Enterprise Products Partners LP (EPD) 2013 Q4 法說會逐字稿

Good morning. My name is Brent and I'll be your conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners fourth-quarter 2013 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions). Thank you. I would now like to turn the call over to Mr. Randy Burkhalter. Please go ahead, sir.

Thank you, Brent. Good morning, everyone and welcome to the Enterprise Products Partners fourth-quarter 2013 earnings conference call. Our speakers today will be Mike Creel, CEO of Enterprise's general partner, followed by Jim Teague, Chief Operating Officer and then Randy Fowler, our Executive Vice President and CFO. 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 release 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. 2013 was a record-setting year for Enterprise, both financially and operationally and it ended with a strong fourth quarter. Our record financial performance in 2013 included records for net income of $2.6 billion, earnings per unit of $2.82 on a fully diluted basis and gross operating margin of $4.8 billion with four of our five business segments reporting improved results. We benefitted from record volumes in our fee-based businesses attributable to production growth and strong domestic and international demand for NGLs. In 2013, we transported a record 5 million barrels per day of NGLs, crude oil, refined products and petrochemicals while our gas processing plants handled a record 4.6 billion cubic feet a day of natural gas on a fee basis and our NGL fractionators averaged a record 726,000 barrels per day.

We generated $3.8 billion of distributable cash flow and increased our cash distributions by 6.5% to $2.74 per unit with respect to 2013 while at the same time retaining $1.3 billion of distributable cash flow to reinvest in the partnership. We ended the year with strong fourth-quarter results that produced record gross operating margin of $1.3 billion with increases from our NGL pipelines and services, onshore crude oil pipelines and services and petrochemical and refined product services segments. For the second consecutive quarter, we had record NGL and crude oil transportation volumes, record NGL fractionation volumes and record LPG export volumes.

Distributable cash flow increased 15% to $1.02 billion in the fourth quarter of 2013 from $886 million in the fourth quarter of last year, providing 1.6 times coverage of the cash distribution declared with respect to the fourth quarter of 2013. Included in distributable cash flow were proceeds from asset sales and insurance recoveries of $24 million this quarter and $31 million in the fourth quarter of 2012.

Earlier this month, we declared a $0.70 per unit cash distribution with respect to the fourth quarter of 2013 and that is a 6.1% increase over the distribution paid with respect to the fourth quarter of the prior year. This distribution will be paid on Friday, February 7 to unitholders of record on the close of business tomorrow. And it represents the 38th consecutive quarterly increase in our cash distributions. This means we have had distribution increases every quarter for the last 9.5 years. We retained $382 million of distributable cash flow this quarter. Retained DCF is available to us to reinvest in the growth of the partnership and reduce our reliance on the capital markets. We intend to reinvest these proceeds and projects with higher returns on capital to increase the EBITDA and future distributable cash flow.

The NGL pipelines and services segment reported record gross operating margin of $737 million for the fourth quarter of 2013, which was 17% higher than the $632 million in the fourth quarter of 2012. Gross operating margin from our natural gas processing and related NGL marketing business increased by $9 million primarily due to higher NGL marketing sales margins, which more than offset lower processing margins in 2013.

Fee-based natural gas processing volumes and equity NGL production from our processing plants in South Texas increased by 200 million cubic feet per day and 26,000 barrels per day respectively in the fourth quarter of 2013 compared to the fourth quarter of the prior year. This was primarily due to the addition of the third train at our Yoakum plant in March of 2013.

Gross operating margins for our NGL pipelines and storage business increased $29 million or 13% to $249 million this quarter. Our LPG export facility and related Channel pipeline reported a $16 million increase in gross operating margin on 273,000 barrels per day increase in propane and butane volumes. Our South Texas NGL pipeline system contributed $7 million of this increase, primarily due to a 122,000 barrel per day increase in transportation volumes from increased Eagle Ford shale production. NGL pipeline transportation volumes were a record 2.9 million barrels per day this quarter, slightly higher than the record set last quarter. Our NGL fractionation business recorded record gross operating margins of $150 million for the quarter compared to $82 million reported for the same quarter in 2012.

Our NGL fractionators at Mont Belvieu generated $56 million of this increase, primarily due to a volume increase of 113,000 barrels per day. We had a new NGL fractionator begin service at the Mont Belvieu complex in October of 2012 and two more NGL fractionators started up in September and November of 2013.

Gross operating margin from the onshore natural gas pipelines and services segment decreased to $187 million this quarter from $210 million for the fourth quarter of the prior year. And that is primarily due to lower marketing sales margins and lower transportation volumes on most of our transportation and gathering pipelines. These pipeline systems include the San Juan, Jonah, Piceance and Haynesville gathering pipelines, which were impacted by reduced drilling activity and production declines in the regions they serve. These decreases in gross operating margin were partially offset by a $9 million increase in firm capacity fee revenues on our Texas Intrastate system due to strong demand for our services from producers in the Eagle Ford shale.

