Enterprise Products Partners LP (EPD) 2009 Q2 法說會逐字稿

Welcome. Thank you for standing by. At this time, all participants are in a listen-only mode. (Operator Instructions). Today's call is being recorded. If you have any objections, you may disconnect at this time. I will now turn the call over to Mr. Randy Burkhalter. You may begin.

Thank you Lexi. Good morning and welcome to the Enterprise Products Partners and Duncan Energy Partners conference call to discuss second-quarter earnings. Mike Creel, President and CEO of Enterprise and [General Partners] will begin the call. He will be followed by Randy Fowler, Executive Vice President and CFO; and Hank Bachmann, President and CEO of Duncan Energy Partners, [General Partner] who will discuss second-quarter results for Duncan Energy Partners.

Also in attendance for the call today are Jim Teague, our Executive Vice President and Chief Commercial Officer and other members of our senior management team. Afterward, we will open the call up your questions.

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 my and information currently available to Enterprise's management. 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 will turn the call over to Mike.

Good morning and thank you for joining us today. We are pleased to report another quarter of strong results supported by record natural gas pipeline throughput of 9.7 trillion BTUs per day and near record pipeline volumes of 2.2 million barrels per day of NGLs, crude oil and petrochemicals.

In addition to the record pipeline volumes, some of the highlights of the second quarter 2009 include a $44 million increase in gross operating margin from the Independence Hub and Trail, which averaged throughput of approximately 891 billion BTUs per day in the second quarter and an 11% or $36 million increase in gross operating margin from our NGL Pipelines & Services segment on record NGL fractionation volumes and equity NGL production.

We generated distributable cash flow of $328 million in the second quarter of 2009 which provided 1.1 times coverage of the distributions declared with respect to the second quarter and enabled us to retain $34 million of excess distributable cash flow. This quarterly distributable cash flow was negatively impacted by approximately $12 million for estimated lost business as a result of Hurricanes Gustav and Ike and $4 million of merger related expenses from the pending Enterprise TEPPCO combination.

Year to date we retained approximately $90 million or 13% of our distributable cash flow while providing an impressive 1.2 times coverage of the distributions paid with respect to the first half of the year. The Board declared a quarterly cash distribution of $0.545 per unit for the second quarter which is 6% higher than the second quarter 2008 and is our 20th consecutive quarterly distribution increase.

We are pleased to be able to continue our record of increasing the quarterly cash distributions in these difficult economic times and challenging business environment. We reported net income of $187 million or $0.32 per unit on a fully diluted basis for the second quarter 2009 compared to our record high $263 million or $0.52 per unit in the second quarter of 2008.

Net income for the quarter was impacted by an estimated $38 million or $0.08 per unit for nonrecurring charges from the forfeiture of our investment in the offshore [oil port] and merger related expenses. Estimated lost business due to the hurricanes reduced income by another $12 million or $0.03 per unit.

Gross operating margin which was reduced by $34 million for the non-cash charge related to the forfeiture of our investment in the oil port and $12 million for the hurricane effects was $509 million for the second quarter compared to $534 million for the second quarter of last year which was the second-highest in our Partnership's history.

Adjusted EBITDA which was reduced by $4 million for merger related G&A expenses in addition to the $46 million of nonrecurring items that affected gross operating margin was $505 million this quarter versus $514 million for the same quarter of last year. Now, I would like to take a few minutes to review the performance of our business segments for the second quarter.

As I mentioned earlier, our NGL Pipelines & Services segment performed very well this quarter, reporting gross operating margin of $354 million compared to $318 million reported in the second quarter of last year. All three businesses in this segment reported higher gross operating margin with the largest increase coming from our natural gas processing business.

Gross operating margin from this business increased 12% to $219 million compared with $196 million in the second quarter of 2008. The majority of the improvement was from our NGL marketing activities at the Meeker and Pioneer natural gas processing plants. Higher sales margins provided in part by our hedging activities together with increased equity NGL production from these plants and our Louisiana gas processing plants were the primary reasons for the increase in gross operating margins.

