrease in marketing was a combined $42 million increase in gross operating margin from our South Texas and West Texas pipeline systems, and our Eagle Ford joint venture pipelines, each of which had increased volumes this quarter. Total onshore crude oil pipeline volumes increased to 1.3 million barrels per day this quarter, 28% higher than the first quarter of 2013.

Gross operating margin from our Offshore Pipelines & Services segment was $39 million this quarter, which was slightly below the $41 million in the first quarter of last year. We're beginning to see crude oil volumes respond to the pickup in activity in the Gulf of Mexico. Our offshore crude oil pipelines averaged 335,000 barrels per day in the first quarter of 2014, which was the highest we've seen since the 354,000 barrels a day in the first quarter of 2010.

Currently, there are 40 drilling ships and deepwater semisubmersible drilling rigs active in the US Gulf of Mexico, and another 16 vessels are expected to arrive before the end of next year. Approximately 50% of this drilling fleet will be focused on existing fields, many of which are already connected to Enterprise assets.

The Petrochemical and Refined Products and Services segment reported gross operating margin of $130 million for the quarter, compared to $171 million in the first quarter of 2013. Gross operating margin from the octane enhancement and high purity isobutylene system decreased $38 million, primarily due to an extended period of unscheduled maintenance at our BEF octane enhancement facility this quarter.

Gross operating margin from our refined products pipelines and related marketing activities decreased $14 million, primarily due to a $17 million benefit that was recognized in the first quarter of 2013, and a provision for pipeline capacity obligations. We had a $14 million improvement in gross operating margin from our propylene fractionation and related marketing business this quarter, due to higher propylene sales margins.

We were pleased to announce last week our plans to construct an ethane export facility. We continue to receive strong interest in this facility, and are having ongoing discussions with other potential customers that could result in our fully contracting its remaining capacity. Jim will cover in this in a little more detail in a moment.

This quarter we completed $2.5 billion of capital projects, including our ATEX ethane pipeline, the Front Range pipeline that extends from the Niobrara in Colorado and connects to the Texas Express pipeline, and our Mid-America pipeline expansion. Those collectively have resulted in about 1,100 miles of new pipeline being placed into service.

We have another $2.5 billion of capital projects targeted for completion this year, and $4.2 billion planned to begin service in 2015 and 2016. These are only the capital projects that have been approved and announced, and as usual, we have quite a backlog of other projects that our commercial teams are working on. Given our extensive asset footprint, we're not lacking for growth opportunities.

Before I turn the call over to Jim, I would like to thank all of you that participated in our annual Investor and Analyst Day. That was in March. We enjoyed the opportunity to update you on our progress and future plans, and we welcome the opportunity for our deep management team to interact with analysts and investors. We're already in the process of making arrangements for next year's conference, and are currently targeting the last week in February for that meeting. If you would like to pencil in February 25, I think that's going to be about the right day.

With that, I will turn the call over to Jim.

Thank you, Mike.

On our last earnings call, we discussed, at that time we were in the midst of a significant extended winter, especially in the Upper Midwest. With winter finally over, it looks like winter in the Midwest and Plains states ranked in the top 10 coldest in the last 115 years, with the Upper Midwest officially ranking fifth. This created challenges, especially for propane and natural gas, but the bottom line is the laws of supply and demand still work.

Because of high prices, the petrochemical industry quickly moved off of propane in a meaningful way. Cargoes of LPG were diverted from Northwest Europe to the East Coast, and exports from the Gulf Coast were either canceled or deferred. Extremely high natural gas prices caused natural gas to be diverted to meet regional needs. Those who panicked were quickly reminded that price does create supply. Interestingly, the price hikes for both natural gas and propane were not very long, as suppliers responded quickly to dislocations.

Mike mentioned, in the first quarter one of our biggest challenges was an unplanned and significant outage at our BEF unit. The north to south crude oil spreads were lower, and frankly, we expected that. We knew $20 spreads couldn't sustain themselves.

Other Enterprise businesses, however, including the considerable amount of new infrastructure we have added, were quick to pick up the slack. We put in our Mid-America Rocky Mountain expansion, our Front Range pipeline, and our ATEX ethane pipeline. This ATEX pipeline is pretty important to the producers in the Northeast. Now they have the reliable ethane solution so they can continue drilling for liquids-rich gas, and no longer be threatened by too much ethane in their residue gas.

