Enterprise Products Partners L.P. (EPD) Q1 2012 Earnings Report, Transcript and Summary

Good morning. My name is Ashley, and I will be your conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners First Quarter 2012 Earnings Conference Call. [Operator Instructions] Mr. Burkhalter, you may begin your conference.

Thank you, Ashley. Good morning, everyone, and welcome to the Enterprise Products Partners conference call to discuss results for the first quarter. Our speakers today will be Mike Creel, President and CEO of Enterprise's general partner; followed by Jim Teague, Executive Vice President and Chief Operating Officer; and Randy Fowler, Executive Vice President and CFO of the general partner of Enterprise. There are also other members of our senior management team in attendance today. During this call today, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 based on the beliefs of the company, as well as assumptions made by and information currently available to Enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. And with that, I will turn the call over to Mike.

Thanks, Randy. We're off to a good start in 2012, posting strong first quarter results supported by record gross operating margin from our NGL Pipelines & Services and Onshore Natural Gas Pipelines & Services segments. Enterprise had a record fee-based natural gas processing and NGL fractionation volumes this quarter. Onshore natural gas transportation volumes were 13% higher than in the first quarter of 2011, and crude oil pipeline volumes were up by 7%. This morning, we reported gross operating margin of $1.1 billion for the first quarter, a 20% increase over the first quarter of 2011. Adjusted EBITDA was also $1.1 billion for the quarter, 22% higher than for the first quarter of the prior year. Net income for the quarter was $656 million and earnings per unit were $0.73 per unit on a fully diluted basis compared with $435 million and $0.49 per unit for the first quarter of 2011. Both adjusted EBITDA and net income for the first quarter of 2012 include gains of $100 million or $0.11 per unit from the sale of 26.3 million Energy Transfer Equity, or ETE, common units and a noncash income tax benefit from the conversion of certain subsidiaries to limited liability companies. The partnership generated record distributable cash flow of $1.6 billion for the quarter, which provided 3x coverage of the cash distribution declared with respect to the quarter. Distributable cash flow for the first quarter of 2012 includes $976 million of net proceeds from the sale of the 26.3 million ETE common units and a net loss of $78 million on the settlement of certain interest rate hedges, most of which were associated with our issuance of 30-year 4.85% senior notes in February. Excluding the proceeds from the sale of the ETE common units and the payments to settle interest rate hedges, distributable cash flow would have been $731 million, providing 1.4x coverage of the cash distribution declared with respect to the first quarter. We retained $1.1 billion of distributable cash flow this quarter for reinvestment in our growth capital projects. From 2010 through 2013, we are investing in total approximately $4 billion in growth capital projects to expand and extend our franchise in the Eagle Ford Shale, including our sixth NGL fractionator at Mont Belvieu. Most of these fee-based projects will be completed in the second half of 2012 and the first quarter of 2013. Jim will review the status of these projects and others in a few minutes. We recently did a comprehensive review of our growth capital projects at our analyst meeting in March, as well as our macro business fundamentals. That information is still available on our website, so now I'd like to turn the discussion to our segment performance. Gross operating margin for the NGL Pipelines & Services segment was a record $655 million for the quarter, 30% higher than the $504 million for the first quarter of 2011. Our natural gas processing and related marketing business benefited from strong demand for NGLs as higher NGL sales margins and higher natural gas processing margins led to a $144 million or a 52% year-over-year increase in gross operating margin. We benefited from higher processing margins and fee-based volumes in our Meeker and Pioneer plants, our Louisiana plants and the South Texas processing facilities. Meeker ran at full capacity for the quarter, processing on average 1.5 billion cubic feet a day of natural gas. Fee-based natural gas processing volumes increased 12% to a record 4.1 billion cubic feet a day for the quarter compared to 3.7 billion cubic feet a day for the first quarter of 2011. Gross operating margin for our NGL Pipelines and Storage business decreased $12 million to $168 million this quarter, primarily due to lower NGL volumes transported through our fractionators in Louisiana and is a result of the startup of our fifth NGL fractionator at Mont Belvieu in October 2011, lower propane deliveries on our Dixie pipeline due to warmer-than-normal weather and higher operating expenses. Partially offsetting these decreases was a $14 million (sic) [$15 million] increase in gross operating margin from the Mid-America and Seminole pipelines and related terminals due to an increase in the systemwide tariffs that became effective in July of 2011, as well as a 9% increase in volumes. Total NGL pipeline volumes were 2.3 million barrels per day this quarter compared to 2.4 million barrels a day for the first quarter of the prior year. Our NGL Fractionation business reported gross operating margin of $65 million for the quarter compared to $47 million for the first quarter of 2011. This 39% increase was largely due to higher volumes and revenues associated with our fifth fractionator in Mont Belvieu. Gross operating margin also increased at our Hobbs and South Texas fractionators. And total fractionation volumes increased 13% to a record 623,000 barrels a day. Our Onshore Natural Gas Pipelines & Services segment