Enterprise Products Partners LP (EPD) 2011 Q3 法說會逐字稿

Good morning, my name is Dennis, and I will be your conference operator for today. At this time, I would like to welcome everyone to the Enterprise Products Partners third quarter 2011 earnings conference call. All lines have been placed on mute to prevent any background noise. After these speakers' remarks, there will be a question and answer session. (Operator Instructions) I will now turn the call over to Mr. Randy Burkhalter. Please go ahead, sir.

Thank you, Dennis. Good morning, all, and welcome to the Enterprise Products Partners conference call to discuss third quarter results. Our speakers today will be Mike Creel, President and CEO of Enterprise, and General Partner; followed by Jim Teague, Executive Vice President and Chief Operating Officer; and Randy Fowler, Executive Vice President and CFO as a General Partner of Enterprise. There are other members of our Senior Management Team 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, it 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 during this call. With that, I'll turn the call over to Mike.

Thanks Randy. First, I'd like to recognize the hard work by our employees in maintaining a safe workplace. The third quarter 2011 was Enterprise's best quarter ever for safety performance in our planned pipeline internal operations, with a total reportable incident rate of 0.52 for the quarter. We want to extend our personal thanks to all of the Enterprise employees, whose hard work and dedication to safety as a core value made this important milestone possible. Turning to our financial operating performance, we are pleased to report record results this quarter in terms of net income, adjusted EBITDA, gross operating margin, and distributable cash flow, surpassing the record results that we set last quarter, supported by growth in natural gas, NGL, and crude oil production in the shale regions, as well as improved NGL sales margins. Our integrated system continues to operate at record, or near record volumes.

Gross operating margin for the third quarter 2011 increased 20%, to a record $973 million, compared to $809 million for the third quarter of 2010. This led to record adjusted EBITDA of $956 million, and record net income of $480 million for the quarter. Our partnership generated record distributable cash flow of $856 million for the quarter, providing 1.7 times coverage of the increased cash distribution of $0.6125 per unit declared with respect to the quarter. Included in distributable cash flow was $190 million in net proceeds from the sale of 4.1 million energy transfer equity LP common units, and the sale of our Alabama intrastate pipeline system. Excluding these proceeds, our distribution coverage was still 1.3 times. We retained $341 million of distributable cash flow for the quarter, and $833 million for the first 9 months of the year, which represents 36% of the $2.3 billion of the distributable cash flow we generated. This retained cash is being used to fund our growth capital projects, and reduce our dependence on the capital markets.

Our NGL pipelines and services segment reported a gross operating margin of $548 million for the quarter, a 38% increase over the $397 million reported in the third quarter of last year. Included in gross operating margins this quarter is $3.7 million of proceeds from business interruption insurance. Our natural gas processing and related NGL marketing business benefited from continued strong demand for NGLs. Its higher NGL sales margins, and higher natural gas processing margins led to a $124 million increase in gross operating margin. Our Meeker gas plant operated at near full capacity this quarter, processing approximately 1.5 billion cubic feet day of unit gas volumes, resulting in a 96% increase in fee-based processing volumes, and a 7% increase in equity NGL production at Meeker. You'll recall that our pioneer plant was down a few weeks last quarter for plant modifications to further improve its ethane recoveries. As a result, Pioneer had an $18 million increase in gross operating margin for the third quarter, as it benefited from higher equity NGL volumes and processing margins.

Fee-based gas processing volumes increased 40%, to 3.8 billion cubic feet a day for the third quarter 2011, compared with 2.7 billion cubic feet a day for the third quarter of last year. Gross operating margin for our NGL pipelines and storage business increased $10 million to $146 million this quarter, primarily due to increased long-haul transportation at higher tariff rates on the Mid-America and Seminole pipeline systems, which reported a $15 million increase in gross operating margin. Total NGL pipeline volumes decreased slightly to 2.2 million barrels per day this quarter, compared to 2.3 million barrels per day for the third quarter of last year. We exported approximately 8 million barrels of propane this quarter, which is 12% less than the exports in the third quarter of 2010. A planned turnaround of our export terminal, which was completed in July, impacted our volumes early in the quarter, but since then lifting's have returned to full capacity, and we expect propane export volumes to be strong for the remainder of the year. In fact, we are sold out for the remainder of this year and next year for propane exports. Our export facility expansion is proceeding on schedule to increase capacity by 50% to 10,000 barrels per hour by the end of next year.

Shippers have executed 10 year shipper pay transportation agreements for the 50,000 barrels per day new capacity expansion of our Rocky Mountain leg of the Mid-America pipeline system. Those shippers have until the end of this year to exercise options to increase their commitments to 85,000 barrels per day, which we expect will happen, given the significant interest and new NGL take away capacity out of the Rockies. In the last few weeks, we have been announced open seasons for the Texas Express NGL pipeline, which is a joint venture with Anadarko and Enbridge (technical difficulties) to move mixed NGLs from the Granite Wash and Barnett regions to Mont Belvieu. The Marcellus ethane pipeline, with an initial capacity to move 125,000 barrels a day of ethane form the Marcellus and Utica regions to Mont Belvieu, and our existing Skelly-Belvieu NGL pipeline, which currently moves 27,000 barrels a day of purity NGLs to Mont Belvieu.

This morning we announced that we have secured long-term take-or-pay contracts for more than 75% of the initial capacity on the proposed Marcellus ethane pipeline. Ethane production from the Marcellus and Utica shale plays could ultimately have direct or indirect access to every ethylene plant in the US through connections at Mont Belvieu, and Jim will discuss these projects in more detail in just a few minutes. Our NGL fractionation business reported gross operating margin of $54 million for the quarter, a 42% increase over the $38 million reported in the third quarter of last year. This increase was largely attributable to our new frac 4 unit at Mont Belvieu, which began commercial operations during the fourth quarter of last year, and is running in excess of its nameplate capacity of 75,000 barrels a day. Our Norco and Hobbs fractionator also reported increased gross operating margin. Norco benefited from higher NGL sales margins and lower operating expenses, and our Hobbs fractionator had increased volumes at higher average fees.