Our onshore crude oil pipelines and services segment reported gross operating margin of $163 million this quarter compared to $135 million for the fourth quarter of 2012. This 21% increase was primarily due to higher pipeline volumes from our South Texas and West Texas pipeline systems and our Eagle Ford and Seaway joint venture pipelines, as well as improved results from crude oil storage. Total onshore crude oil pipeline volumes were a record 1.3 billion barrels per day this quarter, up 42% from the fourth quarter of 2012. Partially offsetting the improved results from our pipeline and storage facilities was a $52 million decrease in gross operating margin from our crude oil marketing and related trucking activities due to decreased margins as a result of lower regional price differences for crude oil.

For example, in the fourth quarter of 2012, the total average spread we made on spot transactions buying Mid-Continent crude, transporting it on Seaway and selling it in the Houston market was over $16 a barrel. And of that, our marketing group earned a little over $13 a barrel after transportation costs. Compare that with the fourth quarter of 2013 when we earned a total average spread on those same types of transactions of just under $3 a barrel and our marketing group lost about $1 a barrel after transportation costs.

Gross operating margin from our offshore pipelines and services segment was $28 million this quarter compared to $42 million for the fourth quarter of 2012. This decrease was primarily due to lower volumes on the Independence Trail pipeline and Hub platform, as well as the Shenzi and Constitution oil pipelines, which were negatively affected by production declines in downtimes during the fourth quarter of 2013 related to Tropical Storm Karen. Gross operating margins from the Cameron Highway Oil Pipeline was up quarter-to-quarter due to the increased volumes from the restart of the Caesar pipeline in the second quarter of 2013.

Our petrochemical and refined products and services segment reported gross operating margins of $175 million for the quarter compared to $143 million in the fourth quarter of the prior year. This 23% improvement in gross operating margin was primarily due to higher sales margins, volumes and fees from our Mont Belvieu propylene fractionation plants, which increased by $11 million and a $19 million increase in gross operating margin from our octane enhancement facility. This facility had more operating days during the fourth quarter of 2013 due to a plant turnaround that began in December of 2012. This segment also benefitted from higher throughput volumes at refined product terminals in Port Arthur and higher sales margins and volumes from our refined products marketing business.

In closing, we are very pleased with the results this year. We generated a 38% total return to our unitholders in 2013 assuming a reinvestment of distributions. Our large integrated footprint of assets continues to generate increased distributable cash flow and provides opportunities for growth and expansion.

During 2013, we completed and put into service $2.3 billion of major capital projects. We completed all of these projects except for two on time and 1% under budget. And we are off to a fast start in 2014 as we have already completed and put into service $2.1 billion of projects this month. The largest of these was our ATEX pipeline, which began commercial operations a month ahead of schedule. Execution and timeliness is critical in completing our organic growth projects. As I said last quarter, we are pleased with the efforts of our engineering and commercial groups in assuring the successful execution of these projects.

We are excited about the future and confident in our team of dedicated employees and their ability to find and execute on new opportunities to add value to our partnership. We want to thank our debt and equity investors for their continued support again in 2013 as we look forward to 2014. And with that, I will turn the call over to Jim.

Thank you, Mike. I want to start out by recognizing members of our senior management team who will soon be leaving Enterprise to make sure we publicly thank them for their service. As many of you know, Lynn Bourdon has accepted the position of CEO at a new midstream company, Enable. Lynn has been with Enterprise for over 10 years where he has led a significant portion of our marketing activities, including NGLs, petrochemicals, refined products and natural gas. He has done a great job for us and we wish him the best as he moves on to Enable and quite frankly, we are complemented by the fact that somebody wants one of our own to run their company. Lynn and I worked together at Dow for many years, so we are close friends. Enterprise will miss him, but I will personally also miss him. The bright side is that when he is successful at Enable, we don't have any other volume in our fractionators and we expect to see Enable volumes at Mont Belvieu.

Terry Hurlburt has also announced that he will be retiring at the end of February. Terry has been with Enterprise for 33 years. Terry leads our operations, safety, environmental and training groups. He is a pro at everything he touches. He is passionate about technology, safety and he is very passionate about Enterprise. We can't thank him enough for all that he has done.

Wanted to mention that Tom Zulim, who headed our regulated group, is on extended medical leave. We keep in touch with Tom and wish him the best as he works through his health issues that he has been dealing with since last summer.

And then, finally, I wanted to mention that Rudy Nix, who is somewhat of an icon here at Enterprise and leads our distribution team, has informed me of his intention to retire within a year.

Collectively, these guys have devoted almost 100 years of service to Enterprise and made significant contributions to our Company's growth and our profitability. While we will miss their knowledge, their expertise and their friendship, these changes create opportunities for others who have been key contributors to our success. One of our Company's recognized strengths is the bench we have with qualified individuals ready and able to step into new roles and take on new challenges in large part due to the efforts of the guys that are leaving us. This enables us to seamlessly continue the success Enterprise has enjoyed. We have announced several promotions to fill these slots and you'll be seeing much more of these folks in the days and months ahead. They are knowledgeable, highly motivated and well-respected, not just here at Enterprise, but in the industry.

I also want to speak to recent market events, more specifically related to the tightness in propane supplies in the Midwest and Northeast. The propane tightness, especially in the Midwest, is something that the industry is trying to correct using the tools it has available. We are dealing with a combination of events, including the obvious like a very large and very late crop drying season in the Midwest and extremely cold weather, especially in the upper Midwest and parts of the Northeast. Some forecasters are saying to expect this winter to be one of the coldest in the last 20 years.