We currently have approximately 70% of our Rockies equity NGL production for the remainder of 2009 hedged at a margin of approximately $0.63 per gallon. The margin is a difference between the prices at which we sold our NGLs forward less the natural gas cost of the shrink.

We have also hedged approximately 55% of our equity NGL production from percent of proceeds contracts, mainly propane and the heavier NGLs at a price of approximately $1.60 per gallon. We have not executed any natural gas processing hedges for 2010 but continue to evaluate opportunities to do so.

Meanwhile current ethane processing margins in the Rockies remained as attractive at over $0.20 per gallon, supported by strong demand for ethane by the petrochemicals industry as an alternative to more expensive crude oil derivatives. US ethylene production for the second quarter 2009 rebounded to an annualized rate of 50.5 billion pounds and consumed an average of 834,000 barrels per day of ethane per data published by the Hodgson Report.

This compares to an annualized ethylene production rate of 54.8 billion pounds and ethane consumption of 812,000 barrels per day in the second quarter of 2008. Currently the ethylene industry is expected to operate an annual rate of about 49 billion pounds and consume approximately 820,000 barrels per day of ethane. This is a marked improvement over the 34 billion pound annual operating rate in December of last year.

Industry ethylene cracking will be reduced by 2 billion pounds per year as two ethylene facilities are slated for permanent closure. Despite these closures, we continue to see good demand from ethylene crackers for NGL feedstocks as opposed to costly crude oil derivatives. Ethane and propane remain the preferred ethylene feedstocks.

A number of traditional heavy crackers are considering making modifications or are in the process of modifying their facilities to enable them to have the flexibility to consume natural gas liquid feedstocks. With our integrated NGL fractionation storage and distribution system, we believe this will lead to new business opportunities for us.

Gross operating margin from our NGL pipelines and storage business increased by 4% to $98 million this quarter primarily due to higher storage fees and volumes at Mont Belvieu, increased export volumes and lower fuel costs. Partially offsetting this quarter-to-quarter increase in gross operating margin were higher pipeline integrity expenses on our Dixie pipeline and lower transportation margins on our Mid-America pipeline.

In what is normally not a seasonally strong quarter for NGL exports, we have a significant increase in the volumes of NGLs exported and we expect to continue to see this for the remainder of this year and for most of 2010. Gross operating margin from our NGL fractionation business increased to $37 million in the second quarter of 2009 from $27 million in the second quarter of last year due to record fractionation volumes this quarter.

As evidence of strong demand for fractionation in the industry, our Hobbs facility which was put into service just two years ago and our fractionators at Mont Belvieu are running at full capacity. With this trend expected to continue, there's a strong possibility that we could announce new projects to expand our fractionation capacity along the Gulf Coast.

Our Onshore Natural Gas Pipelines & Services segment reported gross operating margin of $74 million for the quarter compared to $123 million for the second quarter of 2008. This decrease was due to a $37 million decline from the San Juan gathering system which had lower transportation fees indexed in natural gas prices.

San Juan natural gas prices averaged $2.59 per MMBTU this quarter compared with $9.19 per MMBTU in the second quarter of 2008. Of course these lower natural gas prices resulted in lower fuel and shrink costs in some of our other businesses.

Also contributing to the decrease was lower revenues from condensate sales from San Juan and Texas Intrastate System and higher expenses from pipeline integrity and repair costs on the Texas Intrastate System. We realized a $5 million increase in gross operating margin from increased storage fees from our Petal and Wilson gas storage facilities.

A new storage cavern with 4.2 Bcf of subscribed capacity began service at our Petal Mississippi facility in third quarter of 2008. We also had a $3 million increase in gross operating margin this quarter from the Piceance and Jonah pipelines and the White River hub in the Rockies.