Our fifth NGL fractionator at Mont Belvieu began commercial operations in October, and immediately began operating in excess of its nameplate capacity of 75,000 barrels a day. The new unit increases total fractionation nameplate capacity to 380,000 barrels a day in Mont Belvieu. Supported by long-term contracts, the new fractionator will accommodate increased NGL production from domestic shale plays. With producers announcing more discoveries of shale plays with NGL rich natural gas reserves, and petrochemical companies announcing more cracker conversions, expansions, and new builds, we have started construction on a sixth fractionator at Mont Belvieu, which is expected to be in service early in 2013. When this new facility is completed, we will have approximately 460,000 barrels a day of gross NGL fractionation capacity at Mont Belvieu, and more than 940,000 barrels a day of gross NGL fractionation capacity system wide.

Our onshore natural gas pipelines and services segment reported gross operating margin of $156 million for the third quarter of 2011, compared to $154 million for the third quarter of last year. Gross operating margin from the Texas intrastate system increased $15 million, primarily as a result of higher firm capacity reservation fee revenues, and increased interruptible transportation revenues. Gross operating margin from the State line gathering system increased by $3 million, primarily due to increased transportation volumes. We had a combined $10 million decrease in gross operating margin from the third quarter of last year on our San Juan and Jonah gathering systems, due to higher operating expenses and lower volumes. Total onshore natural gas pipeline volumes increased 6% to 12.4 trillion BTUs per day for the third quarter of this year.

Our largest capital project to date is the Haynesville extension of our Acadian gas pipeline system in Louisiana. This $1.5 billion pipeline is complete, and began commercial operations yesterday. Initially, it was scheduled to begin operations on September 1, however drilling and construction along the Atchafalaya River was delayed a little while, while flood waters from the Mississippi River receded. I'd like to congratulate our employees and contractors for a job well done in completing this project as soon as possible and under budget. We currently have 1.6 cubic feet a day of the 1.8 bcf a day of capacity subscribed under long-term contracts that are expected to generate approximately system $16 million a month in revenue from demand charges. Gross operating margin from the onshore crude oil pipelines and services segment increased 93% to $67 million for the third quarter this year, compared to $35 million for the third quarter of last year. We had increased throughput volumes on all of our onshore crude oil pipelines, except Seaway, which continues to be impacted by the lack of demand for northbound transportation to the over-supplied Cushing hub. Increased drilling activity in the Eagle Ford shale led to higher volumes on our South Texas system, while increased production in the Barnett shale benefited our Red River gathering system.

Crude oil marketing margins improved over the third quarter of last year, due to favorable crude differentials, and the integration of pipeline expansion projects in our lease purchase business which led to a 29% increase in volumes. We continue to develop the Wrangler pipeline project with Enbridge Inc. Subject to sufficient shipper commitments and regulatory approvals, the new pipeline would provide an outlet for more than 800,000 barrels a day of medium to light crude oil stranded at Cushing, and priced at a substantial discount to crude imports that are based on Brent prices. The open season for this project is scheduled to end this evening at 5 o'clock.

Excluding $8 million of insurance proceeds received in the third quarter of last year, our offshore pipelines and services segment had a $6 million decrease in gross operating margin, due in large part to the slowdown in permitting for exploration and production activity in the Gulf of Mexico, and maintenance at certain upstream platforms and producing wells during the third quarter of this year.

Naturally occurring production declines that have not been upset by new drilling contributed to $3 million decrease in gross operating margin, and a 12% reduction in volumes at our Independence hub platform and trail pipeline. We expect to receive additional volumes into the Independence and Cameron Highway pipelines in the fourth quarter of this year associated with the initial production from a new well and the restart of other wells that have been down for re-completion and facility maintenance. Gross operating margin from the petrochemical and refined products and services segment was $146 million this quarter, compared to $166 million for the same quarter last year. The propylene fractionation business had a $16 million decline from the very strong third quarter of 2002, due to lower volumes and sales margins. Propylene fractionation volumes were 4% lower this quarter, due to refinery turnarounds and planned maintenance activity, as well as new supply entering the market.

The refined products pipelines and services business had a $29 million decrease in gross operating margins, primarily due to higher maintenance and pipeline integrity expenses, as well as a decrease in refined products marketing sales margins. Pipeline volumes for the refined products pipelines were 5% lower for the quarter. As we said in our call last quarter, structural shifts in population, and refinery production in PADD 2 have led to a decline in demand for transportation of refined products from the Gold Coast to the Midwest. Also, several significant refinery expansions are coming online that are benefiting from cheaper WTI crude prices, leading to an increase in refined products production in the Midwest. Our octane enhancement business reported an 88% increase in gross operating margin to a record $39 million for the quarter, largely due to higher margins and increased volumes and contributions from the high purity Isobutylene plant that we acquired out of bankruptcy in November of last year.

We recently announced an increase in our quarterly cash distribution to $0.6125 per unit, or $2.45 on annualized basis. This is a 5.2% increase over the distribution declared with respect to third quarter of 2010. It is also a 29th consecutive quarterly distribution increase, and our 38th increase since our IPO in July, 1998. We are very pleased with the record results this quarter. Our businesses continue to benefit from the development of shell plays, the growing demand for NGLs and speed stocks by our petrochemical customers, and crude oil basis differentials. Our integrated, diversified asset base has served us well, and we have clear visibility to future growth drivers, with approximately $4.5 billion of energy infrastructure projects that are scheduled to be put in service between 2012 and 2014. With successful execution, the expected cash flow accretion from these projects should provide us support for future increases in our cash distributions to partners. Our success would not have been possible without the hard work and dedication of our employees. We applaud their efforts, and we remain excited about the many opportunities available to Enterprise. With that, I will turn the call over to Jim.