We've got several other significant projects under construction. We're continuing to move forward on our PDH plant. It is expected to be commissioned in the first quarter of 2016.

Phase one of the Aegis ethane header to Lake Charles should be up and running during the first quarter of next year. If you think about it, Aegis, in combination with our ethane pipeline to Corpus, we will have an ethane header system that literally stretches from Corpus Christi, Texas, to the Mississippi River, there for any ethylene plant that chooses to, to connect and float on our storage at Mont Belvieu.

On the crude side, our Seaway loop is expected to be completed this quarter, and we're also going to bring on another 900,000 barrels of new storage into service at ECHO. Over the next 12 to 18 months we will continue to add capacity at ECHO, as we had to -- having over 6 million barrels a day, and frankly, I think it needs to be larger. That's in conjunction with ECHO.

We also continued to build out our crude oil delivery system in the Houston Ship Channel and Texas City, which is a key to our ECHO success. We began commissioning our refined products export project, where we've completed phase one and we will begin exports of distillate this month and gasoline soon afterwards; I think in July. Work continues on our two LPG export expansions at Oiltanking, and as Mike said, we're going to begin work on an ethane export facility; and we'll soon announce the location of that.

I know we've talked about that project for a long time, and it seems like this project was a long time coming, but given the magnitude of the commitments and investments required by our customers, really, they moved pretty fast. Although there's a lot of ethylene capacity expansions planned here, producers have significantly more ethane than the US ethylene industry can consume, and they need new markets. We've tried to be clear about our views on supply and demand fundamentals.

Because of rapidly growing shale, the US and global markets have come to the realization that for many of these new molecules, we're rapidly becoming an exporting nation. We now have more natural gas than we can consume. We have more NGLs than we can consume. We have more refined products than we can consume, and we're now developing a similar long position for some types of crude, specifically growing volumes of light crudes and condensates. This will continue to create meaningful opportunities.

Our integrated assets across multiple commodities, including significant access to water, and our asset development capabilities, will continue to serve us well as we enter this new phase of global significance as a supplier of hydrocarbons. Since the expansion of the shales, our business model has been focused on providing the assets and services producers needed to handle these growing supplies, and we are going to continue to focus on their needs.

However, we're also ideally situated on the demand side of the value chain. The demand side of the value chain is integrated into all of our systems here at Enterprise. We're connected -- pipeline connected to every ethylene plant in the US.

We're pipeline connected to greater than 90% of the refineries east of the Rockies, and we're now building a critical header to connect these growing crude oil supplies to all of the major refineries in the Houston Ship Channel, Texas City, and in Beaumont-Port Arthur. We are significantly expanding our focus on the demand side of the equation, in order to take growing production to growing markets, including global markets.

With that I will turn it over to Randy.

Thanks, Jim.

I will take a few minutes to discuss additional income statement items and capitalization for the quarter. We reported net income of $807 million, and fully diluted earnings per unit of $0.85 for the first quarter of 2014. Net income included $90 million or $0.10 per unit gain from asset sales and insurance recoveries. Net income also included, although it was reduced for a non-cash asset impairment, charges of $9 million, or $0.01 per unit. After adjusting these items, EPU on a fully diluted basis would have been $0.76 per unit.

Interest expense increased $25 million to $221 million in the first quarter of 2014, due to a $13 million decrease in capitalized interest, as well as interest expense associated with higher average debt balances.

We had capital spending of $980 million this quarter, which included $78 million of sustaining capital expenditures. We currently expect growth capital expenditures for the full year of 2014 to range between $3.7 billion and $4.1 billion; and we expect sustaining capital expenditures for the full year of 2014 to be approximately $350 million.

Adjusted EBITDA for the 12 months ended March 31, 2014, was $4.8 billion. Our ratio of debt principal to adjusted EBITDA was 3.6 times for this period, after adjusting for the 50% equity treatment of the hybrid debt securities. If we further reduce debt by the $988 million of unrestricted cash on hand at the end of the first quarter, debt to EBITDA would have been 3.4 times.