Total onshore natural gas transportation volumes increased 12% to a record 8.3 trillion BTUs per day this quarter. The capital markets improved significantly during the quarter, which lowered our incremental cost of capital substantially from the first quarter this year.

Since March 31, 2009 we have raised $725 million of capital consisting of $500 million of 4.6% three year notes issued in June and $225 million of equity. The equity transactions included $137 million from the sale of 8.9 million Duncan Energy Partner units and $88 million through our distribution reinvestment program last quarter.

EPCO accounted for $75 million of the proceeds raised through the May distribution reinvestment. Affiliates of EPCO and Enterprise GP Holdings have committed to reinvest $82.5 million of their upcoming EPD distributions in August. Our liquidity at the end of the second quarter was approximately $970 million.

We invested $274 million in growth capital projects in the second quarter and Randy will give more details later in the call about these capital expenditures. During the first half of 2009, we commenced operations at new facilities representing $1.2 billion of total investments.

We announced the completion of our Sherman extension natural gas pipeline in March of this year. While that pipeline has been ready for service, we've not yet begun commercial transportation on the pipeline due to integrity issues with Gulf Crossing pipeline, the connecting takeaway pipeline. Based on notices from Boardwalk, the owner and operator of the Gulf Crossing pipeline, we expect to put Sherman extension into full force this Saturday. Once in service, we expect the Sherman extension to begin increasing volumes to near capacity based on long-term agreements with shippers for 1 Bcf a day of capacity.

Our Shenzi crude oil pipeline is currently flowing 129,000 barrels per day -- from the BAC operated Shenzi field in the Green Canyon area of the deepwater Gulf of Mexico. This 20 inch pipeline which has 230,000 barrels per day of capacity provides producers access to both our Cameron Highway and the Poseidon pipelines.

Our other major growth capital projects under construction are the Trinity River basin lateral in the Barnett Shale and the Marathon and Collbran Valley natural gas pipeline systems in Colorado that will feed our Piceance basin pipeline system and our Meeker natural gas processing plant. The Sherman extension will lay the foundation for the separate but complementary Trinity River basin lateral, a new 1 Bcf a day 30 and 36 inch pipeline to facilitate production from new areas of the Barnett Shale that are not adequately served by pipelines today.

Phase I is expected to be completed at the end of this quarter and will allow initial deliveries from this area into the Sherman extension pipeline. Phase II consisting of additional pipeline and compression is scheduled to be completed in mid-2010.

We estimate current production from the Barnett Shale to be about 4.9 BCF a day from 11,500 wells. Like most natural gas basins, the rig count for the Barnett is down substantially from the third quarter of last year due to producers conserving their capital during the current cyclical load for natural gas prices. There are currently 73 rigs active in the region and based on our analysis, we believe the rig count will remain at 70 to 73 for the remainder of the year.

We like the Barnett Shale with its low finding and development costs over the long term. Six of the top operators in the Barnett have reported a drilling inventory of almost 20,000 locations.

The Eagle Ford is a developing shale play in South Texas and potentially along the entire Texas Gulf Coast. We're very interested in providing midstream services to producers developing the Eagle Ford shale given the proximity of our integrated system of natural gas and NGL pipelines, storage, processing and fractionation facilities in that region.

Over 2 million acres with Eagle Ford potential have been leased and more than 20 producers are in various stages of exploration and development with a number of test wells drilled in South Texas. Limited public data indicates successful wells will produce similar to or better than the Barnett Shale wells with most of the natural gas fairly rich in natural gas liquids which of course will need to be processed before it can be marketed.

Turning to the Rockies, inlet volumes continued to increase at our Meeker and Pioneer processing plants with approximately 1 Bcf a day currently flowing into the Meeker complex and approximately 700 million flowing into Pioneer. Currently we are extracting about 50,000 barrels a day of natural gas liquids at the Meeker plants and 30,000 barrels per day at the Pioneer facility.