Thank you, Mike. I'd like to focus on a number of the major projects we have under construction, and give you some insights into a couple that we've recently announced. Suffice it to say that we remain disciplined in that we build or buy has to fit what we already have. So no matter where the project falls along our value chain, whether it be natural gas, NGLs, or crude oil, they have one thing in common, and that is, in addition to being good stand-alone investment opportunities, each has significant leverage too, and thus brings incremental long-term value far our existing portfolio. Assets linkage is a core principle that our Company was built on. It remains a key component of every investment we consider.

The Acadian Haynesville pipeline that Mike talked about is an example of these criteria. The pipeline is a great investment opportunity in and of itself, but furthermore it takes our legacy system in south Louisiana to a whole new level, because it makes the Haynesville shale gas resources readily available to that pipeline and to our customer base. The Acadian extension connects to 12 interstate pipelines, and terminates at our legacy Acadian system, where it serves over 1.5 bcf a day of industrial load in the Mississippi River corridor. There isn't another play in the country where the wells produce the amount of gas that producers are finding in these wells, and our Acadian system now originates in the sweet spot of the play, and can not only deliver into those interstate pipelines, but terminates at one of the largest industrial corridors in the US through our legacy system. In addition to the Haynesville extension, all of our natural gas liquids and crude oil projects in the Eagle Ford are at or ahead of schedule, and drilling and production in the play continues to exceed expectations.

Our Eagle Ford 30 inch and 36 inch rich gathering pipeline, our 900,000 a day processing facilities -- and incidentally we announced our third train just this week, our 127 mile Eagle Ford NGL pipeline to Mont Belvieu, and our 36 inch residue pipeline are all expected to be online by mid-2012. With over 3,500 drilling permits issued, 2,400 wells already drilled, approximately 200 rigs currently running, and 700 wells that are waiting on completion and-or infrastructure, our processing capacity is sold out, with firm long-term commitments, and frankly, our assets can't get up and running soon enough. As expected, in addition to rich natural gas, the Eagle Ford is quickly becoming a large crude oil play, and work also continues on schedule for Eagle Ford crude oil pipeline. Our pipeline project is being built in 2 phases, running 215 miles through the heart of the crude oil window, with an initial capacity of 350,000 barrels a day, and our network of terminals and storage along the pipe connecting to our new eco-terminal near Houston will have a total storage capacity of approximately 5 million barrels.

What is exciting, as more crude makes its way to the Gulf Coast, our eco-terminal can be expanded to accommodate up to 4.5 million barrels of crude tankage. Mike mentioned several other projects we have under construction, like our Mid-America Rocky Mountain expansion, frac 6, and our export facility. We are expanding our propylene splitter business to be able to produce an additional 500 million pounds of polymer grade propylene. Each and every one of these projects leverages our existing asset footprint, and brings additional value into our portfolio. We had 2 major JV projects we announced during the last quarter, the Texas Express NGL pipeline, and the Cushing to Gulf Coast crude oil pipeline. We believe these are lucrative opportunities that are best done with strategic partners, with each company bringing complementary pieces together, in order to make the opportunity a success. Like all the other investments, these projects are excellent stand-alone opportunities, but equally important, these projects link and leverage our midstream assets, bringing incremental value to enterprise.

We are excited about the Texas Express NGL pipeline, which currently has a binding open season underway, and is being built as a JV among Enterprise, Anadarko, and Enbridge. It has both gathering and transportation components for the growing plays of the Rockies, mid-continent, and West Texas, with each partner contributing attributes to the joint venture. But for Enterprise, this project adds incremental value to us by leveraging our existing Mid-America pipeline between Conway and Hobbs, and provides significant new volumes to her NGL infrastructure as at Mont Belvieu and along the Gulf Coast, feeding our fractionator's, our storage, and our distribution at work. In other words, our assets will feed this pipeline, and our assets will be fed by this pipeline. Then, there is the crude oil pipeline from Cushing to Houston with our partner, Enbridge. We believe this partnership brings the right combination of strengths, with Enbridge bringing strategic access to supplies north of Houston through existing pipe, and Enterprise bringing access to the US Gulf Coast refineries through our connectivity from our eco-terminal.

Again, in addition to being a great investment opportunity for both Enterprise and Enbridge, this project will bring the rapidly growing supplies of crude oil from Cushing and points north of Cushing to our eco crude oil terminal and pipeline system, combining access to the growing North America crude oil supplies with our ability to reach every Houston area refinery and the entire Gulf Coast refining market through our pipeline and marine connectivity. Finally, I want to discuss the ethylene pipeline project we have proposed from the Utica Marcellus to the Gulf Coast, for which we are currently conducting an open season. We have been laying the groundwork for this project for a while, and we believe new developments continue to point to the growing strategic importance of this project to both the Northeast producer community and Gulf Coast petrochemical. Producers not only continue to beat expectations in the Marcellus, but recently have also announced impressive acreage positions and drilling intentions for the nearby Utica, which is also expected to be rich in NGLs. On the demand side, petrochemical companies continue to be focused on significant expansions in the US because of the favored feed stock costs from growing shale reserves, primarily ethane.

We believe these Northeast NGLs are now key to realizing the growth potential for the Gulf Coast petrochemical industry. Our conservative estimates anticipate more than 400,000 barrels a day of incremental ethane needed for ethylene expansions, de-bottlenecks, conversions, and new builds over the next several years, with many of the expansions and conversions expected to occur over the next 12 to 36 months, as petrochemical are anxious to capitalize on the competitive advantage from domestic ethane. Our 1,230 mile pipeline will have an initial capacity of 125,000 a day, and because one half of this project utilizes the existing pipeline, the project is extremely competitive, from both a cost and timing perspective. We announced a -- we had a press release this morning announcing that Chesapeake and Enterprise had agreed to a transportation services agreement. We are not surprised that Chesapeake was the first to sign up, as they have been quite supportive of our projects in the Barnett, the Eagle Ford, the Haynesville, and where else was it? [Multiple speakers.]Everywhere.