In addition, there are a number of other events, including processing plant outages in the Northeast and a major pipeline outage in the Midwest that impacted regional supplies. It is important to note that the upper Midwest has no pipeline access to Gulf Coast supplies. Instead relying on slower and less efficient rail and truck movements. Peaking requirements are handled by local retailer inventories, which are now very low. When you're planning for the future, you have to look at the past and the recent several years would not have told propane retailers to stock up for near record crop drying and weather at the obvious risk of extreme price exposure and what has been a generally falling market.

I can't say their planning was anything other than prudent, but that doesn't make this event easy for the industry to fix. The entire industry is doing everything it can to get incremental propane where it is needed, but pipeline access is problematic in the Midwest. Our TE Products pipeline system is configured so that not only can we deliver supplies from the Gulf Coast to the Northeast, but we can also receive local Utica and Marcellus supplies and make those available. Our shippers determine whether they ship propane, butanes or refined products. A price response has been needed in order to get them to change their shipping plans and several of our shippers have chosen to minimize shipments of other products in favor of shipping more propane. That same price response is happening relative to imports where, as I understand it, ships are bringing incremental propane supplies to the Northeast. We continue to do all that is possible on our end to respond to needs. In the final analysis, price ultimately solves the problem.

Moving on to earnings, as Mike said, we are pleased with our quarter and frankly with the results. Realizing it's never enough, there are always areas that fall short of our expectations where we will do better in 2014. The beauty of Enterprise is that there are always businesses that outperform. We also have a growing platform of new assets that we are putting into service. We benefit from diversity, both geographic and product, which gives us options to make money under almost any market condition. Finding value under different market conditions across all our assets is how our people think day in and day out. While a growing base of fixed fee assets across multiple commodities makes for a stable group of businesses, we are a company whose culture is geared to find the upside. We are never comfortable, we are driven to find and deliver on value across our assets. We were successful in doing that in 2013, we are expecting to do it in 2014.

In the Eagle Ford, our buildout is all but complete. The Eagle Ford continues to exceed our expectations and our assets are running at high utilization rates. Relative to NGL pipelines, we have recently put our Mid-America Rocky Mountain expansion and Texas Express pipelines into service and we've started to linefill our Front Range project. Mike said we put our ATEX pipeline into service January 1 and work is going as planned on our Aegis pipeline header where segment one to Lake Charles is expected to be in service by the end of the year.

In addition, we completed our work to be able to deliver C5 plus volumes into the Southern Lights pipeline in the Midwest and by July into Cochin. This is needed by the Canadian Oil Sands as a diluent. Over the last two years, Leonard Mallett and his team have had one of the largest pipeline buildouts ever. And we appreciate their accomplishments from both a timeline and cost perspective, especially in an environment that is tight on crews and materials.

In crude, as you know, we finished the Seaway reversal in early 2013 and we are close to completion of looping Seaway. We also completed the lateral from Jones Creek to ECHO. Activities at ECHO include the tank buildout, the 95-mile lateral to Beaumont/Port Arthur and the header we are building along the Houston Ship Channel. These crude oil assets are strategic both to the supply and demand sectors of the industry and we are making a great foundation for additional crude expansions at Enterprise. When we are through, we will have direct connectivity from ECHO to every refinery in Houston, Texas City, Beaumont and Port Arthur and water access across six docks in three locations.

Work also continues on our Beaumont refined product export dock, which should be up and running in stages during the second quarter and third quarter of this year. At Mont Belvieu, we put our eighth fractionation train into service in November. With many of our new units exceeding their design capacity, we now have almost 700,000 barrels a day of fractionation at Mont Belvieu and approximately 1.2 million barrels a day systemwide.

Our PDH plant is progressing. We are still looking at late 2015. And our dock expansions, and I note that is plural, are in construction. Last year, we announced a dock expansion moving our capacity from about 7.5 million barrels a month to 9 million barrels a month of LPG. Right after the first of the year, we announced that we completed a 50-year agreement with Oiltanking, which enables us to increase our loading capacity to an instantaneous 27,000 barrels an hour. We expect about 16 million barrels a month. We looked long and hard at other alternatives and in the final analysis are delighted that we are going to be able to expand on our 33-year relationship with Oiltanking. This keeps us closely aligned with facilities that are a great fit for our infrastructure and they provide great service to us and our customers. We are continuing to pursue ethane export opportunities. We are in negotiations with several companies as global petrochemicals now understand the US NGL shale resources and are making plans to participate.

In closing, 2013 was a great year thanks to our people. We are confident that those same people will deliver in 2014. And with that, I will turn it over to Randy.

Thank you, Jim. I'd like to take a few minutes to discuss additional income items for the quarter, as well as capitalization. We reported net income attributable to limited partners of $699 million and earnings per unit of $0.75 per unit on a fully diluted basis for the fourth quarter of 2013. Net income and EPU were reduced by $44 million or $0.05 per unit on a fully diluted basis for non-cash asset impairment charges. $39 million of this $44 million was on the face of the income statement while $5 million was included in equity earnings from unconsolidated affiliates.

