Enterprise Products Partners L.P. (EPD) Q4 2011 Earnings Report, Transcript and Summary

At this time I would like to welcome everyone to the Enterprise Products Partners Fourth Quarter 2011 Earnings Call. [Operator Instructions] I will now turn the conference over to Randy Burkhalter, Vice President of Investor Relations.

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

Thanks, Randy. Enterprise had another successful quarter to end 2011, setting financial and operating records as our integrated system of assets handled all-time-high natural gas volumes, NGL fractionation volumes, and fee-based natural gas processing volumes, as well as near-record liquids volumes. This led to new records for net income, adjusted EBITDA, gross operating margin and distributable cash flow. In 2011, we invested $3.6 billion of growth capital to develop midstream infrastructure, primarily related to the Haynesville and Eagle Ford Shale plays, to serve our producing customers and to accommodate our petrochemical customers in meeting their increasing demand for NGLs as feedstocks. We completed 2 large projects in the fourth quarter of 2011, the Haynesville Extension of our Acadian natural gas pipeline system and our fifth NGL fractionator at Mont Belvieu. The Haynesville Extension provides producers access to 12 interstate pipelines that serve markets in the Midwest, Northeast and Florida, as well as our legacy Acadian system, and the fifth fractionator at Mont Belvieu increases our nameplate fractionation capacity to 380,000 barrels a day at that location. These projects which total approximately $1.7 billion of capital investment were completed 5% under budget and began generating new sources of gross operating margin and distributable cash flow in the fourth quarter. Our commercial, engineering and operations teams continue to develop new projects, capitalizing on growth opportunities provided by our diverse system of assets. We currently expect to spend approximately $3.5 billion on organic growth projects in 2012. In total, we have about $6.5 billion of projects under construction that are scheduled to begin operations in 2012 through 2014. We expect these new, primarily fee-based assets will generate additional distributable cash flow through 2015, giving us clear visibility to near-term growth. Turning to our financial and operating performance. We reported record results again this quarter supported by growth in natural gas, NGL and crude oil production in the shale regions, as well as strong NGL sales margins. Our integrated system continues to operate at record or near-record volumes. Enterprise reported gross operating margin of $1.1 billion for the quarter, a 33% increase over the fourth quarter of 2010. This led to record adjusted EBITDA of $1.2 billion and record net income of $726 million for the quarter. Net income attributable to partners for the fourth quarter of 2011 was $0.82 per unit on a fully diluted basis compared to $0.33 per unit on the same basis for the fourth quarter of 2010. I will point out that net income for the fourth quarter of 2011 included a $130 million or $0.15 per unit of gains from sales of assets. Our partnership generated record distributable cash flow of $1.4 billion this quarter, which provided 2.7x coverage of the cash distribution declared with respect to the quarter. Included in distributable cash flow this quarter was $593 million of net proceeds from assets from the sale of our natural gas storage assets in Mississippi and 1.1 million common units of Energy Transfer Equity, L.P. units. Excluding these proceeds, our distribution coverage was still 1.5x, allowing us to retain some of our cash flow to help fund our growth capital projects and reduce our dependence on capital markets. In 2011, we invested approximately $3.6 billion in growth capital and improved our credit metrics while only issuing $543 million of Enterprise common units. We have the flexibility to create additional value for our partners due to the way we manage our cash distribution coverage, and the fact that our general partner no longer has any incentive distribution rights. This disciplined approach to cash management results in a lower cost of equity capital, reduces equity dilution and supports long-term distribution growth. Turning to segment results, our NGL Pipelines & Services segment reported gross -- record gross operating margin of $635 million for the quarter, a 39% increase over the $457 million reported for the fourth quarter of 2010. Our natural gas processing and related NGL marketing business benefited from strong demand for NGLs as higher NGL sales margins and higher natural gas processing margins led to a $157 million increase in gross operating margin. Our NGL marketing business continues to have higher NGL sales margins driven by strong industry fundamentals, such as increased petrochemical demand for light end feedstocks, regional basis differentials and a strong butane isomerization market. Our Rocky Mountain processing plants also contributed to the increase in gross operating margin due to strong processing margins, higher equity NGL production and increased fee-based processing volumes. The Meeker gas plant operated near full capacity this quarter, processing approximately 1.5 billion cubic feet a day of natural gas. We also completed an expansion of our Piceance gathering system, which supplies our Meeker gas plant, resulting in lower pipeline pressures and higher gathering volumes from some of the more NGL-rich gas producing areas. Fee-based natural gas processing volumes increased 22% to a record 4.1 billion cubic feet a day for the quarter compared to 3.3 billion cubic feet a day for the fourth quarter of 2010. Gross operating margin for our NGL pipelines and storage business decreased $10 million to $170 million this quarter, primarily from lower NGL volumes transported to fractionators in Louisiana due to the startup of our fifth NGL fractionator at Mont Belvieu, decreased NGL volumes on our Tri-States pipeline from unscheduled maintenance on a third-party's offshore platforms in the Gulf of Mexico, lower propane deliveries on our Dixie pipeline due to warmer weather and higher pipeline integrity expenses on certain pipelines. The Mid-America and Seminole pipelines reported a $16 million rise in gross operating margin, largely due to an increase in systemwide tariffs that became effective in July 2011. Total NGL pipeline volumes were 2.3 million barrels per day this quarter versus 2.5 million barrels per day for the fourth quarter of 2010. A few weeks ago, we announced that shippers exercised options to increase their capacity commitments on the Rocky Mountain expansion of our Mid-America pipeline to 82,500 barrels a day from an initial 38,500 barrels a day. That's a 114% increase. We executed firm 10-year ship-or-pay transportation agreements to our shippers to support this expansion, which will enable them to maximize the value of their Rocky Mountain NGL production by providing access to the largest NGL market in the U.S. The expansion will also complement our Texas Express Pipeline joint venture, which will provide shippers access to Mont Belvieu for their mixed natural gas liquids. We also announced our plans to move forward with the construction of the Appalachian to Texas Ethane Express pipeline or the ATEX Express pipeline to provide shippers an attractive option to move ethane from the Marcellus and Utica basins to Mont Belvieu where they will have access to every ethylene plant in the United States. Shippers have executed 15-year take-or-pay proceeding agreements to move ethane volumes, ramping up to 120,000 barrels per day over a 5-year period beginning in early July -- of early 2014, and Jim will go into more detail about these projects in a few minutes. Our NGL fractionation business reported gross operating margin of $69 million for the quarter, that's an 80% increase over the $38 million reported in the fourth quarter of 2010. Gross operating margin from our Mont Belvieu fractionators increased $23 million, primarily because of the addition of 2 new fractionation units. Frac-4 began commercial operations in the fourth quarter of 2010, while frac-5 began operations in the fourth quarter of 2011, and both have been running at full rates. Gross operating margins were also up at our Norco, Hobbs and South Texas