We believe that market fundamentals continue to underpin support for US NGLs, especially ethane, which remains highly advantaged compared to other feed stocks. Like all of the other projects we have discussed today, not only would this project be strategic to producers in petrochemical, but it directly links into our infrastructure along the Gulf Coast, and will provide additional supplies and opportunities to Enterprise. In addition, it lays the groundwork for further extension of our integrated business model into the Marcellus and Utica plays, much the same way that acquiring the Mid-America pipeline system led to our building, gathering, and processing in the Piceance and the Jonah Pinedale fields that are now feeding our infrastructure of fractionation storage and distribution.

In closing, the US shale gas, and now shale oil, phenomenon continues, and, as you all know, the midstream industry is racing to keep pace. We will remain focused on developing systems and providing services necessary to satisfy the growing supply and demand sides of this equation. Suffice it to say, we focus on both sides of the supply and demand. We continue to find opportunities for capital, and expect that these growing volumes will add not only heads-up returns, but additional linkage to our entire portfolio. With that I will turn over to Randy.

Thank you, Jim. I would like to take a few minutes just to discuss some additional financial items. General administrative costs decreased to $50 million in the third quarter of 2011 from $70 million in the third quarter of 2010. G&A costs for the third quarter 2011 include $10 million of expenses related to the Duncan Energy Partners merger, which closed in September 2011, while G&A cost for the third quarter of 2010 included $14 million of expenses associated with the Enterprise-GP Holdings merger. Also included in G&A costs last year were approximately $20 million of charges related to the liquidation of certain employee partnerships in conjunction with the Enterprise-GP Holdings merger.

Interest expense was $189 million this quarter, compared to $192 million reported for the third quarter last year. Average debt balances for the third quarter of 2011 was $14.8 billion, versus the average debt balance for the third-quarter last year of $13.8 billion. As far as, in terms -- we take interest costs, and then we reduce that by capitalized interest to get to the interest expense, the capitalized interest member for the third quarter of 2011 was $33 million, compared to about $12.5 million for the third-quarter 2010. Year-to-date, that capitalized interest number spent is approximately $75 million, compared to $33.5 million for the third-quarter of 2010. We estimate capitalized interest for the full year will probably be about $110 million to $115 million higher than what was reported last year. In terms of provision for income taxes, it increased to $12 million from $5 million reported in the third quarter of last year, primarily due to higher accruals for the Texas margin tax, as a result of new assets placed into service in the state of Texas. Total capital expenditures were $1.1 billion this quarter, which included $989 million for growth projects. Approximately 86% of the growth capital expenditures this quarter were for the Haynesville and for the Eagle Ford shale related projects. Through the first 9 months of this year, we have spent $2.6 billion on growth capital projects, and we expect to invest approximately $3.7 billion in total in growth capital projects for 2011.

Sustaining capital expenditures were $81 million this quarter, and $218 million for the first nine months. We still expect to spend approximately $250 million to $275 million of sustaining capital for all of 2011. In terms of capitalization, adjusted EBITDA for the 12 months ended September 30, 2011 was $3.6 billion. Adjusted EBITDA is defined as EBITDA less equity earnings, plus the actual distributions received from unconsolidated affiliates. Our consolidated leverage ratio of debt principle to adjusted EBITDA was 4.0 times for the 12 months ended September 30, 201, and that is after adjusting the debt for 50% equity treatment for the hybrid securities. Our floating interest rate exposure was approximately 11% of the total debt portfolio. The average debt life was 11 years, if use the first call date for the hybrids. It is a little over 16 years if we use the final maturity for the hybrids, and our effective average cost of debt was 5.4%. In terms of liquidity, at September 30 we had consolidated liquidity of approximately $2.8 billion. That is cash on hand, as well as availability under EPD's credit facility.

In September, we closed on a new $3.5 billion, 5 year credit facility that replaced our old credit facility scheduled to mature in the fourth quarter of 2012. We had significant response from our banks. I want to say, total commitments from our bank succeeded $5 billion, and we actually upsized the size of the facility from $3.25 billion to $3.5 billion, and continue to be much appreciated of our bank group and the support they have given us over the years. We used a portion of the proceeds from the borrowings under the new facility to refinance the indebtedness under the credit facility that was outstanding, the prior credit facility at EPD, as well as refinancing the debt obligations at Duncan Energy Partners. At September 30, we had about $720 million outstanding under the new facility. With that, Randy, I think we are ready for questions.

Okay, Dennis, we are ready take questions from the audience now.

Thank you.

(Operator Instructions)

The first question comes from he line of Darren Horowitz with Raymond James.

Good morning guys. A couple questions. Jim, I want to go back to a comment that Mike made earlier on the MAPL expansion. If you guys get the commitments sufficient to increase capacity to 85,000 barrels a day, does it make sense for you guys to expand Hobbs' capacity? Or is the better option to move more y-grade maybe to Belvieu and maybe expand either Seminole or Chaparral, or possibly even lay another line right alongside?

It could, in fact make sense to expand Hobbs. We haven't decided yet, Darren. But that could be...

Okay. And the blue and the red line, though, Jim. They're running full, right?

Yes.

Okay. Shifting over to frac capacity at Belvieu, Jim, how much of frac 6 capacity is going to be driven by volumes that are currently being diverted to Louisiana?

Say that again, Darren.

The frac 6 capacity, how much of that capacity, do you think, is basically going to be by volumes that are currently running through your fracs in Louisiana.

I think most of it is going to be based on Yoakum, as we bring up the plants in Eagle Ford. There will be some that we are diverting. We're not diverting as much as we did. We will increase that flow through to Louisiana when the Eagle Ford plant comes on, but once that frac is up, we see Eagle Ford gas processed at Yoakum.