You may have noticed a new item in our reconcilement between operating income and gross operating margin on exhibit D of our earnings release. In the fourth quarter of 2013, certain shippers on Texas Express and Seaway did not utilize their minimum volume commitments. Although we received payments of nonrefundable fees totaling $4.4 million for capacity charges, due to certain contractual makeup rights related to the shortfall in volume, the revenues associated with the shortfall in minimum volumes cannot be recognized as revenues in operating income and net income for generally accepted accounting principles until the earlier of the deficiency volumes being shipped, the expiration of the makeup period or the pipeline being released from its performance obligation.

We consider the transportation fees earned by these pipelines important in assessing their financial performance and therefore, we include the nonrefundable deferred revenues associated with the makeup rights in our non-GAAP financial measures of gross operating margin and distributable cash flow. The nonrefundable deferred revenues we include in our non-GAAP measures are reconciling items and just a timing difference, if you would, in comparing to their corresponding GAAP measures.

In 2014, we expect several of our new pipeline projects may experience months where customers are unable to utilize their contractual minimum volume commitments, including the ATEX and Front Range pipelines in addition to Texas Express and Seaway potentially due to the effects of timing of new well startups in the Marcellus and Utica shales and ethane rejection in the supply basins served by ATEX, Texas Express and Front Range pipelines. As a result, we expect to have this reconciling timing difference between our GAAP and non-GAAP financial measures in 2014 as well.

And turning to capital spending, we had capital spending of $1.3 billion this quarter, including $1.2 billion spent on growth capital projects, bringing total growth capital spending to $4.2 billion for the year 2013. Sustaining capital expenditures were $78 million in the fourth quarter of 2013 and $292 million for the full year. There were certain discretionary maintenance projects that slipped into 2014. We are still working through the 2014 budget process, but we currently expect total capital expenditures to be between $3.9 billion and $4.4 billion during 2014 and this includes approximately $350 million for sustaining capital expenditures.

Adjusted EBITDA for the 12 months ended December 31, 2013 was $4.7 billion. Our consolidated leverage ratio of debt principal to adjusted EBITDA was 3.5 times for the year 2013. And this is after we adjust the hybrid debt securities that we have for 50% equity treatment. We received net proceeds of approximately $553 million for the equity that we issued through an overnight offering in the fourth quarter of 2013. When combined with the at-the-market equity issuance program, our distribution reinvestment plan and employee purchase plan, we received total net proceeds of $657 million here in the fourth quarter of 2013. This also includes $25 million of common units that affiliates of privately held EPCO purchased through the partnership's distribution reinvestment plan this quarter bringing their total purchases of Enterprise common units during 2013 to $100 million. These affiliates have expressed their willingness to invest up to $100 million to purchase additional common units through the distribution reinvestment plan again in 2014. The first purchase is expected to be $25 million for the distribution to be paid on February 7.

And looking at our debt portfolio, the average life of our debt outstanding, term debt outstanding is 13.3 years. This is using the First Call date for the hybrid securities and our effective average cost of debt was 5.3% at December 31, 2013. At year-end, we had consolidated liquidity of approximately $4.1 billion, which includes availability under our credit facilities, as well as unrestricted cash.

Before taking questions, I would like to mention that K-1s will be mailed between February 18 and February 24 and will be available online by noon on February 17. With that, Randy, we are ready for questions.

Okay, Brent, we are ready to take questions from our listeners.

(Operator Instructions). Stephen Maresca, Morgan Stanley.

Hey, good morning, guys. Nice quarter and thanks for taking my question. Jim, you mentioned in negotiation with several companies on the ethane export front. I was wondering if you could just talk what is the view from these customers in terms of their willingness to spend the necessary dollars to convert assets to use ethane, how soon we could see something happen and are there vessels available to handle this?

Steve, if you look at the spread between ethane and naphtha, they have got a lot of room to spend money. They all seem to be willing to do so. I mean the final analysis we will see if we get a deal done. I think the biggest hurdle they have had to overcome so far is they are so used to dealing with just naphtha that they look at everything relative to naphtha and really wanted to price it like that and frankly, that doesn't work for us. So I think they have finally come around -- I am looking at Bill and Lynn -- they have finally come around to saying they understand -- they've educated themselves, we've helped to educate them as to what the opportunities are in the US. They have come around to recognizing they are going to have to price it relative to our market and they seem comfortable. Saying all that, we haven't signed any deals yet.

Okay. And then on the propane side, can you talk just a little bit about the export dynamic? Have you seen at all any slowdown in terms of customer discussions or demand for propane or butane given the shift in pricing?

Not at all. We've still got people wanting to talk to us. Term contracts, three to five years in term. I mean we've still got a lot of folks that we are in negotiations with on LPG exports and I don't think we have seen a slowdown.

Jim, that is correct. We have customers looking every day calling -- received calls this morning looking for additional term business in 2014, 2015. We are discussing everything from one-year contracts to five-year contracts with multiple customers.

I think those folks recognize that this is a seasonal issue.