fractionators. Our Onshore Natural Gas Pipelines & Services segment reported gross operating margin of $199 million for the quarter, a 46% increase over the $136 million reported for the fourth quarter of 2010. Our Acadian Gas system reported a $30 million increase in gross operating margin for the quarter, largely due to its Haynesville Extension pipeline that began service on November 1, 2011. Gross operating margin from the Texas Intrastate System increased $24 million, primarily because of growing production from the Eagle Ford Shale. Total onshore natural gas pipeline volumes increased 14% to a record 13.2 trillion Btus per day for the quarter. Producer development of the Eagle Ford Shale continues to be strong as the rig count increased 88% to 210 active rigs at the end of 2011 compared with 112 rigs operating at the end of 2010. We're currently receiving approximately 900 million cubic feet a day of natural gas from the Eagle Ford compared with 440 million cubic feet a day at the end of 2010. The vast majority of our Texas gathering and processing systems are currently operating at maximum capacity. In the fourth quarter of 2011, we commissioned the expansion of our 30- and 36-inch Eagle Ford wet gas pipelines allowing us to increase capacity and lower operating pressures. We expect to see a steady increase in Eagle Ford volumes throughout the first half this year, with a significant increase in mid-2012 after we complete the first 2 300 million cubic feet a day trains at our Yoakum gas processing plant, and the commissioning of our Eagle Ford mainline expansion. Gross operating margin for the Onshore Crude Oil Pipelines & Services segment increased 157% to $67 million compared to $26 million in the fourth quarter of 2010. All of Enterprise's major onshore crude oil pipelines, storage assets and marketing activities reported increases in gross operating margins for the fourth quarter of 2011 on higher volumes and sales margins, with the exception of Seaway Pipeline, which was essentially the same as the fourth quarter of 2010. Seaway obviously continues to be impacted by the lack of demand for northbound transportation to the oversupplied Cushing hub, but increased drilling activity in the Eagle Ford Shale led to higher volumes at our South Texas system. In November 2011, Enterprise and Enbridge jointly announced plans to reverse the Seaway Crude Oil Pipeline that extends from Cushing, Oklahoma to Freeport, Texas. On January 4, we began open seasons for increased commitments from shippers to support an expansion of Seaway in an extension of the pipeline into the Port Arthur-Beaumont refining markets. The initial 150,000 barrels a day of capacity on the reverse system should be available during the second quarter of this year, and after pump station additions and modifications, we expect to be able to flow up to 400,000 barrels a day by the first quarter of 2013. The current open season is to solicit interest for capacity over and above that 400,000 barrels a day, and again, Jim will talk about this in more detail following my remarks. Offshore Pipelines & Services segment reported gross operating margin of $60 million for the quarter compared to $66 million for the same quarter of 2010. The Independence Hub platform and Trail pipeline had a $2 million decrease in gross operating margin on 8% lower volumes. Overall, our offshore natural gas pipeline volumes were 1.1 trillion Btus per day for both quarters in 2010 and 2011. Gross operating margin from our offshore crude oil pipelines decreased $5 million to $20 million this quarter, primarily due to maintenance by certain producers on their upstream platforms and wells that impacted volumes. Total offshore crude oil volumes were 282,000 barrels per day versus 304,000 barrels per day in the fourth quarter of 2010. In January, Enterprise and Genesis Energy announced transportation agreements with 6 Gulf of Mexico producers that support the construction of a new crude oil pipeline serving the Lucius development area in the southern Keathley Canyon. This 149-mile 18-inch pipeline will have the capacity to transport 115,000 barrels per day of crude oil and will connect a Lucius production platform to an existing platform at South Marsh Island 205 that is part of the Enterprise-operated Poseidon pipeline system. We expect this pipeline to begin service by mid-2014. Crude oil from Lucius will be delivered into the Poseidon pipeline, providing yet another source of incremental cash flows from this project. Gross operating margin from the Petrochemical & Refined Products and Services segment was $137 million this quarter compared to $140 million for the very strong fourth quarter of 2010. The propylene fractionation business had a $5 million decrease in gross operating margin due to lower sales margins and pipeline volumes. Propylene fractionation volumes were 75,000 barrels a day for the fourth quarter of 2011, down slightly from the 74,000 barrels a day in fourth quarter of 2010. Enterprise's butane isomerization business reported a 52% increase in gross operating margin to $32 million this quarter due to increased isomerization volumes and revenues from the sales of byproducts. Butane isomerization volumes were a record 106,000 barrels a day for the fourth quarter of 2011, 22% higher than the fourth quarter of 2010. The refined products pipelines and services business had a $23 million decrease in gross operating margin, largely due to higher operating expenses and a 125,000 barrel a day decrease in refined products volumes being transported from the Gulf Coast to the Midwest. Our octane enhancement and high-purity isobutylene business reported a 139% increase in gross operating margin to $27 million for the quarter, largely due to higher margins from octane additive sales, as well as a full quarter of earnings from our high-purity isobutylene plant that we acquired out of bankruptcy in late 2010. We recently announced an increase in our quarterly distribution to $0.62 per unit or $2.48 on an annualized basis. This is a 5.1% increase over the distribution declared with respect to the fourth quarter of 2010. We've now increased our cash distribution for 30 consecutive quarters, the longest period for any of the large cap publicly-traded partnerships, and this is our 39th increase since our IPO in 1998. In terms of consistent distribution growth, we increased cash distributions in excess of 5% for each of the last 7 years, including during the financial crisis in 2008 and 2009. After our major capital projects we completed in the second half of this year, including those in the Eagle Ford Shale, we plan to do our annual assessment and evaluate the potential for an increase to our distribution growth rate in light of our expected distribution coverage and our growth plans for 2013. We're very pleased with the record results reported again this quarter and for the full year. This success would not have been possible without the hard work and dedication of our employees and the support of our investors and commercial partners. Our employees across every part of our organization have worked together to make Enterprise the partnership it is today, and I hope they are as proud of their accomplishments as we are of them. We have 8 locations that have gone more than 20 years without a lost time accident, and 3 of those have gone more than 30 years, and we want to thank all of our employees for embracing safety as a core value. Of course, we have many other facilities with excellent safety records, but a lot of those have not been around for 5 years, much less 20 or 30. I'd also like to congratulate the whole Enterprise organization for their hard work that led to the recent upgrades of our credit ratings by Standard & Poor's and Moody's. Both rating agencies maintained their positive outlook on Enterprise's senior unsecured debt securities and cited factors that contributed to an improved credit profile for Enterprise, including an increasing proportion of fee-based income, progress in simplifying our legal equity -- our legal entity structure and a lower cost of capital, primarily due to the elimination of the general partner incentive distribution rights. We remain excited about the opportunities available to the partnership, and we look forward to another successful year in 2012. And with that, I'll turn the call over to Jim.