Okay. Here's kind of -- I was thinking about it, I think, the same way, Jim, because you all have 600,000 a day of processing capacity at Yoakum that's under construction. You've got that new 300,000 a day train, which is going to be online in the first quarter of 13, so you could make the case that the y-grade out of Yoakum's tailgate alone could support a frac 7. I don't want to put the horse too far ahead of the cart.

You sound like some of our guys on the sixteenth floor.

All right, last question for me, Jim, just kind of a big picture question, and you touched on it earlier, but when we are thinking about the supply demand balance for ethane going forward, if you don't factor in any of the new ethylene cracking capacity that could potentially be added, and you just focus on the additional light-end expansions and conversions of existing crackers, do you think that is enough to handle the incremental ethane supply that is going to be hitting the Gulf Coast?

I think what we have looked, and I'm going to look at Tony Chovanec to confirm it, but I think what we've looked at, if you look at all the announced de-bottlenecks, expansions and conversions, and you believe all of them, you're in the neighborhood of 150,000 or 155,000 barrels a day of incremental demand. So it's a lot of demand. Anything we bring in, for example, if we do this project out of the Marcellus, there is a ramp to that project, so it's not like all that product is hitting the market at the same time. So right now we are real comfortable in where we sit, frankly. I will go back to what we have said in the past, as a petrochemical industry, it's hard to pass on the cost of [technical difficulty] and ethane.

Sure. I appreciate the color, Jim. Thanks.

Your next question comes from the line of Bradley Olson with Tudor, Pickering, Holt.

Good morning, guys.

Good morning.

Some of your customers mentioned -- I'm sorry, some of your competitors mentioned there have been some NGL pipeline outages, specifically into Mt. Belvieu. You guys mentioned some pretty strong NGL pipeline results. How much of those strong results that you guys reported are related to one-time outages on other lines, or is it a more consistent trend than that?

Our pipelines have been running full, so there's been no impact at all on us.

Okay. So the kind of year-over-year increase in results from Seminole and Naple, that's unrelated?

It's unrelated to that. We do have a tariff increase every July.

Okay. So that is just a tariff increase. And I guess, qualitatively, if you guys would not mind talking a little bit, I know there has been a trend, especially in the Rockies, where you have been working out agreements with E&P operators to give them back some of the NGL exposure, and move some of those key pole contracts that you have had into more high fee type contracts structures, and I guess I was wondering how the dynamic between the really strong processing results that you guys reported this quarter, and the move towards a more fee-based structure, how should I think about those two dynamics?

I will take the first stab at it, and then let Jim jump in. Part of what is driving us to doing more fee-based deals is the fact that producers want the upside from the liquids. It doesn't make a whole lot of sense for them to be drilling rich gas and giving away all of the upside from the liquids.

That's the answer.

So, as far as, you guys mentioned a few individual items with Pioneer and Meeker, but what -- can you guys give a percentage of that kind of $120 million increase in the NGL processing business that's attributable just to higher equity NGL realizations for Enterprise?

Hi Brad, this is Randy. From an equity NGL production standpoint, we were actually less in the third quarter of 2011 than we were in the third quarter of 2010 --

I guess that was kind of what I was getting at. With such a strong increase, seeing the equity volumes decline, is the offsetting factor just much higher price realizations on a per barrel basis?

I think between processing margins, the effect as far as NGL prices on equity NGL production, and then, frankly, the NGL gross operating margin from a huge increase in fee-based processing.

Okay. Just one more, I think this is probably a question for Jim. As far as the propylene splitter expansion, I think just in the last couple months or so, propylene prices have fallen off pretty hard. Maybe you guys could talk just a little bit about some of the factors that have led to that, and how that affects how you are thinking about the splitter expansion, if it affects it.

Well, it's not going to affect the splitter expansion. Yes, propylene prices have fallen, but the margin between refinery grade and polymer grade continues to be strong. So what we're focused on is the margin, rather than the absolute. Chris am I on base? And that will be on in the first quarter of next year, 2013.

Great. Thanks a lot, guys.

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

Good morning.

Good morning, Brian.

On the Marcellus ethane pipeline, can you give us a little color on the Chesapeakes contract? You mentioned that it ramps up over a 5 year period.

I don't think we want to get into much more than we had in the press release today.

Okay. Can you just comment a little bit, then, on discussions with shippers for remaining capacity?

Probably not.

Okay.

We do have an open season. And a good chunk of that capacity is already spoken for.

Fair enough. Another easy question. On Seeway, can you discuss how discussions are going with Conoco?

What we can say is that Conoco has already publicly stated that they are in discussions with us, and we can confirm that, but beyond that we don't have whole a lot to say. I'm not sure what is going to happen and when. Meanwhile, we will continue to work on the Wrangler pipeline.

Okay. Following the sale of your gas storage business, are there other assets you are looking to divest to redeploy capital to your CapEx program?

Important to note, we only sold one part of our gas storage business, the Petal gas storage facility, and frankly, it fit Boardwalk much better than it did us. It wasn't connected to the rest of our system. We continue to look at our assets to see what makes sense for us to keep, and frankly, most of our assets, we really like. We have sold Alabama Intrastate gathering system this past quarter. So Petal, we expect that to close here in the fourth quarter, but beyond that there is nothing significant that we are looking at.

Given the many projects you have announced recently, and your existing projects, what is your view of 2012 expansion CapEx?

We talked about the amount of projects that we expect to go into service between 2012 and 2014, and as you can guess, we've got a fairly healthy capital budget for all of 2012 and 13 in 2014 we're actually looking at more projects. So I think if you look at our capital spending for the last couple of years, it is probably indicative of what we will do next year.

Given the significant amount of spending, probably another billion or so left in 2011, and a few billion in 2012, what are your thoughts about equity financing?