Okay. And then, finally, from me, just on the financial side, maybe for Mike or Randy, latest thoughts on distribution policy. Obviously your coverage is extremely robust and you do have an ability to accelerate your payout beyond the year-on-year growth you have been accumulated. Are you considering doing that given the strong business performance and outlook?

Steve, we aren't at this point and we do discuss it from time to time, but as Randy pointed out, we've got somewhere in the range of $3.9 billion to $4.5 billion of CapEx for 2014. So we are still in a period where it is pretty robust. We have got our PDH plant that is a big project consuming a lot of capital, not generating cash flow yet. So we are going to be pretty cautious about how we go about increasing distributions. We have a long track record of doing it, but we want to do it in a way that is prudent and it makes the most sense for the balance sheet and for our unitholders.

Okay. Great. Appreciate the call, everybody.

Darren Horowitz, Raymond James.

Morning, guys. Jim, just two quick questions from me. The first, and this goes back to comments that you have made in the past. You've talked about shifting that processing contract mix to more fee-based and less equity barrels. Obviously, looking at the results the equity NGL barrels hit a record, and with that volatility that you just talked about across ethane and propane there's a pretty big disconnect between Conway and Mont Belvieu pricing.

So obviously that begs the question about arbitrage opportunity. And I know that said part of it is seasonal and I think we get that, but if you could just give us more color about the opportunity set that you see, maybe how long it could last and possibly even the magnitude of margin capture, that would be helpful.

I think we will probably talk about that on the first-quarter earnings call, won't we? We have done everything we can to move product to meet needs. In the Midwest, quite frankly, we've got a limited toolbox. We don't have pipelines to the Midwest. We do have our Hobbs fractionator. And we have diverted propane from -- I mean we could've brought it down to the Gulf Coast and put it on a ship. Instead we diverted it to the Midwest. But we have got trucks, I guess, moving as far as Minnesota the last time I saw out of Mont Belvieu.

But whatever we can do, we are doing, but our toolbox is limited in the Midwest. In the Northeast, we have got -- our TE products pipeline is going full out and serving those folks. You know, I will probably get slapped, but if you didn't have The Jones Act, you could've had this thing resolved pretty easily by moving product off the Gulf Coast in the Northeast and then displacing back to the Midwest. We don't have that in our toolbox.

Yes. Well, if that also happened I don't think your marketing guys would have the opportunity set that they have had historically and maybe going forward, too. So maybe those were the folks that might think about slapping you for saying that.

But shifting over to butane, just a quick question, and there has been a lot of discussion obviously about a possible shortage and all this focus on these light end cracker conversions and opportunities for possibly a rise in butadiene or butylene prices. And obviously, there's some export there from normal butane and you've talked about that catching up with propane. And I'm just wondering as you look out over the next couple of years, when does it make sense to start thinking about a butane dehydrogenation facility for on-purpose butadiene or butylene or possibly the export of those products; or is there just the ability to ramp more normal butane exports as a lot of those global arbitrage economics dictate?

I think we will export more normal butane. As far as on-purpose butadiene, we tried; we didn't get any traction. There for a while we thought we were, but in the final analysis the user of butadiene has got to step up and take a position like the propylene users did. And so far they haven't shown any interest in doing that.

Do you think that we are pretty close to pricing pressure to where they do? I mean doesn't what is happening in the butane market kind of feel like what was happening in the propane market 18 months ago?

We're going to let Lynn answer that seeing how this is his last call.

You know, and if you go back again to what Jim said on the on-purpose butadiene side, there just hasn't been enough support from the market for that. They've been able to find supplies from other sources at economics they felt like were better than supporting an on-purpose butadiene side. On the butane supply side, which I think was the root of your question, we don't see it exactly the same thing as the propane side because the propane side was a lot longer in supply on a relative basis than we received with the butane side. There's a few more alternatives for the butane, everything from gasoline blending. We still see a fair amount of butane going into the cracker, which is producing butylenes, butadienes on that side. But we do see increasing normal butane exports.

Our own facility, we have been exporting more normal versus what we had previously. And we have always been capable of exporting normal butane, but when you consume 100,000 barrels a day or so in your own system, you tend to take care of your own needs first rather than other facilities, which didn't have those same outlets and they were forced to find another home for the normal butane. And that's why you saw other facilities exporting more normal versus propane relative to what Enterprise has done. But our exports of normal butane are growing and we have a fair amount of demand from offshore customers who are looking for it. And our system is set up as we go forward, we will see more of that.

Thank you.

Matthew Phillips, Clarkson.

Thanks. Good morning, everybody. A follow-up on the propane LPG export. I mean is there any near-term room for lifters not to take cargoes? I mean I know it is term business mostly, but is there an inflation clause built in if it doesn't work or does the price get passed straight along through to the lifter?

Yes, I think we had one cargo -- one or two cargoes where they opted to -- in February -- is it February?

Yes, February.

-- that they opted to pay the deficiency and not lift, which is fine with us. There were a couple of spot cargoes that frankly we could have sold that we opted not to because the opportunity domestically was better. It is just a reflection of that -- price does create -- does change things.

Okay, that makes sense. And a follow-up on exports. There has been a lot of discussion in the media and the industry overall of crude exports here in the US. Is that something you view as realistic or at least in volumes enough to really matter to players such as yourself?