reported record gross operating margin of $206 million for the quarter, a 30% increase over the $159 million reported for the first quarter of 2011. Our Acadian Gas system had a $41 million increase in gross operating margin, largely due to Acadian's Haynesville Extension that began service in November of 2011, while gross operating margin from the Texas Intrastate system increased $29 million, primarily due to growing production from the Eagle Ford Shale. Partially offsetting these improvements was a $14 million decrease in gross operating margin associated with the Alabama pipeline assets that were sold in August of 2011 and the Mississippi natural gas storage facility that was sold in December of 2011. Total net onshore natural gas pipeline volumes for the quarter increased 12% to 13.1 trillion Btus per day. Gross operating margin for the Onshore Crude Oil Pipelines & Services segment was $39 million for the quarter, a 24% increase over the first quarter of 2011. Most of our major onshore crude oil pipelines' trucking and marketing activities reported increases in gross operating margin for the quarter on higher volumes and sales margins. Increased drilling activity in the Eagle Ford Shale led to higher volumes on our South Texas system. And total onshore crude oil pipeline volumes increased to 706,000 barrels per day for the quarter, 6% higher than the year prior. The Offshore Pipelines & Services segment reported gross operating margins of $52 million for the quarter compared to $61 million for the first quarter of 2011. This decrease was primarily due to lower revenues from the Independence Hub platform and Trail pipeline, which had a $9 million decrease in gross operating margin on 20% lower volumes and lower revenues. Demand revenues of $4.6 million per month for the Independence platform ended at the beginning of March of 2012. This decrease in gross operating margin was partially offset by a $3 million increase in gross operating margin from our Anaconda Gathering System, which benefited from the Anaconda extension pipeline that had first deliveries from the Nautilus pipeline in July of 2011 and deliveries from the Caesar Tonga platform that came online in March of this year. The Caesar Tonga platform is currently producing over 45,000 barrels a day of crude oil and 50 million cubic feet a day of natural gas, which flows into our pipeline network and our Neptune gas processing plant. We're seeing positive leading indicators of activity in the Gulf of Mexico. Currently, 25 rigs are actively drilling in the Gulf of Mexico and 8 are waiting on permits. There are additional 8 rigs scheduled to arrive in the Gulf of Mexico by October, which would exceed the pre-Macondo levels of active deepwater rigs. This activity is primarily developing existing crude oil reservoirs, many of which are connected to Enterprise's onshore -- offshore pipeline system. In the deepwater Gulf of Mexico, there are long lead times between drilling and first production, but these are positive developments for our offshore pipeline system. Gross operating margin from the Petrochemical & Refined Products Services segment was $98 million for the quarter compared to $112 million for the first quarter of 2011. The primary reason for the decrease was a $19 million decrease in gross operating margin from our octane enhancement and high-purity isobutylene business. The octane enhancement facility experienced operational issues and was down for an extended period of time during the quarter, and that led to lower-than-planned MTBE and isobutylene production as well as higher-than-expected repair and maintenance expense. The plant returned to full commercial operations in late March of 2012. Also contributing to this quarter-to-quarter decrease were lower butane isomerization volumes and revenues from the sale of byproducts as well as a 13% decrease in transportation volumes on our products pipeline system. Transportation volumes on our products pipeline system were 559,000 barrels per day for the quarter, down from 642,000 barrels a day in the first quarter of 2011, due to reduced demand for refined products in the Midwest and lower demand for propane in the Northeast due to warmer-than-normal weather. Gross operating margin from the propylene fractionation business increased 25% to $61 million this quarter due to higher sales margins. Propylene fractionation volumes were essentially flat at 72,000 barrels a day. We recently announced the 31st consecutive quarterly increase in our cash distribution to $0.6275 per unit, a 5% increase over the distribution declared with respect to the first quarter of 2011. This is the longest period of consecutive distribution increases by any publicly traded partnership. We're proud of the strong results our businesses produced this quarter and of our dedicated employees who made it happen. We currently have $7.5 billion of growth capital projects under construction. $3 billion of these projects, which are predominantly fee-based, should begin operations this year. These new assets will deliver important services for our customers as well as generate new sources of distributable cash flow for our partners. The Enterprise team has been very disciplined over the years in executing our strategy to create value for our investors, and that strategy has not changed over time. We said long ago that our plan was to expand and extend our footprint around our core assets, provide more fee-based services to our customers and concentrate on the businesses we know. That plan has served us well and we see no reason to change directions now. We concluded the quarter with a strong balance sheet and significant financial flexibility that will support the remaining growth capital expenditures that will be funded this year. We remain excited about the opportunities available to the partnership this year and for the years to follow and look forward to working for our investors to create more value. And with that, I'll turn the call over to Jim.