Thank you, Mike. Today, I'd like to provide you with some insight into a few of the major projects we have underway and provide you with some of Enterprise's observations on NGL supply and demand now that an ethane solution has been defined out of the Marcellus. And I'll add, it seems every 6 months, someone starts shouting that the sky is falling where NGL supplies are concerned and we'll address that. As Mike's already discussed, we had a pretty good fourth quarter and an impressive 2011. While the income results were impressive, we also had a great year in continuing to implement our major projects and also in identifying new strategic opportunities for Enterprise. I'm going to echo what Mike said, that results like this come from a number of factors: one being well-positioned to capture market opportunities; good investment decisions; a highly integrated business model; but I think maybe most important, the dedication of Enterprise employees. Our folks are driven, they're creative and they deliver results. In short, they make things happen. As Mike said, we're quite proud of them, and I know that a lot of them dialed into this call, and I think it's important that they know their efforts are appreciated. In fact, we think they are our strongest asset. In regards to key projects, needless to say, we've had some very strategic developments over the last couple of months. First that the Eagle Ford continues to beat everyone's expectations, and frankly, our assets can't get up and running soon enough. Our pipes, our plants and our fractionators in the Eagle Ford are chock-a-block full. Our Texas commercial operations and marketing groups are going above and beyond to make sure that our producer's gas is flowing. They come in early and they stay late to make sure that our performance meets our customer's expectations. Our Yoakum processing plant and related NGL natural gas facilities will begin coming on line with the first train at Yoakum in early May, the second train, Tom, in June?

Yes.