Did he say crude exports? I can't hear you, Matthew.

Sorry. Yes, crude exports. Yes, sir.

We are loading out ships that are obviously going to the East Coast and up into Canada of crude right now. I think we are going to do 2 million, 2.5 million barrels this next month. So we think water access is important and we know that the topic of exporting crude is a pretty hot topic right now. And personally, I think you're going to have to do something with all the light crude coming online to accommodate that. Exports create markets that enhance production and I think what we have seen -- I'm not sure you would had the kind of NGL production growth that we have seen in the US if those producers didn't have a -- be comfortable that there was a market for their product. It is one heck of a bridge and it enhances the production. So we are pretty supportive of it.

If it enhances production to export it, if we continue the restriction of exports, does that imply that we will hit a wall in production at some point due to pricing?

It implies you'll have a price delta.

Yes, Okay, thank you.

T.J. Schultz, RBC Capital Markets.

Hey, guys. Good morning. Just a general question first on the ethane market. We have been drawling about a million barrels per month from inventory. Just looking for your thoughts on the market currently and into spring and summer if you think we could accelerate withdrawals to get markets more in balance, maybe before some of the crackers go down.

I don't think -- I think there is plenty of ethane. We are not putting large ethane margins to natural gas in our budget.

Okay. On ethane exports, the facility you indicated potentially in Beaumont or the ship channel, if you could just discuss what would push it to Beaumont or if it is an option to export ethane from your current footprint at Oiltanking?

I think what would push it to Beaumont right now is just dock availability. We have done quite a bit with Oiltanking already, but have a lot of LPG needs there. We have docks available at Beaumont and likely that would make us lean in the Beaumont direction.

Okay, thanks. Lastly, the spread impact on Seaway, can you say again what the marketing losses were here given the spreads during the quarter and what your expectations are for spreads in 2014 or specifically for your marketing efforts next year or this year?

Yes, T.J., I threw out some numbers for marketing related to spot transactions and the numbers that go with it. They made about $7.5 million in the fourth quarter of 2012 and lost about a little under $2 million in the fourth quarter of 2013. It is pretty simple to understand that once we put Seaway into service that the basis differential between Cushing and the Gulf Coast narrowed substantially. We really don't see much to change that, particularly with the new TransCanada line that has gone into service. So we are opportunistic. We are looking at Seaway as an asset that we are earning steady fee-based revenues on. And just like any other asset we have, if there's an opportunity to take advantage of price differentials, we will do it; if they're not there then we won't.

This is Jim. It's not just -- you have got Seaway, you've got TransCanada's pipe, but you've got a lot of pipe coming into the Houston area from West Texas. What we are doing is -- we talked about it in our comments -- what we think helps differentiate Seaway from others from a long haul long term is the distribution system we are building in the Houston, Beaumont, Texas City, Port Arthur area. But it is only natural. You get pipeline capacity, basis narrows. This happens everywhere.

Great. Thanks, guys.

John Edwards, Credit Suisse.

Yes, good morning, everybody. Thanks for taking my questions. Just what was the volumes on Seaway this quarter? And then just if you could comment on the expected Seaway rampup as you put the expansion into service?

In the fourth quarter, the volumes on Seaway were probably just shy of 300,000 barrels a day, if I recall correctly. I don't have the number in front of me, but probably somewhere just shy of 300,000 barrels a day. We've now completed and put into service and I believe made the first deliveries on the Jones Creek to ECHO lateral that will take all those Seaway volumes into ECHO. The loop project is scheduled to be complete probably late second quarter is what we are thinking today. And as far as volumes on the loop project and when it will come up will certainly depend on our partner Enbridge's timing on the Flanagan South piece, which we understand won't be long after that. And then also our extension of the Seaway project over into the Beaumont/Port Arthur area is scheduled to probably be again late second quarter, early third quarter. And as those pieces come into play, I think we will see Seaway ramp up, we will see what the appetite is. I think our capacity at that point in time will be between 850,000 and 950,000 barrels a day and we will see who's going to ship.

Okay, great. That is real helpful. And then just with ATEX being placed into service January 1, just what kind of volume ramp are you seeing on that so far?

Again, John, we have got one connection in service right now receiving volumes. We are expecting our second one by the end of the first week in February and a third connection by the end of February. We are flowing about 20,000 barrels today, but we have seen that as high as 40,000.

Okay, great. Thank you very much. That's all I had.

Ted Durbin, Goldman Sachs.

Thanks. Actually I want to pick up on something that was in the press release here. You mentioned that you are interested in growth at a reasonable price, but not growth at any price. I guess I am wondering how we should read that. Is that a commentary that maybe you're not seeing projects that are reaching the return threshold that you're looking for? Does that imply that maybe the capital budget comes down or is this more of a commentary around the industry? Maybe just a little bit more, just flesh that out a little bit more for us.

Yes, Ted, we are not going to throw rocks at the industry. I think it is more of a function that we have been asked a lot about the acquisition market, for example. Are we going to be acquisitive in 2014? And I think the intent of the statement was to say we are going to stick to our knitting; we have got plenty of organic growth projects that have good returns that add value to our downstream assets. We are not going to try to compete on price to acquire things just for the sake of getting big.