Thank you, Mike. Today, I'm going to keep my comments focused on our recent most important developments since we just had our analyst meeting a few weeks ago where we had some excellent dialogue with investors and analysts. We believe that what we are today we created 5, 6, 7 years ago, and what we expect to be 5, 6, 7 years from now, we're creating today. In that regard, I thought it'd be interesting just to look at the projects that we announced in the first quarter of this year. We announced the ATEX Marcellus ethane pipeline. We announced an open season for the Seaway reversal. We announced a Gulf of Mexico crude oil pipeline around the Lucius production. We announced that we would double -- almost double our Mid-America pipeline expansion in the Rockies. We announced our Texas Express project with Anadarko and Enbridge. We announced our seventh and eighth fractionation trains at Mont Belvieu. We announced a joint venture project with DCP and Anadarko called Front Range pipeline. And we announced that we were going to loop the Seaway pipeline. We're trying to do our part to make sure that what we are in 5 or 6 years will deliver the same kind of results that we're delivering today. In addition to the hard work by our employees, our first quarter results continue to emphasize the benefits of solid investments underpinned by long-term fixed fees; construction of new assets that are on-time and, more often than not, under budget; and the benefits of our diversified and highly integrated business model. For perspective, we delivered these results on the face of several challenges, including an extended turnaround environment in the ethylene industry, which contributed to much lower processing margins for ethane compared to a year ago; a horrible winter for both propane and natural gas; and a significant unplanned outage at our MTBE plant that hit us for over $35 million against our budget and, I can argue, almost $50 million against what the market would have offered. Our diversified business model provided us with significant offsets to these negatives, including an increase in natural gas processing volumes due to production growth in the Eagle Ford and a lack of freeze-offs in places like the Rockies, higher realized natural gas processing margins and additional volume across our export docks where we literally squeezed in every barrel we could while sometimes, on the incremental cargos, enjoying margins that were 2 and 3x above our normal contract rates. With a portfolio as large and diverse as ours built on a solid foundation of fee-based contracts, we continue to find ways to make incremental income even in situations that would be catastrophic for others. Relative to our most recent developments, we're excited about projects that we've been working on that are currently in startup mode. As we speak, the first of our 3 Eagle Ford trains is in the startup phase, and work continues on the second and third train expected to be online in the third quarter of this year and the third train in the first quarter next year. As we bring this first train into service, it's worth keeping in mind that this is much more than the first of 3 processing plants because this first plant has to be supported by the buildout of ridge gathering and pipeline assets upstream of the plant, new natural gas and NGL takeaway infrastructure downstream and storage and fractionation assets in Mont Belvieu. Relative to our Eagle Ford crude oil activities, we're also close to achieving some major milestones as we expect to commission our Phase 1 pipeline from Marshall to Sealy in June and then commission our ECHO crude oil terminal in July. We've still got plenty of work left to do in the Eagle Ford. We still have to start up the next 2 Yoakum trains. We'll be extending our rich NGL pipeline much further into South Texas all the way to La Salle County. We've got the addition of more fractionation at Mont Belvieu. And of course, we have an extensive buildout of our crude oil asset base as we continue to grow our crude oil business. With several major projects coming online in the second quarter, we and our producers are beginning to see the benefits of our hard work. It's refreshing to see the plan that we laid out just about 2 years ago coming together and continuing to present even more opportunities as the Eagle Ford exceeds both ours and the industry's expectations. Another recent development since our analyst meeting is our announcement that we'll be building Front Range NGL pipeline in partnership with Anadarko and DCP Midstream. This pipeline will originate at the DJ Basin in Colorado and extend approximately 435 miles to Skellytown, Texas. The new Front Range pipeline is anchored by volumes from our partners and will provide producers with reliable takeaway capacity and market access to the Gulf Coast. In keeping with our tradition, in addition to being a great investment for us, Front Range provides direct integration through interconnections to our Mid-America pipeline system and our recently announced Texas Express Pipeline and, equally important, provide significant new volumes to our integrated asset base at Mont Belvieu. We anticipate initial capacity will be 150,000 barrels a day, expandable to 230,000. Enterprise will construct and operate the pipeline, which is expected to begin service in the fourth quarter of 2013. This is now the fifth NGL pipe or major expansion that we've announced, and we are now building significant NGL pipeline infrastructure for growing volumes all the way from the Rockies to Appalachia, which we believe is testament to the core strengths, geographic reach and the flexibility of our asset base. And this is all being done with a fierce discipline of staying true to our business model. Next, on the Seaway developments. The big item since our analyst meeting is our announcement that we, with our partner Enbridge, are planning to loop Seaway. After this expansion is complete in 2014, Seaway's overall capacity will exceed 850,000 barrels a day, and it will be all but fully subscribed for periods that range from 5 to 15 years. The size of the commitments to both the reversal and the expansion are impressive and indicative of the magnitude of opportunities for our shippers. When you consider the Seaway developments, along with Enbridge's expansion from Flanagan to Cushing, we're going to give crude oil producers in the Bakken and points north direct pipeline access to the huge refining demand on the U.S. Gulf Coast. And by building additional pipe from our ECHO terminal to Beaumont-Port Arthur refining complex, we also give our shippers access to the region's heavy oil refining capabilities. ECHO has a strong potential to be the hub for matching growing oil production with storage and consumption on the Gulf Coast. While underappreciated at the moment, natural gas has and will continue to provide us with opportunities both through its integration with our NGL assets on the supply side and what we believe are going to be significant increases in demand in Texas and the Gulf Coast through power generation and new industrial loads. While prices are currently depressed, producers are in the business to make money, and they continue to work on getting their costs down and, more importantly, they will continue to focus their efforts on rich gas and crude, leaving significant lean gas reserves on the shelf until prices recover. Lastly, I want to spend a minute on NGL supply-and-demand fundamentals. We're going through a period of high inventory builds for both ethane and propane, which are currently influencing the pricing of each other. While the reasons for the excess inventory levels are different, they both have in common that the large inventory builds, we believe, are short term in their nature. Their first quarter saw well over 100,000 barrels a day of ethane demand due to -- lost due to extensive petrochemical outages on the Gulf Coast, some outages planned, some unexpected. And these outages have continued well into the second quarter. All that lost demand resulted in a short-term situation for growing ethane inventory in spite of some of the best cracking margins ever. On the other hand, propane, like natural gas, saw poor winter demand due to the very mild winter, leading to stock builds. As a result, we're dealing with a competitive pricing environment between both as petchem demand for either will be subject to feedstock switching if one gets too expensive versus the other. That said, we believe that ethane inventories will start drawing down in May as these turnarounds complete and some of these plants come back up with a capability of cracking even higher volumes. Additionally, inventories -- merchant inventories will be further impacted in May as 2 large NGL fractionator outages in Mont Belvieu will result in somewhere around 100,000 barrels a day of lost ethane supply for at least a month. Looking beyond May in the second quarter, it's clear to us that petrochemical expansions and debottlenecks are proceeding, as we expected, due to the higher margins that come from cracking the lightest feedstock they can. As a Dow Chemical employee -- retiree, I was both -- I was proud to see Dow's recent announcement confirming that they will be building a world-scale ethylene plant at Freeport, 3.3 billion pounds, and restarting another ethylene plant in Louisiana at the end of the year and emphasizing how excited they are about the advantage that comes with cracking U.S. feedstocks. A quick ad lib: A 3.3 billion pound plant is twice the size of what was considered a world-scale plant only 15 years ago. 3.3 billion pound ethylene plant consumes close to 100,000 barrels a day of ethane. Their CEO, Andrew Liveris, explained to the world not only about his company's views on the growing domestic feedstock advantage, but he also spoke of a manufacturing renaissance that he believes is going to take place in the U.S. led by the newfound energy advantage. While Dow is the first major company to absolutely affirm they are going forward, they are not the only company who gets this. It seems that every petrochemical company out there with operations in the U.S. now understands this and is rushing to be able to crack as much light feedstock as they can. All you have to do is look at the margins they're enjoying. The U.S. Gulf Coast is quickly reemerging as the petrochemical center, and Enterprise will be at the forefront of that development. At our analyst meeting, we talked about the U.S. now entering the demand phase for our new energy resources. And we're excited about what this means for the U.S., the Gulf Coast and, particularly, for Enterprise, and we'll have more to come on that in the future. With that, I'll turn it over to Randy.