We issued $850 million of 10-year notes at 3.9%, and $1.15 billion of 30-year notes at 5.1% in February 2014. The proceeds of this offering repaid debt, and are also being used for general Company purposes. We are still in the process of deploying this cash.

Based on our current plans, we do not expect to be back in the term debt market for the remainder of 2014. The average life of our debt portfolio is now 14.6 years, using the First Call date for our hybrid debt securities; and the average effective cost of debt for this portfolio is now down to 5.2%. At the end of the first quarter, we had consolidated liquidity of $5.5 billion, which included unrestricted cash, and approximately $4.5 billion of available borrowing capacity under our credit facility.

As a result of our liquidity and our performance, we elected to terminate our $1 billion 364-day bank credit facility in advance of the scheduled maturity date, which was June 18, 2014. The effective date of this termination is actually today, on May 1.

With that, Randy, I think we're ready for questions.

Okay, Kyle, we're ready to take questions from our listeners.

(Operator Instructions)

Your first question comes from the line of Darren Horowitz from Raymond James.

Good morning guys. Jim, congratulations on the ethane export project announcement. I have a few questions for you first, then maybe one for Tony. Recently, we've heard some of the petchem customers with more domestic capacity publicly state that US Gulf Coast ethane export potential is quote high risk.

I guess they're calling into question whether or not the facility is going to get built on schedule, and they're talking about the scale possibly not impacting global supply, their feedstock costs, but I think there's also some concern maybe that the market might not be as loose as what you have indicated. I understand that they're concerned about their feedstock rising, so effectively they're talking their book, but I would like your thoughts in that regard.

I'm not going to accuse anyone of talking their book. First of all, I think you know as well as anyone, Darren, that we have a high regard for the US petrochemical industry. And been very supportive of their expansions and been supportive to the extent that we're willing to put money in things like the Aegis pipeline system and the ATEX pipeline system.

Frankly, producers need markets. I know that a lot of people haven't got the same robust forecast as we do, but invariably, when we sit down with a petrochemical company or with a producing company, by the time we're through, they have a full understanding of what we're looking at, and they start having a little more sympathy for it, and become a bigger believer.

We also say that when we talk about what we believe our forecast to be, we talk about potential supply, and that potential supply says that it has a market and it has a margin. If I look at our Arb sheet from this morning, there's not a single plant that I see across the country that ethane isn't underwater as much as $0.13 a gallon, on a market-based T&F basis, and still underwater on a variable basis for someone like Enterprise, or someone that has demand fees.

So in a nutshell, we believe there's plenty of ethane. We don't think that this is going to change things dramatically. We believe producers need markets.

If you think about it, ethane used to sell at 40% of crude. It is selling at 12.5% of crude. Propane traditionally sold at 65% to 75% of crude. We are now exporting a lot of propane, yet it's selling at 45% of crude.

I think exports are a good bridge. Frankly, I would rather everything this country exported be solid rather than liquid, but that's not reality today.

One more thing, Darren. You can't have ethane selling at below natural gas and expect people to put ethane extraction capability in.

So I'm going to look at Leonard. If a $300 million a day plant costs, call it, $175 million, what is the ethane extraction part of that capital? $65 million, $70 million? So am I going to spend $65 million to 70 million to extract a product that I'm losing money on, or am I just going to do C3+, where, frankly, those processing margins are better than what Bill Ordemann and I used to look at for the total?

Well, Jim, I agree with you. I think to a large degree, you're preaching to the choir. If you look at just the economics around C3+ on a composite barrel basis you are going to have a tremendous amount of C2 supplies and associated product.

I guess what we worry about or what we think about over the next five to six to seven years is the practicality of maybe that Arb closing, and a lot of the incremental upfront retrofit costs for a lot of those European crackers. And that's difficult to pinpoint. That bridges me to my second question, maybe for Tony. If you just think about the Gulf Coast to Northwest Europe ethane arbitrage opportunity and you look at your ethane supply growth assumptions, and the ability of that export capacity to ramp, how much Northwest European ethylene naphtha feedstock capacity do you ultimately think can be displaced by Gulf Coast exported ethane?

Darren, I don't know the answer to that question. Every plant is different. Obviously, it is going to be plants that have access to water, and either being on the water or have a pipeline to bring feedstock to them. But there's not generic general answer to your question.