And the last train in the first quarter of 2013. Mike stated this, but it's worth restating. With over 4,300 drilling permits issued, 3,100 wells already drilled, 210 rigs running and approximately 1,000 wells waiting on completion of our infrastructure, our new plant -- our first train will be full from day one. I didn't frankly believe that until the guy sat me down and went through the numbers, and it's hard not to be excited about the need for even more rich grass -- rich gas infrastructure. What we've already done in the Eagle Ford is overwhelmingly successful whether we lay another inch of pipe or not. However, I don't think we're through. We also continue on schedule for our Eagle Ford crude oil system, which includes 2 phases of crude oil pipeline running 215 miles through the heart of the Eagle Ford crude window with an initial capacity of 350,000 barrels a day, and our network of new terminal storage along the pipe connecting to our new ECHO terminal near Houston, which combined will have a storage capacity of approximately 5 million barrels. Again, whether we add another contract, we already have a very successful project. Mark Hurley tells me we're not through. Moving next to Seaway. We're quite pleased with Enbridge's purchase of Seaway and our joint project to reverse and expand it, including building that other 85-mile extension from our ECHO terminal to Port Arthur, which will give our shippers access to the largest refining complex in the world. We expect to get the pipeline into southbound service in the second quarter and have the project fully completed by late this year. As is the case with most of our systems, we expect significant integration between the Eagle Ford crude oil projects and the reverse and expanded Seaway Pipeline that's going to yield even more benefits for years to come. We believe that Seaway's capacity will be fully contracted. We are in the midst, as Mike mentioned, of an open season, and frankly, if we have the shipper interest, we will loop Seaway. One of the things that differentiates Seaway is, in combination with our partner Enbridge, we can access supplies from Alberta, the Bakken and Cushing and then deliver those pipe to every refinery in Houston, Beaumont and Port Arthur. Through an upgraded barge dock, we can access the entire Gulf Coast. That supply and market position is anchored by 21 million barrels of storage that between us, Enterprise and Enbridge owns in Cushing, almost 7 million barrels that Seaway owns, and when fully developed, an ultimate 5 million barrels of storage at ECHO, all tied to every refinery on the Gulf coast. We will have the ability to deliver it to the refinery, not tell the refinery to come and get it. This project is consistent with all our projects. We're offering the producer flow assurance, ratability and market choices and the consumer reliability and flexibility. Now about some of our major NGL pipeline expansions of which we have 4 underway. We have our Eagle Ford NGL pipeline, our Mid-America Rocky Mountain expansion, our Texas Express and our Marcellus ethane pipeline that we're calling ATEX. The magnitude of these expansions is exciting because of the geographic reach, serving the growing production literally from the Rockies to Appalachia. In addition to being great standalone projects backed by long-term ship-or-pay agreements, all 4 are going to bring long-term strategic value to our NGL network for the -- Mike's already mentioned that the Mid-America expansion topped out at 82,500 barrels a day. This project and the Texas Express joint venture NGL pipeline we're building with Enbridge and Anadarko are complementary, and they are sure producers, both in the Rockies and in the rich corridor developing in the Mid-Continent, that they have a reliable outlet for their production. I'll add we're not slowing down out west. There's more to come. The last project is the ATEX Express Marcellus ethane project that we announced in January. For Enterprise, this is a home run. It's a home run for the producers in the Marcellus and Utica, and it's a home run for the Gulf Coast petrochemical industry. Because we are going to use significant amounts of existing pipe, we're able to be competitive from both a cost and timing standpoint. And the project significantly increases the value of an existing asset for Enterprise. It adds substantial value to both the Marcellus and Utica producers and to the Gulf Coast petrochemicals as these volumes are key to both realizing their growth potential. The project integrates Marcellus Utica volumes into our NGL infrastructure at Mont Belvieu and all along the Gulf Coast. It provides Enterprise with what we believe is going to be very strategic access to some of the fastest-growing rich gas supplies in the country, and it creates a platform for us to seek and develop other opportunities in the Marcellus and Utica, similar to what we did in the Rockies once we acquired Mid-America. Last, let's touch a little bit on the ethane fundamentals. Now that a definitive large-scale solution for the Marcellus Utica ethane has been reached, there have been many "experts", and in my script that's in quotes, who are projecting an early and significant supply of ethane on the Gulf Coast. At Enterprise, we track supply-demand fundamentals, and I'm not going to ever jeopardize my credibility by saying that there won't be windows where ethane will be oversupplied, or for that matter, undersupplied. I will tell you that our models indicate that ethane is likely to stay in balance even after Marcellus comes in service. Personally, I think the petrochemical industry needs Marcellus to realize their potential. In a market this big, there's always variables on both the supply and demand side of the equation, each with numerous possibilities and timelines. These include things such as, how quickly the reserves can be developed and brought online, how quickly petrochemicals can do their new conversions and builds, turnarounds play a part and then how quickly new pipe will be filled. I can tell you, they won't be full on day one, and they're not contracted this way. This is a fact that many people miss. New pipelines are not full on the first day. For example, our Texas Express with a capacity of 280,000 barrels a day when it comes up, and our Marcellus with a capacity of 125,000 barrels a day will neither be full. This is -- there is typically a 3- to 5-year ramp up on these projects. Out of all the scenarios we run, even a very high production scenario, we don't show ethane being significantly oversupplied for any extended period of time, and we're talking months, not years. As an extreme, I asked our fundamentals group to model the remaining naphtha and gas oil cracking at a time when we are showing growing ethane use, and they found that the naphtha gas oil cracking was still 230,000 barrels a day of equivalent ethane demand. Now that's probably not likely to be converted, but it gives you an idea of the size of the headroom. I said before, don't underestimate petrochemical industry's ability to consume ethane. The economics are compelling to not only crack all the ethane they can, but as quickly as possible, and to position themselves to be able to crack substantial amounts more in the years to come. The wide gas to crude spreads that have been developing in the last few years, the installation of ethane flexibility has quickly moved from being a nicety to being an economic necessity. The answer lies in ethane's price advantage, and we continue to see the laws of supply and demand hard at work. Just last week, per our models, ethylene from ethane cost $0.20 a pound less than ethylene from naphtha. On a 1.5 billion pound a year plant, that is an annualized $300 million in margin. In addition, that ethylene made from that ethane is globally competitive, and the cost advantage has not and will not be ignored. Further, with ethane as this market's baseload feedstock, other opportunities present themselves. There's a greater appetite for reliable supplies for propylene and for butadiene, which is a positive for propane and butane, and there are growing exports for propane. In short, shale has given new opportunities for petrochemicals, refining, midstream and especially for Enterprise. At our company, we know our business. We understand our customers and their needs, both on the producing and consuming side, and we focus on market fundamentals for the long term. Frankly, we're very excited about where we are, and we're very excited about where we're going to the point that being a 66-year-old, I wish I was 50. And with that, I'll turn it over to Randy.