Thank you, Jim. I'd like to take a few minutes to discuss some additional income statement items and some balance sheet items. G&A costs in the first quarter of 2012 increased to $46 million from $38 million in the first quarter of 2011, primarily due to increased employee salaries and benefits and other employee expenses. For the remainder of 2012, probably $38 million to $40 million per quarter is a good run rate. Interest expense increased to $187 million this quarter from $184 million for the first quarter of last year, due primarily to increased debt to fund our growth projects. Average debt balances for the first quarter of 2012 and 2011 were $14.5 billion and $14.1 billion, respectively. Capitalized interest increased by $13 million this quarter compared to the first quarter of last year. We recognized a net income tax benefit of $34 million this quarter compared to a $7 million provision for income taxes in the first quarter of 2011. The $41 million positive variance was primarily due to the conversion of certain subsidiaries to LLCs, as Mike mentioned earlier. Total capital expenditures were $1 billion this quarter, which included $928 million for growth projects. Approximately 60% of the growth capital expenditures this quarter were related to the Eagle Ford and Haynesville projects. Currently, we expect to invest approximately $3.7 billion in growth capital projects in 2012. Sustaining capital expenditures were $90 million this quarter, which was about $11 million higher than our plan, due largely to a carryover project from 2011. We still expect to spend approximately $300 million to $325 million of sustaining capital expenditures in 2012. Adjusted EBITDA for the 12 months ended March 31, 2012, was $4.2 billion. This is calculated on Exhibit E of our earnings press release. Our consolidated leverage ratio with debt principal to adjusted EBITDA was 3.3x for the 12 months ended March 31, 2012. This is after adjusting debt for 50% equity treatment for the hybrid debt securities. The average life of our debt is 12 years if we use the first call date for the hybrids; it's 17.4 years if we use the final maturity date for the hybrids. And our effective average cost of debt is 5.9%. The proceeds from monetizing 26.3 million ETE units during the first quarter of 2012 essentially funded our $928 million of growth capital expenditures this quarter. Since the end of March, we sold our remaining 3 million units of ETE and received additional net proceeds of approximately $120 million. This completed the monetization of our entire position in ETE units. In March, we filed an S-3 registration statement that allows us to issue EPD common units from time to time through certain sales agents to be named in one or more prospectus supplements. This type of offering is called an ATM or at-the-market program. The next step in this process would be filing such a prospectus supplement, which will probably occur in the second quarter. This is just another tool in our financing toolbox. On our last earnings call, we said that, based on our then-current expectation of capital expenditures and earnings, we did not see the need to issue equity this year, and that view has not changed. At March 31, 2012, we had consolidated liquidity of approximately $3.6 billion, which included availability under EPD's credit facility, as well as unrestricted cash. With that, Randy, I think we're ready for questions.