Let me take a shot, Darren. Everybody's got their cracker model. None of them are right because, like Tony said, every cracker has its own unique characteristics, but we all have a generic model.

On our generic model, it says basically you produce, your cash cost producing ethylene from ethane is $0.13 a pound. Cash cost from naphtha is $0.48 a pound, so you've got $0.35 a pound difference. Let's assume you only realized $0.10 a pound on that versus naphtha after break, and all of that stuff.

That's $150 million a year on 1.5 billion pound a year cracker. If you want a 20% return, Randy, you could spend $750 million.

You can't have -- it's like we talked about, or Mike mentioned, $20 spreads LLS to WTI first quarter of last year. We knew that wasn't going to last. We knew it wasn't sustainable. Wide spreads are not sustainable.

Darren, this is Mike. The comment that ethane exports were high risk, I listened to that, and I listened to it about three times. What I took away from there was that he was saying that it was high risk for them, that particular petrochemical company, because of where their plants were geographically located, and their downstream plants, not that it was a high risk of proposition for Enterprise.

Oh, no, I agree with you, Mike, and I appreciate the clarification. I was thinking more about the risk to impacting their ethylene margins, or their ability to source feed that's more competitive for them. I fully agree.

Last question for you Jim, and I hope this is a little bit easier one, but I'm just thinking about the math, and not to put you on the spot, so I'll give you our math. If we think about the scale or scope of the project for ethane export that you have announced, and let's just say we assume it's roughly a $1 billion cost and we also assume that you have got about two-thirds of the capacity committed. Would it be fair for us to assume a low double-digit unlevered rate of return, just based on what you have committed?

Boy, you are good, Darren. I've got to give you credit. I'm going to tell you, we've got enough contracts that if we don't sign another barrel up, we've got a nice project, and it is not low single-digit returns.

I appreciate it, Jim, and just so you know, that's state school math for you.

By the way, one other question you talked about is some comments whether we could build it in the time frame that we were -- that we advertised. Those guys forget, we've got a Leonard Mallett and a Richard Hutchison over here. We've gotten pretty good at building stuff on time and under budget.

Thank you, Jim.

Your next question comes from the line of Brian Zarahn from Barclays. Your line is open.

Good morning.

Good morning.

I will shock you and ask a couple more ethane export questions. So it looks like $1 billion dollars is reasonable on your costs, given you have increased your project inventory by that amount. How should we think about contracted capacity, contract length?

Before somebody answers that question, the increase in our capital expenditures is a number of things. It's not just this project. So I wouldn't necessarily assume this is $1 billion project.

Is that more of a --

I'm not going to tell you.

We'll use round numbers for now. But I guess maybe a little more additional color on contracts and how you -- length?

I think we could say it's 10 plus years.

Okay. What's your expectation for your additional discussions with customers for additional contracted capacity?

Let me expand on it a little bit. To me, this is like a pipeline. This isn't going to be, in my mind, like an LPG, where you have a spot market trade.

These ships are being built specific to a need. I think -- so you are not going to see a spot trade, I don't think, anytime soon, if ever, on ethane. But, yes, we have a lot of interest. We're talking to a lot of folks. And I fully expect with Al Martinez involved, we'll sign more contracts.

In terms of geography, how are markets outside of Europe looking?

Panama Canal doesn't hurt. We're talking to people all over.

How do you expect pricing to be for the ethane, to be more naphtha related, or Belvieu ethane, plus?

The beauty of the US NGL market is there's a pricing point that you can buy all the ethane you want at, and it's a pretty dynamic market, and we're not going to do naphtha-related contracts.

Last one from me, what type of opportunities longer-term do you see for your marketing business, with the export terminal?

The ethane, the LPG?

Ethane.

What I think we're going to end up doing is doing our best to contract it out to long-term contracts.

Would you keep some of that for, similar to your LPG side? Would you keep some of that for your marketing business?

Absolutely not.

Okay. Thanks, Jim.

Your next question comes from the line of Ross Payne from Wells Fargo. Your line is open.