Our Piceance basin and Jonah gas gathering systems are currently averaging 1 Bcf a day and more than 2.1 Bcf a day respectively. The Piceance basin's central treating facility that began receiving natural gas volumes in March is treating about 65 million a day of Exxon gas production and Exxon has 30 or more wells drilled and waiting to start production plus seven rigs currently drilling in that region.

The rig count has declined significantly in the Piceance basin and the Jonah/Pinedale regions also. The good news is the majority of the new wells completed in the Piceance region will likely feed into our natural gas pipeline and into the Meeker complex. We have gathering and processing agreements with 10 of the top 12 producers in the Piceance basin.

With the current rig count, we expect the average volume on our Piceance and Jonah gathering systems to remain at current levels at least through the second half of 2009. We are also evaluating opportunities to provide midstream services in the Haynesville shale area. And with that, I'd like to turn it over to Randy Fowler to discuss other financial items.

Thank you Mike. I would like to briefly discuss the income statement items below gross operating margin. Depreciation and amortization expense and operating costs and expenses for the second quarter of 2009 increased to $153 million from $136 million for the second quarter of 2008 primarily due to increased property, plant and equipment from additions of the Petal natural gas storage cavern in August 2008 and the Meeker II processing plant, Exxon treating facility and Sherman extension pipeline in the first quarter of this year.

G&A expense increased to $28 million this quarter from $24 million in the second quarter of last year primarily due to $4 million of merger related expenses incurred this quarter. We reported $126 million of interest expense this quarter compared to $96 million for the second quarter last year.

Average debt outstanding increased to $9.4 billion this quarter from $7.6 billion in the second quarter of 2008 primarily to debt incurred to fund growth capital investments. $12 million of the interest expense increase is attributable to a lower amount of capitalized interest in the second quarter of 2009 versus the second quarter of last year due to a decline in the amount of construction work in progress.

Turning to capital expenditures, we invested approximately $240 million in growth capital projects and $33 million in sustaining capital expenditures in the second quarter of 2009. There were no large single project expenditures, just a number of smaller amounts including capital spent on the Trinity River basin lateral, the marathon gathering pipeline, the Sherman extension pipeline and the rail rack and terminal at Mont Belvieu that we acquired from Martin Midstream in the quarter.

At June 30, 2009 we had $9.4 billion of debt outstanding; including 100% of our $1.23 billion of hybrid securities and $467 million of EPD debt. As Mike mentioned, EPD had a liquidity of approximately $970 million at June 30, 2009 which includes availability under our credit facilities and unrestricted cash.

We normally have a seasonal increase with working capital during the second and third quarters as we build NGL inventories that are forward sold for deliveries during the winter months. This year our working capital levels are a bit higher than normal because of current business opportunities.

At June 30, we had approximately $620 million of total working capital deployed in NGL inventories that have been forward sold and in restricted cash which principally supports our natural gas processing hedging activities. We expect this level of working capital to tick up during the third quarter but expect by year end 2009 the amount deployed will decrease by approximately $340 million from current levels as inventories are delivered and receivables are collected.

Our consolidated floating interest rate exposure was approximately 21% at the end of the quarter. The weighted average term to maturity of our debt which uses the first call date for the hybrids is approximately 7.5 years and our effective average cost of debt is currently about 5.6%.

Our consolidated debt at the end of the quarter totaled $9.36 billion. Adjusted EBITDA for the 12 months ended June 30, 2009 which is EBITDA less equity earnings plus actual cash distributions received from unconsolidated affiliates was $2 billion.

Our consolidated leverage ratio of debt adjusted for the 50% equity content in the hybrids to the last 12 months of adjusted EBITDA was 4.3 times at June 30. EBITDA was negatively affected by approximately $156 million of hurricane effects in 2008 and the first half of 2009. Excluding these impacts, the debt to pro forma adjusted EBITDA would have been 3.9 times.