Ashley, we are ready to take questions now.

[Operator Instructions] Our first question comes from the line of Darren Horowitz with Raymond James.

Jim, a couple quick questions for you. The first, as you mentioned, as those ethylene plants come back online, can you give us a sense for how much incremental ethane demand you think might materialize? And as ethane inventories get drawn down at the same time that those 2 fracs are reducing supply, how much upside do you think ethane might have in terms of price?

If I knew that, Darren, I wouldn't be sitting here talking to you. I don't know. I mean, it -- there's more variables than just that, so I don't know what price will be. I'm having somebody hand me something here. Give me a number.

Announced? There's about 70,000 barrels a day of incremental ethane demand that's been announced by the end of the year. That's just announced. We believe there's going to be quite a bit of incremental demand that's coming on projects that are not announced. What it means for prices? I mean, as Jim had mentioned, propane is going to continue to influence ethane pricing at least over the next few months because of the propane inventory situation.

Right, okay. Jim, another tricky question for you, and this one is more geared towards what you guys have going on with Meeker and Pioneer out of the Rockies. But I'm curious as to how you're thinking about hedging those NGL equity volumes because to that point, with higher propane inventories pressuring price and, obviously, there's been more of a shift from producers switching, reducing equity exposure, more fee base. So how are you thinking about your exposure for what's coming out of the tailgate of those plants in the back half of this year?

I think we've got about 60%, Mike, of our stuff hedged at this point for the year. I think we're pretty well hedged on the C3Plus. And we are expecting that we'll be able to lock the ethane in a little higher than what it is today once some of these dynamics present themselves.

Can you share for us on the C2 where you're hedged in the third and the fourth quarter?

No. I just don't see it here, Darren. I'm trying to think. Okay, we're probably 15% hedged in the third and fourth quarter.

Okay. And then last question, Jim, just an update on the propane export terminal expansion. I -- we were kind of thinking, maybe late third quarter or early fourth quarter, one of your competitors is coming online in the first half of next year. Do you think that's going to be enough export capacity to help balance the propane market?

I don't know. We're selling -- I don't have a clue, Darren. We're selling our -- we're selling cargos, we're doing contracts out through -- I'm looking at Lynn Bourdon. Through 2014 and into 2015, now?

We've done contracts through 2017.

Okay. So we're seeing a lot of demand for people wanting to lock up space on the export dock there. What we're more focused on than what you're talking about is to make sure that we've got the export quality of propane that we need. That stuff needs to be 2%, 2.5% ethane, max. So what we're focused on is making sure we have that. When you -- and when people’s talking about putting in export capabilities, what you really need to do is look at what is their capability to supply the quality of product that goes through that terminal.

And our next question comes from the line of Brian Zarahn with Barclays.

In the offshore segment, can you give us your thoughts about expected improvement in Gulf of Mexico volumes? Is this more of an event this year or more of a 2013 event?

Yes, this is Mark Hurley. Yes, we think that we're going to see volumes into our systems increase slightly this year over last year, and then we see it ramping up pretty steadily in 2013 through the end of the decade. So we feel pretty bullish on it.