You look at the amount capital that we have spent this year on growth projects, and our financial metrics coming out of the third quarter at 4.0 times debt to EBITDA, and also consider that the Haynesville project, a $1.5 billion project, just went in to service yesterday, and it will start generating $16 million a month in demand charges, we have done all of that with no equity issuances this year. So, to me, it looks like we are in pretty good shape.

Brian, just to add to what Mike said, I guess as far as an asset that we would consider selling, obviously we still have 30 million ETV units, And that's also been able to come in and, frankly, keep us out of the equity markets by coming in and selling some of those holdings. We have been deliberate the way we have been selling those units. We will continue to be deliberate in the way we do that, but that's also given us a lot of financial flexibility.

Brian, so far this year we've sold about 9.1 million energy transfer equity units for proceeds of about $354 million.

Thanks for the color.

Your next question is from the line of Stephen Maresca with Morgan Stanley.

Hi. Good morning, everybody.

Good morning.

My question, a couple of questions actually. First around the Marcellus and ethane, and I want to make sure I heard this right, Jim, you said, 400,000 barrels a day needed of ethylene expansions over the next 12 to 36 months, that is what you guys said you had in your forecast. I guess if I heard that correctly, how confident are you guys in this, is this visible things that are already are in process from the petchems, and then as a subset to that, can you think of how much ethane ultimately comes down to the Gulf Coast from the Northeast, above and beyond your project?

Let's let Tony answer the first part of that question.

The 400,000 barrels a day is between now and, call it, 2015 or 2016. Not over the next 12 to 36 months. So there is a smaller number that industry has announced and that we massage to project over the next 12 to 36 months, but that is a member we think is going to come, call it by the 2015 time frame.

What Tony has in his numbers, and they track this pretty closely, and, hell, by definition it's probably wrong, but they are the right direction. 400,000, what I had in the comments is less than what he wanted me to put in there. But what that includes, it does not include all of the announced new builds. I think it includes 2 ethylene plants, so it is the de-bottlenecks, it is the conversions, it is the expansions, for example, I think Dow has announced they're going to bring the St. Charles plant back on, and it assumes, I will go back to, if you don't have any new builds, you are still looking at 150,000-160,000 barrels a day of incremental needs, given those expansions and de-bottlenecks. In the terms of your question, as to how much we can expect to bring down from the Marcellus and the Utica, I am not sure we have a clue at this point. Our pipeline can do up to 150, 160 fairly easily, with power and looping it can get up close to 200. I think what is exciting for us, in addition to the pipe itself, is go back to what I said, when we bought Mid-America, it led to the Piceance, Jonah, Pinedale, Meeker, and Pioneer and we are in a position, if we're able to do this project, we are in a position to leverage that further upstream, because it fits what we have now.

Okay. Thanks for that. On the cost for this ethane project with Chesapeake, is there any ballpark that you can give in terms of, as it is stated now, what it would cost you guys?

Steve, we are early in this. We haven't done engineering work yet to get comfortable with announcing a number, but frankly we have got a lot of the pipe that we are just going to be reversing, so as Jim said in his comments, it is going to be very economical.

Okay. Finally, from me, how should we be thinking about return rates on capital employed for some of these new projects, like potentially Wrangler, but like this ethane project that you are doing with Chesapeake, are these things now incrementally more than projects have been in the past, given the need from producers to have infrastructure built?

I think the way you ought to look at it is, first of all, it is going to be demand charge driven, so we are not going to be held hostage to the vagrancy of the market. It is going to pay a regular monthly fee. The returns are going to be, depending on how you look at it, they're going to be attractive, and I can't tell you what that number is. If you look at the Marcellus pipeline, and you recognize that part of that is already in refined product service, the way we look at it is, we are going to take that out of refined product service, so there is a certain amount of revenue that we are going to lose associated with that business that we're going to pick up on ethane, so it gets a little bit complicated. The other thing, take a Wrangler where for example, we might be targeting a certain rate of return, but what we have seen this year, and frankly for the last, probably, couple of years, we have consistently seen projects coming in under budget, so while we might be targeting for that kind of a pipeline a mid-teen kind of return, it might be more or less depending on where we actually come out with the spending.

The other thing is when we look at our returns, we look at them differently if they are demandly supported, and then as they support our downstream infrastructure, so we look at it in the context of the total.

Okay. Thanks a lot everybody.

Your next question is from the line of Jeremy Tonet with JP Morgan.

Good morning, and congratulations on the quarter.

Thank you, Jeremy.

Most of my questions have been answered, but I want to follow up on Wrangler a little bit. If you are successful in acquiring Conoco's interest in Seeway, does that impact your approach to the Wrangler project?

Timing is everything. We are committed to working with Enbridge on a solution, and it may be that if Conoco is serious and they move quickly at a price makes sense, maybe it impacts Wrangler. It is hard to tell right now.

Okay great. Thank you.

Your next question is from the line of John Tysseland with Citigroup.

Good morning. Given your excess cash flows, balance sheet, and extensive expansion projects, I know this question comes around a lot, and I will be clear with where I am going with it, but how do you think about acquisitions in the current environment? And where I am heading with this is really, in particular, if you look at the ethane pipeline out at Marcellus, if that moves forward, do you think there's an opportunity to either acquire or build processing in that region?

I think the answer is yes. But I think our tendency has been towards building. Acquisitions still are very pricey these days, and there is still a lot of MLPs that doesn't appear to have much way to grow, other than to acquire assets by building. We have a little more control over where that product goes and how it ties into our system, and how we continue to create that value chain.

If you buy somebody, there is invariably something that you can't use or have to get rid of. We like building.

Okay and then the second question, just as a follow-up to Darren's line of questioning on the Eagle Ford, you have a bunch of stuff coming online, the Yoakum plant, NGL pipeline, and a crude pipeline. How do you think about the ramp up of volumes behind those assets as they come online, or should we expect them to be a gradual, or is there just a lot of volume they are going to be running full when you get them online?