Our leverage ratio is also elevated due to debt balances reflecting a significant amount of capital cost for the Sherman extension and Shenzi pipelines which were completed during the first quarter of 2009 but are not yet contributing meaningful EBITDA as of June 30. Leverage is also elevated due to the higher level of working capital. We expect leverage to decrease to less than four times at year end. With that, I'll turn the call over to Hank Bachmann to discuss Duncan Energy Partners.

Thank you Randy. We are pleased to report another strong quarter for Duncan Energy Partners, with a 74% increase in net income, and almost a 200% increase in distributable cash flow. Both net income and distributable cash flow are higher due primarily to the midstream businesses that we acquired from Enterprise in December 2008 and supporting our third consecutive quarterly increase in the cash distributions paid to our partners.

In June, we completed our first follow-on equity offering and issued 8.9 million common units that generated net proceeds of approximately $137 million to our partnership. We used those net proceeds to purchase from Enterprise an equal number of DEP units and canceled those purchased units.

While the Partnership did not retain any of the net proceeds of the offering, there was no dilution or increase in the number of DEP's outstanding units. What the Partnership was able to accomplish as a result of these transactions was to effectively increase the amount of units owned by the public by 60% to approximately 24 million common units, thereby providing our investors with substantially more daily liquidity.

In fact, average daily liquidity has increased from 92,000 units per day for the first five months of this year to over 330,000 units per day thus far in July. For the second quarter of 2009, we reported net income attributable to Duncan Energy of $23.2 million or $0.40 per common unit on a fully diluted basis compared to $13.3 million or $0.32 per common unit on a fully diluted basis for the second quarter of 2008.

Distributable cash flow increased to $32.3 million for the second quarter of 2009 compared to $10.8 million in the second quarter last year, primarily as a result of the $21.6 million of cash distributions received from the midstream businesses acquired from Enterprise in December 2008. On July 15, 2009 the Board of Directors of our General Partner declared a quarterly cash distribution rate of $0.435 per common unit which represents a 3.6% increase from the $0.42 per common unit paid in respect to the second quarter of 2008 and as I mentioned before, is our third consecutive quarterly increase in the cash distributions paid to our partners. Distributable cash flow for the quarter provided 1.3 times coverage of the increased cash distributions to be paid on August 7, 2009. Now I would like to briefly discuss the performance of our business segments for the second quarter of 2009.

This quarter our Onshore Natural Gas Pipeline business segment reported gross operating margin of $30.2 million compared to $43.9 million for the second quarter of 2008. This quarter-to-quarter decrease was primarily attributable to a decrease in gross operating margin from the Texas Intrastate System due to lower condensate sales and higher pipeline integrity expenses and lower sales margins and sales volumes on the Acadian pipeline system.

This decline was offset in part by our Wilson natural gas storage facility which had increased gross operating margin of approximately $2.2 million this quarter due to higher storage reservation fees. Natural gas pipeline volumes increased slightly to 4.74 trillion BTUs per day compared to 4.73 trillion BTUs per day in the second quarter of 2008.

Our NGL Pipelines & Services business segment had gross operating margin of $25.5 million for the second quarter of 2009 after adjusting for a measurement loss associated with the Partnership's Mont Belvieu storage facility. This was a 24% increase over the gross operating margin of $20.5 million for the second quarter last year, also adjusted for a measurement loss in that quarter.

The increase is attributable primarily to higher storage fees and volumes at our Mont Belvieu storage facilities, a decrease in fuel costs at our facilities in Mont Belvieu, Texas and South Texas and lower maintenance expenses at the Partnership's South Texas fractionators. A reminder that operational measurement gains and losses at our Mont Belvieu, Texas storage facility are allocated to Enterprise and reflected on our financial statements as an adjustment to noncontrolling parent interest.

NGL transportation volumes decreased to 106,000 barrels per day in the second quarter of 2009 from 127,000 barrels per day in the second quarter of 2008 and NGL fractionation volumes were 77,000 barrels per day this quarter versus 80,000 barrels per day in the same quarter last year.