Thanks, Jim. I'll take a few minutes to review some additional income items and capitalization items. General and administrative costs decreased to $44 million in the fourth quarter of 2011 from $54 million in the fourth quarter of 2010, primarily due to transaction expenses related to our merger with Enterprise GP Holdings of approximately $11 million, which were included in G&A cost in the fourth quarter of 2010. Interest expense was $183 million this quarter compared to $213 million reported in the fourth quarter of 2010. Included in interest expense for the fourth quarter of 2010 was approximately $31 million of charges related to the merger with Enterprise GP Holdings, including charges associated with their interest rate swaps and the write-off of their unamortized debt issuance cost. Average debt balance for the fourth quarters of 2011 and 2010 were $15.1 billion and $13.8 billion, respectively. Capitalized interest increased by $18 million this quarter compared to the fourth quarter in 2010. Total capital expenditures were $1.1 billion this quarter, which included $1 billion for growth projects. Approximately 66% of growth capital expenditures this quarter were associated with the Haynesville and Eagle Ford Shale-related projects. As Mike mentioned earlier, we spent $3.6 billion on growth capital projects this year, primarily for fee-based pipeline and related projects in the Haynesville and the Eagle Ford Shale plays. Currently, we expect to invest approximately $3.5 billion in growth capital projects in 2012, approximately 40% of that expenditure related to the Eagle Ford Shale-related projects. Sustaining capital expenditures were $79 million in the fourth quarter of 2011 and $296 million for the entire year of 2011. In 2012, we expect to spend approximately $300 million to $325 million for sustaining CapEx. Adjusted EBITDA for the 12 months ended December 31, 2011, was $4 billion. Adjusted EBITDA is defined as EBITDA less equity earnings from unconsolidated affiliates plus actual cash distributions received from unconsolidated affiliates. Our consolidated leverage ratio of debt principal to adjusted EBITDA was 3.5x for 2011 after adjusting debt for 50% equity treatment of the hybrid securities. Our adjusted ratio of debt-to-EBITDA was 3.6x if you reduce adjusted EBITDA for the $156 million of noncash gains from the sale of assets recorded in 2011. Our floating interest rate exposure is approximately 8% of the total debt portfolio. The average debt life was 11 years using the first call date for the hybrids and a little over 16 years if you use the final maturity. Our effective average cost of debt was 5.6% with respect to the quarter. Since the beginning of 2011, we have made notable progress in evaluating our portfolio of assets. For those assets that are earning low rates of return on capital and not strategic long term. The 2 largest assets we have divested are approximately 32.4 million Energy Transfer Equity units and our Mississippi natural gas storage business. This includes the $825 million of ETE units that we settled on January 18. In total, we sold these assets for approximately $1.7 billion, which suggests we were earning an unlevered return on capital of approximately 7%. We believe our organic growth projects should generate higher returns on capital and generate incremental distributable cash flow without growing our balance sheet. For example, if you assume we can redeploy this capital at a 15% unlevered return, we could generate incremental Bcf equal to approximately 6.5% of our current annualized distribution rate of $2.48. Assuming a more modest 12.5% return on capital, the distributable cash flow accretion would be approximately 4.5% of our current distribution rate. It is unusual for an MLP to sell assets because they generally cannot afford to lose the associated distributable cash flow. Because of our healthy distribution coverage and a general partner without incentive distribution rights, we have this type of flexibility to high grade our assets, increase our distributable cash flow and the value of our partnership units. At December 31, 2011, we had consolidated liquidity of approximately $3.4 billion, which included availability under EPD's credit facility as well as unrestricted cash. Our consolidated liquidity at December 31 does not include the $825 million of proceeds from the sale of approximately 22.8 million Energy Transfer Equity units that closed on January 18, 2012. You add those 2 together, that's $4.3 billion. With that, we'll turn it over for questions.

Thank you, Randy. Christie, we're ready to take questions from the audience now.

[Operator Instructions] Your first question comes from the line of Brad Olsen at Tudor, Pickering.

Thanks for all the color on the kind of macro data points. I guess on the back of that, considering the fact that ATEX emerged from the fact that you guys were able, with your legacy assets, to deliver a low-cost solution for Marcellus supply -- ethane supply in the Marcellus, do you think that there's any potential long-term to use maybe a similar strategy to provide a propane takeaway solution out of the Marcellus?

As we look at the production growth up there in that area, I think it will be 5 to 7 years before the propane production will exceed the growth of demand. So what we're looking at short term is using the network of assets we have to feed the distribution system that's there. And then yes, down the road as production grows, we do have the capability of providing a solution back at Belvieu.

Okay, great. And I guess the long-term view that you guys provided notwithstanding, in last month, ethane pricing has softened pretty significantly. And just because you guys touch so many producers as well as consumers, do you have any thoughts about -- I guess is the warm winter up in the northeast displacing propane that would have otherwise gone up to PADD 1? And is that propane getting cracked on the Gulf Coast, or is there -- are there other factors that work in the kind of ethane softness that we've seen?

Having a hard time with the question. I mean, when we talk about softness, we've gone from phenomenal margins to just great margins. We've had quite a few turnarounds. We've lost probably 50,000 barrels a day. That's to be expected. We're still pretty excited. I don't know what it has to do with propane. I haven't seen a heck of a lot of, Tony, propane cracking. Or have we? Have we seen an increase?

Seen a slight increase but not really a great deal of it.

Slight increase, Tony says, but not a great deal.

Okay. And any numbers around that slight increase in propane cracking?

Not more than what, 30,000, 40,000 barrels a day?

About right.

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

So just 2 quick questions for me, Jim. With all the emphasis on moving white grade into Belvieu and the ATEX line moving more product into Belvieu, how do you guys think about the Conway to Belvieu spread for ethane widening over time, and more importantly, your position to increase that ability to capitalize on that regional arbitrage?

Well, that Texas Express, I'm going to look to Jim Collingsworth, but our Texas Express, in combination with our Mid-America Pipeline system, will have the ability to move Mid-Continent white grade into Mont Belvieu. Frankly, I don't think you can hold these spreads long term, so it's going to be piped in and built.

What I would add, Jim, what used to balance it was $0.035, and with the new tariffs all in, you're now looking at escalation over the next 3 or 4 years, you're up to $0.10 or $0.12.

Okay, did you get that Darren?

Yes, I did. It's just amazing to me because your Belvieu Conway ethane spread, your purity versus EP mix was up around $0.60 and which is fantastic. And like you said, you've gone from fantastic spreads, now it's around $0.30, but it's still pretty healthy and it seems like there would be an increasing opportunity for arbitrage because Conway could effectively be the marginal ethane spot. Would you agree with that, Jim?

I think it's the marginal ethane site.

Yes, yes. So just kind of thinking about that with the commitments on MAPL updated to 2005, you seem to have the volume to justify Texas Express expanding up close to that 400,000 mark and moving more product to Belvieu. And if that's the case, how do you think about additional volumes coming into Hobbs and the ability maybe to even move more product on either Seminole or Chaparral?

Chaparral are chock-a-block full today and have been for several years, so the only opportunity we've got to move additional volumes is Texas Express. And going from 280,000 to 400,000 barrels a day is a very cheap expansion and something can be done within 9 to 12 months.