Well, since I have Mark on the line, my next question is in terms of the crude oil business, you're seeing your competitors enter the crude oil midstream sector through either acquisition or announced organic projects. Has it -- does this impact your growth plans down the road, do you believe?

Let me take it. No. We're going to keep doing what we're doing. Our intent -- and it doesn't matter if it's crude oil, NGLs, petrochemicals or natural gas, our intent is to stay disciplined that what we do fits what we got. And we're going to continue to build our systems out regardless of the commodity in the same way as we have in the past.

Okay. And then obviously you've got continuing growth in your organic projects. Can you give us some initial thoughts on 2013 CapEx?

Well, I think you can look at where we've been for the last couple years. Throw out 2009 because we were lower in CapEx because of the financial market uncertainty, but 2010, '11 and '12 kind of shows you we're kind of $3.5 billion to $4 billion a year run rate. And based on the new projects that we're looking at, don't really see that slowing down much.

Okay. And the last one for me. On the distribution, can you give us a little color on your thought process around potentially increasing the annual growth rate above the $0.12?

Well, I think we mentioned this last call, that we are certainly mindful of our distribution coverage. That coverage has been somewhat distorted because of some unusual transactions such as the sale of the Energy Transfer Equity units. But throwing out the noise, we're still at 1.4x with a pretty healthy capital budget for the year. What we said was that we're going to reevaluate our distribution strategy towards the end of the year when more of these projects come online and we have a little more clarity on timing and cash flows. But certainly, we listen to our investors, and we're going to be taking that into consideration.

So you still expect a potential decision by year end?

We're going to reevaluate. We'll make a decision one way or another, yes.

And our next question comes from the line of Mark Reichman with Simmons.

Well, this is kind of just a general question, but given the need for infrastructure and recognizing the value to both producers and, say, like, for crude oil refiners, I was hoping you could shed some light on some of the discussions you have with producers during the open seasons and talk a little bit about kind of how you price your services to ensure the highest return for investors, taking into account regulatory issues. And then just talk a little bit about the implications for current and future returns and whether you want to just talk about, say, crude oil or compare and contrast that with other types of infrastructure, whether it be natural gas or NGL investments.

Mark, I think that, clearly, anytime you go through an open season, you're talking with potential shippers and you're trying to determine what a market rate is. And we've had a lot of experience with crude oil open seasons that just didn't work out well because we couldn't generate shipper interest. I think that, in this case with Seaway in particular, we really had an advantage, in part, because of our partner that had access to shippers that we didn't have access to before. So really, the rates that we're coming up with, the negotiated rates based on settlement -- on the discussions with shippers, and I think that what we're going to come up with is a rate that makes sense for us and for them. You can certainly look at recent basis differentials and say, "Gee, it'd be nice if you could get $15 a barrel to move that stuff from Cushing to the Gulf Coast," but in reality, that just doesn't happen.

Okay. And then just secondly, on the income tax benefit, I guess it was just a little unclear to me, what was behind that conversion of those subsidiaries to LLCs?

Partly, to reduce our tax burden. We're a partnership, and it didn't make sense to have C corps underneath us at all times. And we've got a couple of entities that we completed buying out 100% ownership interest, and so the logical progression was to convert those to LLCs. That's more consistent with an MLP structure.

Okay. And then lastly, just on just a little discussion on what happened at the octane enhancement facility.

The motor broke. I think that the short answer is that we do an annual turnaround. When we were bringing the facility back up, we had problems with the catalyst, and frankly, it just took us much longer than we expected or hoped it would to sort out those problems.

And our next question comes from the line of Ted Durbin with Goldman Sachs.

Coming back to the Seaway pipeline. It looks like you filed for tariffs of around $4 a barrel, kind of depending on whether it's heavy or light. I'm just wondering, how much of that should we be thinking about as being contracted versus spot for the first 150,000 a day and then for the 400,000 a day, when that comes online? And then just directionally, does that -- for modeling, is that kind of a rate we should be thinking about for the incremental volumes that you're going to be bringing on the additional 400,000 or 450,000?

Yes, we -- as far as the rates on Seaway, we're contracted at roughly 2/3 of the capacity that will start up of the 150,000 barrels a day in May. The $3.82 is the rate that will be the walk-up. And of course, the committed shippers have -- are going to go the rates that were in the PSA negotiations. Going forward, we will -- we see ourselves sticking to the $3.82, as escalated with the FERC index. And as new shippers come on, they will come on at their negotiated committed rates.

Okay, that's helpful. And then, you talked a little bit about -- at the Analyst Day, about wanting to get bigger in the Marcellus. Any further thoughts there in terms of how that might happen? Are you thinking about -- do you build your way into there? Do you buy in a way into there? Just to have a little more commentary on that.