This is Mark Hurley, it will be gradual following the production curves of the producers in the area. We expect these volumes to peak in about the 2014 to 15 to 16 range depending on how aggressive the producers are.

Great. Helpful. Thank you.

He is speaking to the crude oil. Tom, from a natural gas point of view?

This is Tom Zulim. From the gas side, once our new processing plants come on at Yoakum, they will be full immediately, because if you remember how we operate our system in South Texas, it's all interconnected between the existing 7 and the new gas processing facilities. So those will be full with new Eagle Ford gas, and to the extent that it is not full with Eagle Ford gas, we will simply move gas from other areas to fill up the newer, more efficient Yoakum processing plant, so Yoakum will be full either way from day 1.

And the reason for that is you get incremental ethane, about 20%, 25% if I'm not mistaken, so you'll preferentially want to fill Yoakum.

And John, on the crude side there will be a ramp up, there is a significant amount of crude that's being gathered by truck now, simply because the pipeline capacity is not there, so that will all move into the pipeline right away.

Back on -- clarifying question on the Yoakum plant, what would you expect your NGL yields per MCF to go from and to on a GPM basis?

With the kind of GPM we are seeing out of Eagle Ford on a 300 day plant, you're going to see between 30,000 and 35,000 barrels a day of y-grade coming out of the 300 plant.

Great. Thank you.

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

Thank you. Good morning, everybody.

Good morning, Yves.

Could you speak to how the nature of the cash flows are changing, I guess the question is, do you have a sense of how much of the cash flow now is fee-based, and drilling even a little bit further down, when you think about the processing plants, what percentages of proceeds versus now being fee-based?

I think from a total company standpoint, probably 2010, we were probably 70% fee-based in nature, when you looked at gross operating margins. I think with Haynesville coming, and some of the other fee-based pipelines coming up out of the Eagle Ford, that probably gets us into the -- and also the new fee-based revenues coming from the processing plants, I think that probably gets us around 75%. You remember, we just got a big gross operating margin number to move, but again, probably mid-70% range, maybe ticking up 76%, 77%.

The last number you gave was what? How much you thought was -- 67, what was the last number and what was the context? I'm sorry.

As we bring on more fee-based assets, you might, my guess is, with Haynesville coming on, and the Eagle Ford projects coming on, you'd probably see us trend that gross operating margin would be comprised of about 75% of fee-based in nature. With some of the other announcements that we've got, that could bring it up to 76% or 77%, but it is going to take us a little bit of time to get all those assets on.

Having said what you just said, does that change the nature at all, in terms of how you think about financing going forward, how you think about, perhaps, the distribution policy going forward?

Let me get the distribution part out of the way, and then Randy can pick up on the rest of it. We have been very conservative in the way that we manage our distributions, and we recognize that NGL margins are pretty wide right now. We are in the midst of another year of heavy construction. As we have always said, we think it makes sense for our unitholders long-term if we take a portion of our distributable cash flow and reinvest in assets that generate even more cash, so that we can consistently increase distributions going forward. Having said that, if you look at our distribution coverage this quarter at 1.7 times, recognize that part of that is the sale of energy transfer equity units. We also, again, are in a pretty strong business environment, and we have had some projects come in under budget, which means we have less capital going out the door. So, on a more normalized basis, you'd look at that distribution coverage as being more like 1.3 times. We'll continue to look at that every quarter and see if further distribution increases are warranted beyond what we have done historically, but we are going to be very careful about the way we do that. Randy, do you want to talk just a little bit about the investment grade metrics?

Yes. Yves, as far as, given the scale, the size that we are, given more of the fee-based nature of the business, given the new projects with more demand charges, and I think, frankly, getting some of the larger projects -- Haynesville was a big step, that was our largest single project at $1.5 billion. All of these Eagle Ford projects that we are talking about? That's really about 20 or 25 smaller projects that are all very doable. As we come in and get those in service, I think you continue to look at Enterprise and, at least with our debt holders are telling us, what the market is telling us by where our credit spreads are, they are derisking Enterprise, as far as coming in and looking at the credit spread, and at some point you would think that would manifest itself with the ratings that we have with the agencies, too, but at least that is what the market is telling us. Also when you look at the way -- our debt financing is longer-term in nature. We're not relying on --it probably cost us some money, but we are not relying on a 0% fed funds rate going forward. The federal funds rate, if it ever comes up, our debt portfolio is in pretty good shape as the way we have been financing the assets.

Great answer, thank you, and the last question, the big picture for Jim, if you would, given the proliferation of liquids, could you see a change in the dynamics, and we have gone through this dance before in terms of maybe building fractionation and maybe even ethylene plants up in the Northeast, especially if you think the Utica is going to play out, and maybe you can put that into context of the ethane header that you have been talking about.

I'm not sure I know what to expect long-term from the Utica and Marcellus, because it just seems to grow more every time we look at it. I guess all things are possible. Personally, I think you want to take your product to the biggest sponge in the market, and that's the US Gulf Coast, and that's why we're looking at creating a system that will support the crackers down here. I have seen one party talk about building a cracker in Marcellus. Everybody else, they are talking about the Gulf Coast, and I expect that's where it will be built. I think he Marcellus liquids are being attracted to the Gulf Coast instead of being pushed to the Gulf Coast, and by that I mean there's an appetite for it. I think it is required rather than a disposal issue.

Thank you.

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

How are you doing, guys? Congratulations on this new ethane line. I wanted to ask this, generally speaking, this is obviously NGLs, here, but maybe Jim, if you could comment on how you think some of the crude might be dealt with out of the Utica. Thanks.

Have you got a clue, Mark?

We are working on that now. I think the question is, how much will leave the area versus how much will remain and be consumed by the refining network up there, and that is the $64 question, so that is what we are working now. Certainly it is a very bullish play, so we are looking for opportunities to move it out of that area if there is a need to.