Okay. And Jim, last question to me. As you look at what you guys are doing with the ATEX NGL line, how do you think about officially moving forward with that Gulf Coast ethane header system? I mean, it would seem to me like you've got all the places -- all the pieces of the puzzle in place to do so. And more importantly, the one piece that is lacking is the front end of the system. And in the spirit of being more vertically integrated, how do you guys think about establishing a gas gathering and processing footprint up in the Northeast?

We continue to push the ethane header system, frankly. It's going to be a function of what kind of support we get from petrochemicals. It seems to be growing legs in terms of the Northeast. You can bet your bottom dollar, we've always said, we don't build and buy what doesn't already fit us. Now it fits us, we're going to take a hard look at, can we develop a presence up there and gather good processing.

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

Congratulations on the credit ratings upgrades. On the -- with your cash flow mix, I think, around 70% fee-based and you have a lot of projects coming online over the next few years, where do you see your mix of fee-based versus margin-based cash flows around 2014 or so?

I think we've been around 70% fee-based and we see that growing to 75%.

Okay. On the Seaway and ECHO projects. First on Seaway, when in the second quarter do you estimate the 150,000 barrels to be online?

I think what we've most recently said trying to narrow it down was 1st of June, but again, if we can get in early, we will.

And then how is the ECHO terminal project coming along?

It's coming along great. We like what we see. We think we can -- I mean, we've got a vision of that being a hub, with probably 5 million barrels of storage.

And then in terms on the potential expansion to Seaway, about how much additional capacity could you add to this system, about 400,000 barrels?

Well, it depends on demand.

I'm going to ask Hurley. I think Mark, and I think I got a little confused with my script, on a WTI basis, that pipe will do 500,000 barrels a day?

The existing Seaway line will do 500,000 barrels a day on a WTI basis.

And on -- based on the contract mix we're looking at heavy to sweet, what are we looking at it's being able to move on that?

About in the mid-400s or so, roughly 2/3 sour, 1/3 sweet. But you asked about how much we can add. It really depends on what the demand is. We can add as much as the market needs, and I think we're sitting here in a great positioned to be able to add as much capacity as the Mid-Continent producers and the Canadian producers need for the next 10 to 20 years.

Is it public on the Flanagan to Cushing key piece, if that will be looped by Enbridge?

We didn’t know.

Let me put it like this. We got pipe in the ground in combination with our partner that can access Alberta, the Bakken and Cushing. The only thing we would need to expand in terms of looping, if we got enough interest, would be Seaway and we're fully prepared to do it.

And we can easily get to 1 million barrels a day of total capacity with -- if there's enough demand to support that. And if there's demand beyond that, we can take that volume higher.

Final question for me on the capitalized interest. Randy, is that expected to be somewhat a 2011 levels?

Yes, in 2012. I think 2011 level was around $100 million, and I think that's probably the same level for 2012.

Your next question comes from the line of Steven Maresca of Morgan Stanley.

In terms of the ATEX ethane line, are there issues different with moving ethane long term than -- long distances I mean, as opposed to moving other parts of the NGL, a barrel or other parts of the products? Just trying to figure out if there's -- what the hurdles are, if there are any, other than just essentially going through normal procedures of building the pipe?

No, there's not and we'd do it today.

The only difference is pump seals.

Pump seals, yes.

Okay. And Jim, thanks for the color on macro. Why does it seem -- you mentioned sort of the sky is falling predictions. It seemed to continue to come out, the debate rages on, and probably will continue to in terms of ethane and NGLs. What do you think the chemical companies are missing, or why are they keep talking about 20% to 50% drops in ethane? Is it certainly a bias on their part to talk like that or is there something you see that they're not seeing?

Steve, it's not the chemical companies. It's some reports coming out from chemical analysts that we think are missing some of the key factors. And I think every time Jim reads one of these, his blood pressure goes up.

But you have heard from CEOs at some of the chemical companies that have predicted ethane to go down. I mean, late last year, they thought ethane would go down 20% to 50% this year, I thought I read that and saw that a couple of places but...

Okay. In a full disclosure, I'm a retiree of the Dow Chemical Company, okay? And they're no different than anybody else. They talk their book. I was with my former friends not long ago in New York. And really, what I said to them was, "you know your real advantage on ethane, given the gas to crude? It's not about ethane being cheaper, it's about you being enabled, given -- it's a relative thing." And if I'm still there, what I'm focused on is, I want to be the guy that can use the most the quickest because that's where the advantage is. I think it took them awhile and rightfully so to really determine is this thing real? They bought into that full force right now and they're moving hard to expand.

Okay. Final question for me. Appreciate that you guys are in great financial shape and don't need equity relative to the plan for '12. Is that -- would that be a goal to get through the year with not issuing equity at EPD?

We've always said that we want to stay in front of our equity needs, and we're looking at 2012 and our capital spend and where we are in terms of liquidity and balance sheet. We're very comfortable that given our current expectation of capital spend, we don't need to issue equity. And so, we were certainly not intending to do anything before it's needed.

Your next question comes from the line of Ted Durbin of Goldman Sachs.

Yes, just following up on Steven's question there on the equity side. Is there -- can you tell us how much of the -- whether it's ETE asset sales or if it's just regular asset sales like the gas storage business, how much of that is actually baked into not needing equity? And then just comment a little bit about -- you said you've got the upgrades from the ratings agencies. They have you on a positive watch. Are you looking to get another notch upgrade on your ratings? Are you happy where you are?

Let me just talk about our equity expectations. Certainly, if we were issuing units of Energy Transfer Equity or selling those, then that's very similar to us issuing equity. As Randy said, if we can take assets whether it's storage or whether it's another third-party's common units that yield 7% and redeploy that in 15% projects, it's a win-win all over the place. And again that kind of upgrade certainly lessens the need for equity. Randy, do you want to talk about Fitch?