I think we're still trying to decide where -- what our role is beyond where we are. And I'm going to let Mike say -- I'll say something and see if Mike agrees: I don't see us buying in right now, given what we see. I think we'll build that.

Based on the latest acquisition in the Marcellus and the price paid for that, I think it really doesn't fit us.

Okay, that's helpful. And then just lastly, if you can talk a little bit around some of your efforts to turn around some of the refined product volumes. Obviously, you're having -- the segment's been struggling. Kind of where are you on that?

You see, there's some other refined products pipelines into the [indiscernible]...

Into the Mid-Continent, yes, into the Midwest.

This is James Collingsworth. Since our analyst meeting, we have met with 5 potential customers, a couple of them being majors. The excitement that we saw in those discussions, especially from a major, highly encouraged us. And we're waiting on them to come back with specific volumes. We've got our numbers running on what our capital is, and we'll see where that goes.

And our next question comes from the line of Carlos (sic) [Ross] Payne with Wells Fargo.

Yes, it's Ross Payne. Okay, Jim, a quick question. Obviously, the Eagle Ford is ramping up in a huge way. We've heard from others that the Bakken is going to be above a million barrels a day by 2016. If you can maybe give us some kind of color on what you're hearing in the Eagle Ford in that regard. And then secondarily, if you can just talk about Meeker being full and what's going on in the Rockies.

I guess we've heard numbers around a million barrels a day in the Eagle Ford. So I mean, if you look at what we've got subscribed on our pipeline, at the peak, we're full without an expansion, so we like what we see. In terms of Meeker and the Rockies, the plant's full. And our guys keep backfilling. They keep doing deals to add incremental volumes to Meeker, and it just continues to run full, producing, what, 100,000 barrels a day, roughly?

Okay. So it's being driven hard by the push to liquids.

Yes.

And our next question comes from the line of Michael Blum with Wells Fargo.

Two quick questions. One, as Independence Hub kind of rolled off those demand charges, would you expect, going forward, it's just going to be purely volumetrically driven? Or do you think there's a possibility to re-up for additional demand charges?

We wish. No, I don't think it's going to be volumetrically driven. Demand charges were there to sanction the project and get it built, but I don't think anybody is going to step up to that now.

Okay. And what is your outlook on volumes for that system?

I think we're going to be in the 400 to 450 range over the next year or so. There's not a lot happening on new gas drilling activity. There is some but obviously not as much as we'd like to see. The activity in the Gulf is really focused on oil right now.

Okay. And then it looks like, as frac capacity comes up at Mont Belvieu, you're seeing volumes diverted out of Louisiana. Would you expect that trend to continue? Or do you think you're sort of going to fill up Mont Belvieu and then get to a point where you're again going to be in a situation where you're pushing the -- sort of the incremental or excess barrel over to Louisiana? Just trying to understand the market dynamics around that.

I don't think, over the next 2 or 3 years -- Rudy in here. I don't think, over the next 2 or 3 years, we're going to see -- we're probably still going to need to use our Louisiana fractionation assets to take care of the surplus.

Our current forecast shows we're going to fill up pipe.

And that's how we contract. I mean -- who is that, Ted?

Michael Blum.

Oh, Michael. Michael, that's how we contract. I mean, we typically will contract beyond the capacity, understanding we've got Louisiana as something we can fall back on. And then when we bring one up, it's full the day it comes up.

[Operator Instructions] Our next question comes from the line of TJ Schultz with RBC Capital Markets.

Just in the onshore crude segment, looking at the sequential other than [ph] gross margin. Was the entire magnitude of the decrease due to Seaway being down in first quarter?

No. What you -- this is the LLS answer, isn't it? And I want to just make a point. A lot of where our lease buying -- these guys, producers, they can read the numbers too, and we've had to switch a lot to LLS. And frankly, we had a couple of contracts that we locked in lower margins than what ultimately the market would've given us in the first quarter.

Yes. And I'll just add that, for quickly the second half of last year, there were 2 things that were really driving very high margins. One was a scarcity of transportation, 50 trucks. And so if you had trucks, you could get out there and get the oil and really buy and sell at very high margins. The other thing is that there was a period of time when you could buy on the WTI index and sell on the LLS index, and that was very enjoyable, but it didn't last for very long. And so now the market is back on more of an even keel with respect to the indexes we're buying and selling on. And transportation is kind of caught up with production, although we do see that logistics are becoming a little more constrained as production in the Eagle Ford is ramping up. So we're a little more optimistic for the second quarter.

Just a question on West Texas. With Trinity flowing fairly soon at 15,000 to 20,000 barrels a day, what kind of time period should we think about for a ramp there to full capacity and should begin gathering volumes? And then thinking about your options, as Avalon-Bone Springs continues to grow, is the plan to take all those volumes onto North Loop and the Midland terminal? Or ultimately, how are you thinking about maybe getting into something like Longhorn?