Okay. Thanks very much.

Your next question is from the line of Michael Blum, also with Wells Fargo.

Thanks. Good morning, everyone. Just a couple of quick ones, I guess. First, just a point of clarification, Mike, did you say on the new ethane line that you've got 75% of the capacity committed, or just the 75,000 barrels of the 125,000 from Chesapeake?

Up to 75,000 barrels a day.

Okay. Just turning to Wrangler for one second. Just trying to think about it how you guys are thinking about it, when you do your analysis of Seeway reverse versus Wrangler, are you assuming within that context that Keystone does get built definitively?

Frankly, we don't know what is going to happen with Keystone, they have got their hands full in Nebraska and other places. We are simply looking at what shippers are willing to commit to.

Okay. Last question for me, on the propane export facility, can you provide an update on where you are from a contractual standpoint, how far out that is now, and where demand is coming from and how that looks, and where the cargo is going?

We are sold out through next year. We have sales. We are doing contracts in to 2013. And most of it goes into the South America area, but there is some that goes to Northwest Europe and Far East occasionally.

Okay. Great, thank you very much.

(Operator Instructions)

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

Good morning, everybody.

Good morning.

Michael's question was reminding me, on the propane export volumes, what are they now? And with the expansion, what do you expect those to be going to?

It really boils down to how much supply you can generate, because what you export is 98% propane, instead of the HD 5 domestic that is about 95%, so what you're going to be able to export is a function of what you can produce, that's an added benefit of our fractionators and our PP splitters, and I think we are in the neighborhood of being able to produce 150,000 barrels a day of export quality propane, and I think that is going to dictate what our capacity is. It's what you produce, not necessarily. In terms of our loading rate, what we are looking at is being able to capture the right time of the month as to when we do export, and that is a pricing issue that we can talk about off-line. But we are looking at being able to produce about 150,000 barrels a day of export quality propane.

Okay. Randy, you were talking about the fee-based moving to 76% or 77%. I guess in terms of looking forward, around 2013, do you expect to hit 80% fee-based by then?

John, I think 76% or 77% is probably 2013.

John, looking forward you can see that the new projects we are building are all fee-based, and the legacy contract that has the key poles, those volumes are declining, so that is going to naturally represent a smaller piece of our business.

Thanks for that clarification, there. I guess, Jim, if you can comment, in terms of the supply and demand dynamic in liquids, where do you see kind of an oversupply bump coming into the market, or do you see it staying relatively balanced each year through 2015 or so, if you can comment on that?

I don't want to get into too much detail as to what we are doing, but we see several opportunities created by petrochemicals preparing ethane and additional supply, and we are working those opportunities. Frankly, at this point, I really don't see a situation where we are going to be supply long relative to demand.

Okay. So you see it staying relatively balanced each year over the next few years.

Yes, and a lot of that is due to the ramp of the production. If it all hit at once, yes you may have a window, but that is not how it is going to be.

Okay great. I was curious -- I apologize I did not get a chance to read it if you said it in the press release this morning, on Chesapeake committing, is that commitment on this proposed line, is that enough to be able to go forward with it or do you have to secure additional commitments?

We are in discussions with several others. Our open season ends on the 10th, and I think we will know by the 10th whether or not we have enough.

Okay. By the 10th you will know if you can go forward on that.

Yes.

All right. And then, okay. On the Eagle Ford shale, I am curious now, what is your outlook? Somebody mentioned that it was going to peak somewhere 2014 to 16, what is the outlook now for oil and gas production coming out of that area? What is your best guess as to where things, where are we now, and where is it going to in the next few years?

I'm going to look to Tom, but every time I turn around they are bringing a new train, because they oversold the ones we're building. So we have announced 900 million a day of processing, and I think we are sold out, and they keep hustling more business. Our system down there is absolutely chocker block full. In fact, our people have to meet every morning and talk about how we are going to handle the gas, how we are going to handle the liquids, and it's more than we expected at this point, and there doesn't seem to be an end to it.

It's just lined up in the queue. Robust.

From a crude perspective, I think Mike hit it, we have got a lot of trucks working down there, and I think whenever the first phase comes on, we have got strong contracts to support that phase. I think it will be a little bit of a ramp, but I think we are doing some things that we're going to realize more value out of that crude, down the road, without getting into it.

Can you venture a guess on what the barrels per day, where you think it is now, and where you think it is going to?

This is Mark Hurley. We see it today at around 200,000 to 250,000 barrels a day, and we see it peaking probably around 750,000 to 800,000 barrels a day, but there are cases where it can go higher than that.

John, these are based on what we know today, and it seems like every month, every quarter, some new discovery or new technique for getting the stuff out of the ground, it is a hard thing to anticipate.

Okay. On this Yoakum announcement, I can't even keep track of all of your announcements, the Yoakum, with this addition here, would that imply that the 600 million cubic feet a day is completely sold out, because you were talking about adding 300 more, and also, if you can give us any numbers with respect to costs. And then also, on NGL production, I guess, before and after the addition on that.

The 600 is fully subscribed. The 900 is virtually there. I mentioned earlier, on the type of GPM we are seeing from the Eagle Ford today, the richness of that gas, you can expect to have upwards of 35,000 barrels a day of y-grade production out of each of the 300 trains.

Okay great thank you very much, that is all I had.

Dennis, if you would, could you give our audience the replay information for the call today? Thank you.

Yes, sir. Ladies and gentlemen, thank you for joining today's call. Today's call will be available for replay beginning 2 hours from now, and running for 1 week, through November 9, 2011 at midnight. The number to dial is 1-800-585-8367, or 855-859-2056, or internationally, 404-537-3406. The conference ID number for the replay is 20604091. This does conclude today's call. You may now disconnect. Thank you.

Thank you, Dennis and thank you for joining us today. Goodbye.