Yes. Again, very appreciative of the upgrades from S&P and Moody's. As you know, we still have a positive outlook there. And I think both noted that if we continue to execute and bring in projects on time, on budget, execute sort of on what we think we can earn on those projects, keep our credit metrics in good shape, then they'd see a window, what, 12 to 24 months out that we might see another upgrade. So I think we just need to run our race and continue to execute and let that play out. I know Mike mentioned Fitch. Fitch is still there at BBB-. I think they have also a positive outlook. I think they're in their cycle right now of doing their annual reviews also.

Okay, great. And then just on the distribution itself. It sounds like you're going to wait until some of the Eagle Ford projects and what not come online. Are you implicitly saying that you'll stay at the same growth rate that you have been on the last few quarters through 2012 until those come on? Or is there a chance that you might bump faster sooner?

No, we're not trying to imply that we're going to do anything. We've always said we look at it every quarter. But what we would say is that we've got extraordinarily strong distribution coverage, in part because our businesses are running on all cylinders, but in part we've had some asset sales that tend to distort the coverage ratio. We do have, as we said about $3.6 billion that we're going to spend this year and that's going to be capital that we're spending that's not going to be returning cash flow to us immediately, so we just need to manage through that construction cycle.

Got it. And then Jim, I appreciate the comments on ATEX and Texas Express, the volumes. Can you give us a sense of the actual ramp there? You said 3 to 5 years. Would you think of that as sort of a pro rata ramp in the volume? Is it back-end loaded? Any more detail you can give us there would be helpful.

No. We look at our IRRs, we look at our simple interest in the early -- simple return in the early years and that's how we make our decisions.

Ted, the producers are only pretty cautious about it. Certainly to sanction a project, we need some certainty of cash flow, and so there's some demand charges that we're counting on during that ramp up period. But whether the production is actually going to be there or not, we don't know.

Got it. But in other words, if the capacity is there, you can run spot barrels on those pipelines presumably even if you didn't have contract volumes coming on them?

But if there were spot barrels then those producers would probably stepping up to more capacity anyway. That's the good thing about those spot barrels. I think they're about -- the tariff's about $0.05 higher than the precedent [ph] rate, so that's not a bad thing.

Your next question comes from the line of John Tysseland of Citigroup.

Mike, just a follow-up on the distribution growth rate question. Any kind of clarity as to what metrics or specific kind of metrics you'll be looking at post -- let's say your CapEx spending slows down, although that's not really in sight at this point, continues to move up. But I mean, what will you be looking at and assessing in terms of -- to look at that growth rate? I mean, can you narrow it down a little bit from between coverage, fee-based cash flows, leverage and need for expansions? Any kind of more detail that you can provide and on the metrics that you'll be looking at?

John, it's kind of all of those, and I don't want to describe it as a black box, but it truly is looking at how our assets are performing given the current business cycle, looking at our needs for capital. We've got a lot of assets that are going to be going into service this year. Some of them about $1.7 billion in the first half of the year and then another big chunk in the fourth quarter. So we want to see how those perform, and make sure that our balance sheet stays where we want it to be. We're not planning on funding all of our capital with 100% retained distributable cash flow, but we do still think a piece of that makes sense. And as we look forward over 2012, just looking at the facts, we expect our distribution coverage to decline throughout the year until those projects come up. And so, we really want to see how those projects perform, look what the business climate appears to be for 2013 and what our CapEx is. You're right, it does appear that we were kind of on track to spend $3.5 billion or so a year on capital expenditures, and we certainly have the opportunities that we think that's probably going to be the case for 2013, although we haven't identified them. But that doesn't necessarily mean that we wouldn't consider an increase in the distribution rate.

That's great color. I mean, any kind of feeling or does your peers' cost of capital at all play into that decision where you have seen some of the midstream MLPs -- I mean, it is a pretty robust environment where they've ratcheted up their growth rate, and does that play at all into the mind of where your distribution growth is? Or is it -- are you really just looking internally?

We're not too much of followers, and we think that some of those bumps that you're hearing other MLPs talk about are because drop downs are doing and things that they really have to do because they don't have the same organic growth opportunities that we do. We're more of a consistent performer and we think that that's going to provide better returns for our unitholders over time.

Great. And then Jim, and I'm sorry, I dropped off right at the beginning of your comments and then dialed back in, but if you answered this or not, I don't know. But on the export -- on the propane export pipeline or export terminal expansion, when -- could you give me a quick update on when that comes online? And if -- once it does come online, we saw, I think, peak exports of about 175,000 barrels a day out of the U.S. What could that be once you get your propane, or the NGL export dock expansion up and running?

I'll let Lynn Bourdon answer this briefly. I like that briefly part.

We're still on track for completing the expansion sometime in late 2012, and we would anticipate with the capacity we have we could double the exports that we had based on the capacity we have. We'll see if the market will bear that as we go forward. But already, we have a significant number of contracts in place for 2012 and 2013, and we'll continue to add to those as the market is accepting of it.

On a barrels per day basis, because I know you guys look at it from a loading hour, I think barrels that you can load per hour. Any kind of clarity on what that means on a barrels per day basis, how meaningful this expansion will be?

Well, we'll be able to load at about 240,000 barrels a day when the expansion is up from a physical capacity standpoint. Rudy?

One of our constraints is going to be supply. We've got to produce the LE, low ethane propane, so one of the things that we're working on fairly significantly right now is making sure that we've got enough supply to maintain the ability to load at that rate.

And what we have I think is -- you really need a very strong fractionation complex to support exports of propane, and that's what kind of differentiates us.

So as we add our fracs, we put on frac-6, we're adding more capacity.

Is the demand still there that you're seeing currently or outside the U.S.?

We're sold out in '12 and we're pushing '13 pretty hard.

Your next question comes from the line of Yves Siegel of Credit Suisse.

Just several quick follow-ups on this call quick. Number one, Mike or Randy, do you have any additional assets that are not earning an appropriate rate that could be divestiture candidates?

Yves, we continue to look at our assets, and we may have some small, rather insignificant assets in the grand scheme of things. We do have some ETE units left. Looks like you're interested.