Another point that we have addressed in other forums is how much capital do we really need to spend on an annual basis to maintain our distribution growth and Randy has done quite a bit of work looking at this and in fact, in one of the presentations, more recent presentations out on our website, it has got the information and in the appendix, it has got the calculations, but it basically shows that in order for us to continue our distribution growth and depending on the assumptions of how we fund it, we need new assets of anywhere from call it $1.5 billion to $2 billion. And frankly with some of our assumptions using distributable cash flow, it could be a little south of $1 billion. So just the message that just because we are spending $4 billion a year and have for a number of years, we don't need to do that in order to maintain our distribution growth. We're doing it because we have high-quality projects that frankly if we don't do them now, they won't be available to us in the future.

Okay, that's really helpful. And then maybe can you just talk to, and I know it is somewhat of a short-term phenomenon, have you seen any pickup in any lean gas drilling in any areas? I'm thinking maybe the Haynesville or whatnot given the move in prices or is sort of just a head fake and we should just expect -- because you guys had some tough quarters here in the onshore gas pipeline business. I'm just wondering if you could talk to that dynamic.

Well, really, it's too soon to say that our price in lean gas area would pick up because of this recent uptick in natural gas prices. But as a general rule, I think what this has done, just like the price uptick in gas at the end of last winter, it has given producers a good solid base to hedge for 2014 and for 2015. But I'm not sure that's really going to change their drilling plans.

Got it. Okay, I will leave it at that. Thank you.

Shneur Gershuni, UBS.

Good morning, everyone. Many of my questions have been asked and answered. I just wanted to return to the -- I think it was the first question with respect to the ethane exports. I was wondering if you can sort of expand a little bit as to what the challenges are left for the customers to overcome at this point. Is there a need for a long-term contract on pricing or have they kind of been educated on that? Is it logistics or CapEx on their end that's sort of holding things in place at this stage? And also wondering if you've had any discussions in the US with utilities about using ethane and boilers as well too?

No, we haven't had discussions with US utilities. I think we are pretty well there with some folks. I think it really gets down to them just getting convinced and pulling the trigger. And we went down this same road with our PDH plant. At a certain point, a guy has just got to say I believe and he steps up and he does the deal. And I think we are getting to that point, Al, with a couple of folks.

I think the challenges are very similar to what any -- even if it were a domestic project. It has been evaluated, it has been presented against their options or their current situation. You're looking at their infrastructure and their costs and making that evaluation. And from our discussions, we feel that companies that we are talking to have spent -- it is not something that has just happened in the last few months. They have been looking at this; we have actually been talking about it for close to two years, very early on just in the discussion stages whether or not this project would fit, whether it's Northwest Europe petrochemicals or Asian markets. And I think we are getting close to closing or getting close to completing some of those agreements.

Okay, great. And one last follow-up question. Just with respect to the PDH facility, are we done with all the major permits that we need or is there anything else that needs to be approved and so forth?

We are not done with the permits. Our permits -- we are actively working with both the EPA and State of Texas. We expect to have our permits in the March/April timeframe.

Great. Thank you very much, guys.

Ross Payne, Wells Fargo.

Thanks. Mike and Jim, we have obviously had a nice uptick in NGL pricing and propane has obviously driven a lot of that. But as a general rule, do you guys think we might see some decent year-over-year comps for the rest of the year? And then secondarily, Bluegrass and Kinder's NGL pipes have been -- projects have been pushed back a bit. Can you speak just generally about what you are hearing from producers up in that area and what they are thinking in terms of getting their NGLs down into the Gulf? Thanks.

Ross, I will talk about the first part of that and let Jim talk about the y-grade pipeline projects on the drawing board, but with respect to the first quarter, we are not going to give guidance, but nice try. But as you can imagine, any time we see opportunities around our system regardless of the product, we're going to try to capitalize on it.

Ross, I don't know what is going to happen on y-grade -- are you speaking y-grade pipelines out of the Marcellus, Utica and frankly I don't know what is going to happen. I think they are both -- every consultant I speak to says one's -- at least one is needed, but somebody has got to step up and commit to it. And right now, a lot of guys frankly have stranded capacity, they've stepped up in the past and it is kind of a hurdle to say, yes, I want to step up to another one. If I have got stranded capacity, I am paying for it somewhere else. So I think it is a struggle. I think sooner or later somebody is going to build one. I don't think it is imminent though.

Based on our experience, we had the open season for propane on ATEX. That seems to be after ethane the item that has the biggest issue at least on a seasonal basis and really had no appetite there. So it may just be a function that, yes, at some point, it is going to be a problem, but we are just not there yet.

Okay. Thanks, guys, very much.

Michael Blum, Wells Fargo.

Thanks. Good morning, everybody. Just one quick question and I apologize if I missed this. On your LPG export docks, at least the consultants are reporting that you are running above nameplate capacity on that. Would you expect that to continue through 2014 until the next expansion comes on?

You mean we are able to load at a higher rate than we thought, is that what you're saying, Michael?

Yes, yes.

We have kind of gotten used to our engineering group. When we tell them to build something, invariably it does more than the nameplate. I don't know, what are we running, Terry? 13,000, 14,000 barrels an hour?