Our Petrochemical Pipeline Services business segment had gross operating margin of $2.6 million for the second quarter of 2009 compared to gross operating margin of $3.4 million for the second quarter of 2008, primarily as a result of lower transportation volumes on our Loutex propylene pipeline. Sustaining capital expenditures were $12.7 million in the second quarter of 2009, a $3.1 million reduction from the $15.8 million recorded in the second quarter of 2008.

Of the $12.7 million spent this quarter, approximately $8 million was spent in respect of the midstream businesses acquired from Enterprise in December 2008, and the remaining amount related to the businesses that we acquired from Enterprise in connection with our IPO. For the year, we estimate that we will spend approximately $55 million on sustaining capital expenditures which compares to $54 million spent in 2008.

Interest expense increased to $3.4 million for the second quarter of 2009 from $2.7 million recorded in the second quarter of 2008 due to higher average debt outstanding as a result of our borrowing of $282 million to fund the cash portion of our December 2008 acquisition. Total debt to principal outstanding at the end of June 30, 2009 increased to $467 million from $208 million at the end of June last year as a result of the December borrowings.

We had total liquidity of approximately $131 million at June 30, 2009 which includes availability under our $300 million revolving credit facility as well as unrestricted cash. In closing, we're pleased to report another quarter of solid results and coverage of our cash distributions. Randy, we are now ready to take questions on Enterprise or Duncan Energy.

Thank you Hank. Before we start the Q&A session this morning, please note that we will only be able to address questions regarding our operations and quarterly performance and will not be able to disclose additional information regarding the previously announced pending merger with TEPPCO since we are currently working on various regulatory and SEC filings per the merger agreement, which we anticipate will be made in the coming weeks. Lexi, we are ready to take questions now.

(Operator Instructions) Darren Horowitz, Raymond James.

Mike, I was hoping that we could get your thoughts on your ability or what you are looking at to hedge your equity NGL production for 2010. It seems that if the petrochem demand is stabilized like you have indicated, you've got ethylene productions forecasted to be running ahead of five-year averages. In addition to a couple of facilities that are slated to be closed, it would indicate that you are waiting for obviously ethane and propane margins to improve before you start to lock some of that production in. I was just curious, is there an inflection point either on the ethane or the propane side where you would start to hedge or what exactly are you guys looking at?

I'm going to let Jim answer it. But we have been pretty opportunistic about the timing on this and frankly we have not been real great at picking the absolute highs, but we have been very good at locking in very attractive margins. Jim, want to talk a little bit about kind of what you look for?

Is there an inflection point, Darren? Yes. Are we absolutely certain what it is? Probably not.

If you look forward and you look at the contago in natural gas, the margins that you see forward that you could lock in, we just think once we get there, the margins will be a lot better than what we could lock in today. So if we ever see that reverse and we're anywhere close to what current margins are -- let me give you an example.

If I look at the Rockies composite today, it's in the neighborhood of $0.415 to $0.425 per gallon. If I go out in 2010, I'm down around that $0.30 per gallon. I think we expect with the run rate we see on petrochemicals, we think that comes back as you get closer.

Jim, just as a follow-up, how does the Gulf Coast ethane market play into this? We have obviously seen exports picking back up. Are exports where they sit today, does it lend more confidence to your ability that the market in the Gulf Coast particularly around Belvieu is going to be tighter?

Are you talking ethane or propane?

Just ethane.

Okay, it appears that ethane is tighter than -- ethane is tighter than it was in January and February. We sense that inventories have been pulled quite dramatically as you've had a pretty robust demand for ethane from petrochemicals.

Then just one big picture question if I could. As you look forward to 2010, can you outline outline for us the Eagle Ford opportunity? Jim, I know that you want more incremental dollars for CapEx allocated to the NGL side of the business. Can you just give us a sense for any potential synergistic overlap and what you see unfolding there?