We can talk offline. But I guess I'm thinking, are you still committed to the Gulf of Mexico?

We think that the Gulf of Mexico certainly has had a step back with Macondo and with hurricanes prior to that. We think that the majors are really putting more emphasis into it now. We did announce our Lucius pipeline, and that one really is a nice asset where we think that the appropriate parties are bearing the appropriate risk. It's not one that we are putting a lot of money into right now, but we certainly don't think that this would a time to sell it. We think that that Gulf of Mexico area is on a rebound.

Okay, and then my final 2 questions would be, number one, for Mr. Teague, do you envision or are you still of the opinion that we won't see more downstream infrastructure get developed up here in the Northeast? I'm thinking maybe perhaps an ethylene cracker or -- any change in your thoughts there, given how much the -- how prolific the Marcellus and Utica may very well be?

It does seem like the place to build ethylene plants given all the infrastructure. And it goes beyond -- if you look at the Gulf Coast and you look at the ethylene, there's full connectivity on the front end, and there's full connectivity -- virtually full connectivity on the back end. It's a huge advantage.

And as you think about the NGL storage, the ethane storage that we've got on the Gulf coast, that's something that they don't have up there.

And then my last question, as you think about this growth capital cycle that you've been on, and clearly, you're getting much better visibility into 2013, do you have any sense of how long the growth, being at an elevated level, could go? Do you think you have good visibility into '14 and '15 in terms of thinking that you could be spending at this multibillion dollar rate?

I think certainly 2013 just given our existing projects. We said we've said, we've got $6.5 billion of projects under construction right now. We've got a few others that we're looking at that has not been announced, haven't been sanctioned, but could happen and if they do, they're more likely to be capital spend in 2013 and '14. If you look back over the last 6 or 7 years, 2009 was the only one that had a down tick in CapEx and that was because of our concerns about the financial markets, which proved not to be as big as an issue as we thought they might be. But I think one of the things to think about, Yves, is that with the ATEX pipeline, with the big assets that we're building in the Eagle Ford, we're really building a backbone that we can build off of and develop smaller, discrete projects that don't have the same kind of timeline, so we can develop them faster to get them producing cash faster, and I think it's just -- it means even more growth to the partnership.

Your next question comes from the line of John Edwards of Morgan Keegan.

Just on the ETE units, how many do you have left?

Sorry John, you're cutting out.

The ETE units, how many units do you have left?

We've got about 6.5 million.

Okay, great. And then I'm just wondering with all the construction, are you seeing any kind of inflation in labor and materials at this point or is it pretty benign?

There's been a slight increase. It's kind of been ramped up pretty steadily over the last couple of years. But I mean, we're still nowhere near we were in 2007, 2008 levels.

And I think a good thing to note is, as we've a couple of times during this conference call, we've been building assets and coming in under budget. So even though those costs have been reflected in the AFEs, we've been able to come in under budget.

Okay. And then are things staying on schedule? I mean, are you seeing any bottlenecks that would cause any slippage? Or do you feel really pretty comfortable with the construction schedules?

I think we feel pretty comfortable at this point, John.

Okay, great. And then just wondering are you looking at a frac-7?

I can look at a frac-12.

If we listen to our fractionation group, we'd have trains from Mont Belvieu to Beaumont.

Okay, all right. And then out of the $6.5 billion currently underway, how much or I guess, ongoing, I'm trying to figure out, I mean, if $3.5 billion budgeted for this year, I mean, how much of that $6.5 billion is built out? Is it just simple math on the $6.5 billion minus $3.5 billion or what's the right way to think about that?

Yes, John I think probably because some of that $6.5 billion was spent frankly in 2011, some is being spent in '12, some is being spent in '13. I mean, the tail on this may be a couple of billion dollars in 2013.

Okay. And then so now, what's the opportunity backlog you're looking at now?

As Carl Sagan would say, billions and billions. Seriously, we have a lot of opportunities. It's really a question of what makes the most sense for the partnership, and we've got a number of projects that literally could be several billion dollars' worth. It's just a question of what really makes sense at the end of the day and whether we can get the contract to support.

Okay. So the bottom line, you're really not seeing a fall off here in opportunities at all?

We've never been opportunity short. It's more trying to be disciplined in the way we spend our capital.

Your final question comes from the line of the TJ Schultz of RBC Capital Markets.

Any update on your ability to charge market-based rates on Seaway? And then assuming you obtain market-based, what's the timing for some of the discounted rates that you intend to honor? What period of time would you be able to set the rate at the market price for transportation?

This is Mark. First of all, we feel very good about our application and the way that we measure your ability to achieve market-based rates, so we think we have a very, very solid case. The timing on that, I think, is going to be into the second quarter with the way the process plays out. With respect to when we take -- start with the commitments that shippers already have on Seaway, those commitments officially start in the second quarter of 2013. There is a possibility they can be moved forward if all shippers unanimously feel they can meet those commitments. And so that's an issue that we're working right now.

Okay, great. I guess, Jim, just a kind of clarification on the naphtha cracking comment. 230,000 barrels a day of kind of ethane equivalent you said that was not likely to be converted. Just I guess some clarification there on what kind of headroom you imply that gives you or what are some of the reasons or limitations for that not to be converted?

Those crackers are integrated with the refineries so you have issues around what does a refiner do with that product that typically goes to the ethylene plant. The point is, within that complex, given the cost advantage, there's still economics to do things beyond what we're showing. That's the point of it. That's the point.

Thank you, TJ. Christie, if you would, would you give our listeners the replay information for the call today.

One moment please. Today's replay will be available beginning at 1 p.m. Eastern Time today through February 8, 2012, at midnight. To listen to the replay, please dial (800) 585-8367 or (404) 537-3406. Conference ID number for the replay is 34210737.

Thank you, Christie, and we'd like to thank everyone for listening in on the call today. And that ends our call. Thank you, and have a good day.

Thank you again for participating in today's conference call. You may now disconnect.