14,000.

And Michael, when you look at the numbers and what we said the hourly rate was going to be for our LPG terminals post the next expansion, and you do the numbers, if you were to hit that theoretical limit, it is 19.7 million barrels a month. And what we are saying is it is more like 16 million because there is operational issues and --.

Yes, you have got -- you've got positioning ships and such as that. But I think right now until the expansion, I think 13,000, 14,000 an hour we are pretty comfortable with.

Okay, great. Thanks, guys.

Chris Sighinolfi, Jefferies.

Hey, good morning, guys. Thanks for the color. A couple quick questions from me. With respect to Darren's question on the NGL equity volumes, we obviously did see them ramp higher in 4Q from sort of the run rate that we had been seeing prior in the year. I was just curious what is driving that. Is that -- is there an effort to sort of optimally run fracs 7 and 8 or is there something else going on there that you could speak to?

The equity volumes we are seeing the rampup in are really discretionary ethane volumes. In our gas processing plants, like a Yoakum, our producers have the right to elect ethane recovery or ethane rejection. Obviously, in today's market, most of those producers are rejecting ethane. We have the opportunity to come in there and take that ethane and when we look at it, we will look at it on a variable cost basis since we own the plant, we own the pipeline, we own the fracs. And it makes sense for us to continue to extract that ethane and make a margin on it.

Now if that ethane were to go underwater like it has at certain of our plants, Pioneer up in Wyoming, for example, we will immediately reject that ethane. So we are not exposed to that, but it shows the ramp up in today's market. With all the ethane rejection going on, we have the opportunity to come in there and take that as equity volume if we want it. If we don't want it, we can leave it in the gas.

So I think that is what has happened. I think the rampup over the course of the year has been with the new Yoakum plant coming up. We have got much more of that opportunity than we've had in the past and also late last year, we had a big contract up in the Rockies. We acquired a lot of volume that was going to a competitor's plant and it is filling up our plant up in Wyoming right now. So we've got a lot more opportunity to create more equity barrels, but we have no obligation to continue to produce them. So it is really opportunistic.

Yes and understanding that and understanding that with Yoakum early last year you guys ramped at sort of the call it 120,000 barrels a day level, but then -- so is it the Wyoming facility that really drove us in 4Q up to 145,000 and for modeling services is that what we should be seeing?

No, I think Yoakum has been running about 145,000 here lately, not 120,000. So it is doing a lot better than we thought. And same thing up in Wyoming. We have got a little bit more volume up there. That has mostly been rejected here until just recently. We have had some opportunities.

The equity NGL line I think is going to Texas.

Yes and probably -- you are talking about a 50,000 barrel per day increase fourth quarter of 2013 versus fourth quarter of 2012 and probably half of it was South Texas and half of it was Rockies.

Okay. All right, well, switching gears a bit. I appreciate the comments in response to Steve's question at the beginning on distribution growth and then thinking about the response to Ted's question about the level of CapEx needed to sort of maintain a current growth rate. I'm just curious given the opportunity set being -- having been and projected to be much larger than that sort of 1.5 billion to 2 billion sustainable level, what is the variable, what sort of drivers do you think might shape a decision to move a bit more aggressively on distribution growth given the coverage in that opportunity set?

Aggressive is probably not a good word to use for us on distribution growth, but certainly we are in a period of a low interest rate environment and so that affects our distributable cash flow. It means that we are generating a whole lot more than we might a couple years from now when interest rates start to tick up. So we are always mindful of our current economic situation and also what the outlook may be two, three, four years down the road. But, clearly, as we've said in the past, once we have more experience and have a better understanding of where the cash flows are going to settle out and what our capital needs are, we will take that into consideration when we look at our distribution. And we fully understand that there are certain investors that would like for us to blow out all of our cash flow. We don't think that is in the long-term best interest of our long-term equityholders or our debtholders.

No, agreed. Totally understood. One final cleanup question. Randy, you mentioned that there were certain discretionary maintenance items that sort of slipped year-on-year thinking about the 2014 maintenance CapEx budget and obviously you are still in that process. How do we think about variables that would drive you away from that $350 million number that is out there today?

I think we are comfortable with that $350 million number.

Okay, thanks, guys.

I think the only point there was that we had some scheduled maintenance that didn't get done in 2013. It fell over into 2014. So maybe 2014 is a little higher than it would have been otherwise.

Okay. Yes, I mean I guess we saw for 2013 the original budget was $350,000. It came in sort of $290,000. So just thinking about it being back up at $350,000, what sort of variance we might see around the $350,000.

We are not sandbagging you.

Okay, thanks, guys.

And sir, we have no further questions in the queue. I'd like to turn the call back over for any closing remarks.

Okay, Brent, thank you. That wraps up our comments, so we will close the call today. We would like to thank everybody for joining us. Brent, in closing, if you would give our listeners the replay information, I would appreciate it. Thank you.

Yes, sir. A replay of today's conference will be available beginning later today until February 6, 2014. To access the replay, please dial 855-859-2056 or if dialing internationally 404-537-3406. To access the call, please enter conference ID number 36839235. Thank you. This concludes today's conference call. You may now disconnect.