Yes, good question. We see Trinity essentially being full middle to second half of next year. And so that asset that we're putting in service today is going to -- is sitting -- placed very well in the middle of that Avalon-Bone Springs area. The -- some of that volume will go into our -- or actually, all that volume will go into our Midland terminal and then into basin. We are looking now at options to get into Longhorn, but that's a thing that's still in the developing stage there.

Okay. Just lastly, shifting gears to the Bakken. You've talked about adding more trucks and then possibly getting more involved in regional gathering and rail solutions. Just looking for any additional color you -- or how you think about you could capitalize on some of the near-term rail opportunities out of the Bakken.

We continue to add trucks up there. I guess we're talking to some folks but, I mean, it's not at the top of the list. We've a got a guy out there that is absolutely fantastic, and we give him the resources to do what he does best. That's kind of where we are.

Our next question comes from the line of Bradley Olsen with Tudor, Pickering.

On the NGL pipeline side, since the announcement of the Front Range pipeline, which is going to add about 150,000 barrels a day, does that necessarily imply that you guys are going to have to add 150,000 barrels a day of compression to bring Texas Express up to 400,000 barrels a day?

No, it doesn't. In time, maybe, as that grows. But we've got -- with the Texas Express, as it's designed today, we can do 250,000 to 300,000. And we've got contracts, I think we said, at 150,000, and you add that other 105,000, you're up. So we can go a ways before we do that. But remember, compression is very cheap and can shift away [ph] in pipe.

Okay. And on the -- I think, during the Analyst Day, you guys made some mention of pursuing some more downstream maybe Petrochemical Services segment, fee-for-service opportunities, maybe joint-venturing or finding some way to get involved in propane dehydrogenation. Any updates on that front?

No. We continue to -- it's something that we would -- we're very interested in doing. And I think, at the end of my prepared comments, I'd said something about we're looking forward now to -- at Enterprise, we put as much focus on the demand side of the equation as we do on the supply side of the equation. A lot of the projects that we've done have been supply-side oriented. We talked about an ethane header system that's more of a demand-side orientation. And it's no secret: If we can do some things around PDHs, it's a natural extension of our value chain. It addresses the demand side, and we're highly interested is about all we can say at this point.

Okay, great. And just one more quick one. Mark, you mentioned some of the changing dynamics in the crude marketing business, specifically the shift to LLS-linked marketing and maybe a little bit of easing of the truck shortage that we saw last year. Would you say that the first quarter margin number for the onshore crude business is a decent run rate, going forward?

I see it getting better in the second quarter due to the fact that things are again getting constrained in the Eagle Ford, particularly barrels flowing into Corpus, which I think bodes well for our pipeline coming up. And of course we'll have the -- in the third quarter and beyond, we'll have the Seaway line in operation, and there will be some margin opportunities there.

And our next question comes from the line of John Tysseland with Citicorp.

I just had a quick clarification question for Jim on the hot topic of this morning, which is NGL exports. Historically, volumes have roughly tracked the propane up in Europe during the winter months. But as we see propane's price decline here in near term, is it your expectation that exports will continue kind of at max volumes due to summer? And then secondarily to that and kind of a follow-up to your comments on demand for product, could you also see petchems abroad looking to the U.S. for NGLs if the price is low enough, meaning that, that export capacity would be more full all throughout the year rather than more seasonal?

Well, we're sold out through this year. Are we sold out next year, Lynn?

Close.

And we're close to being sold out next year. With the expansion?

Yes.

Yes, with the expansion. John, it really comes back to gas to crude. As long as you have natural gas selling as low as it is relative to crude, it makes this market a natural source for propane for the rest of the world. And frankly, I think some of that is driven by crackers in other parts of the world using LPG that creates a little bit of a vacuum that attracts product from the U.S. for more traditional markets or demands.

So at this point, your expectation would be that the export market or the export side of the U.S. would not decline during the summer and maintain a pretty hefty pace. Is that fair?

Well, I got contracts that said that won't happen for the next 2 years.

And there are no further questions in the queue. I will now turn the call back over to Mr. Burkhalter for any closing remarks.

Ashley, if you would, would you give our listeners the replay information for the call today?

Thank you for participating in today's conference call. This call will be available for replay beginning at 1:00 p.m. Eastern Standard Time today through 11:59 p.m. Eastern Standard Time on May 9, 2012. The conference ID number for the replay is 71017585. The number to dial for the replay is (855) 859-2056 or (404) 537-3406.

Okay. Thank you, Ashley. And thank you, everyone, for joining us on our call today. And have a good day. Goodbye.

Thank you, ladies and gentlemen. This does conclude today's conference call. You may now disconnect.