How you doing guys. Two quick questions for you. Sticking with the ethane just for a second, can you talk about where the ship development is, how many ships you're seeing, what the timeline might look like on that? And second of all, for Mike, you might have touched on this, but if you can talk about the utilization on Foothills and Texas Express? Thanks.

Sure. Al, why don't you tell him where the ships are being built?

Thank you. I think it's not specific to one of the major ship building facilities, but I think ships are being built in the Korean shipyard, I believe the Japanese shipyards, and also possibly also in China. Those are the three major locations where the ships of this nature, the gas carriers, the VOGCs, and we'll call it the ethane gas -- the ethane carrier, we will be built very similar.

Do you know how many ships or what the timeline is in terms of delivery might be?

We don't know how many. You can give him a timeline.

I'll say that they're basically all of our discussions are, they're in concert with our contracts.

Okay.

In other words, they'll have the ships when the facility comes up, Darren -- or Ross.

And refresh my memory. The timeline on that for completion on your side?

Leonard?

Third quarter '16.

No kidding? Third quarter of 2016.

Great. Then on the utilization of Foothills and Texas Express? To give us an idea how much ramp-up we probably are going to be seeing in the future?

Ross, you mean Front Range, right?

Front Range, I'm sorry.

Mike, do you have that?

Yes, of course they're being impacted by ethane rejection. When I talk about physical volumes, we're not talking about contractual, because we've got deficiencies on there.

70,000 barrels plus.

70,000 barrels a day?

Almost 80,000. Current.

For the quarter, Ross, Texas Express is more like 67,000 barrels a day.

But the contractual agreement is higher than that?

There's demand charges.

Okay, thanks. That's it for me.

Your next question comes from the line of John Edwards from Credit Suisse. Your line is open.

Good morning everybody. Randy, when you were running down the financing activity, I didn't hear you mention issuing any equity during the quarter. Was none issued?

John, the only equity that we issued was through the dividend -- or distribution reinvestment plan, so there was not a follow-on equity offering to the public, overnight deal, nor was there any activity under the ATM facility.

Okay. And then just -- I guess one more question on the ethane export. I mean, at this point, what kind of volumes are you anticipating on that?

At what the capacity is, John.

John, we haven't announced anything with respect to the contracted volumes. As we've mentioned, we're still talking to a lot of other people, but we're confident in the project with the contracts that we have in place today.

Okay. Fair enough. That's all I had. Thank you.

(Operator Instructions)

Your next question comes from the line of Michael Blum from Wells Fargo. Your line is open.

Thank you. Just one more question on the ethane thing, and I apologize. So just to be clear, the ultimate contracts for supply will be between US producers and foreign petrochemical companies, and you, as Enterprise, will just effectively clip a coupon to move it through your dock?

We might be the seller, but it is going to be on an OPIS-related price, Michael. Effectively you're right, we're going to be collecting a fee.

But would it be your marketing arm that would be selling the products?

Yes.

Okay.

But not in every -- we're not taking price risk on that at all. It's strictly a pass through. We're basically accommodating their need, but our contract customers have rights to buy their own, I think, Al.

Correct.

So either way.

We're offering a service to aggregate product for them, if they buy it or sell it to them, delivered to the dock.

Got it. Okay. And then just a couple of questions on ATEX. So just based on what you said, running about 30,000 barrels a day in the first quarter, would you expect, based on everything you were saying, the reasons for why that wasn't at the 68,000, that's going to now ramp up to the 68,000 as those fracs come on, et cetera?

We've got two plants that are connected to ATEX, and we're waiting on two more to connect, scheduled either later this month or early in June. So I think as those additional two plants get connected to our system, we will see the volumes ramp up.

Okay. And then last question on ATEX. Have you any other -- any additional discussions with Northeast producers for propane service on that line, just given all the moving pieces up in the northeast?

We're always talking to them about opportunities, but nothing specific.

Okay. Thanks guys.

There are no further questions at this time.

Okay, Kyle. If you don't mind, Kyle, would you give our listeners the replay information?

Yes, sir. A replay of today's conference will be available beginning later today.

To access the replay, please dial 855-859-2056, or if dialing internationally, 404-537-3406. To access the call please enter your conference ID number 31363407.

Thank you. This concludes today's conference call. You may now disconnect.

Thank you Kyle and you guys have a good day.