We want more capital dollars for all aspects of the business.

Right.

We are all over South Texas -- how many processing plants we got down there? Seven or eight?

All the gathering that we have down there, this is one of those deals -- I think we told Dan if we fumble this one, we probably ought to all be fired. We have a vision as to exactly what we want to look like in the Eagle Ford.

We understand what we need to do and we are pitching that vision to every producer that is down there and getting extremely good responses. That's about the extent of what I want to say right now Darren. But we know where we want to be and the producers down there know where we want to go and are supportive of it.

Darren, I would add to that the NGL business is very important to us but I think our focus with respect to CapEx in 2010 and 2011 is going to be more heavily weighted on the natural gas side.

Sure. I appreciate the color guys. Keep up the good work.

Thank you.

Ross Payne, Wells Fargo.

Yes, first question is the $12 million in hurricane impact. Any thought on when that may come back or is some of that going to be [shut in] for an extended period of time? And second question is related to the DRIP. How long can we count on that? How many more quarters if any after this? Thanks.

Let's take them in reverse order. On the DRIP, you can count on the next distribution and that's probably about it. Not to say that there won't be more, but it's not something that anybody is committing to right now.

I will let Jim Guion talk a little bit about the offshore production. But the plants and the facilities and pipelines are coming back on. Frankly, the amount that we had from business interruption in the second quarter was less than first and things are improving every month.

We do expect to get some recoveries on that as early as this quarter. So things are looking better. Jim, do you want to talk a little bit about platforms in the Gulf?

Well real briefly, we have got a couple of systems, our pipeline systems that are still shut in. Anaconda is one. We're relying on A&R to repair their downstream pipe. And as of this morning, they are anticipating that that should be back on and producing either today or tomorrow.

Beyond that point, we have got -- our Viosca Knoll system still has some work and we're working with MMS on a repair procedure or maintenance procedure on those pipe. But other than that, most of our pipes are back flowing and our platforms are dependent on the Anaconda. Once it gets back on, we should be up and flowing full force.

Is Anaconda eminent?

Yes, sir. Within the next day or two.

So once Anaconda is up, then the only thing -- the only issue out there is Viosca Knoll.

Yes sir, that's correct.

Otherwise we are up and fully flowing.

That's correct.

Ross, to put dollars on that, we -- like you said, estimated lost business in the second quarter was $12 million. What we estimated lost business for in the third quarter is $5 million which principally is the downtime in July.

Okay, super. Great, thanks for the color guys.

Brian Zarahn, Barclays Capital.

Can you provide a little commentary on the Texas Intrastate business and what you -- just sort of what we should be expecting for the rest of the year?

I will pass that to Chris. Again, do appreciate the fact that we have this hedge in place that does affect us somewhat. Chris is doing a lot of work trying to optimize all of our pipelines, particularly the Texas Instrastate.

The pipeline is sold out for the rest of the year. So our volume is not where we're getting hurt right now. It's from flow rates of some of our firm customers with the spreads collapsing in the Gulf from west to east across the pipeline.

We are experiencing some lower takes in the commodity side of the component. But the vast majority of the revenues are locked in from a firm point of view and we have had a normal amount of integrity work during the summer time. We typically do that in the second and third quarter while flows are down so we are prepared to flow for the first and fourth quarters.

Okay, I'm looking at -- is there any change to your CapEx estimates for the year?

No, still on target for right around 900, $950 million for the year in growth CapEx.

And then how much more merger related costs should we expect for the remainder of the year?

Well that's kind of hard to tell, probably a fair amount. What we had so far was legal costs related to negotiations and the preparedness and that kind of thing. But we do have, as Randy indicated in his opening comments, that we have SEC filings to make and proxy solicitation process to go through. So thereare other things that we need to accomplish.

Thank you.

Michael Blum, Wells Fargo.

A couple of questions. One, I think Mike, you threw in there that you're looking at some opportunities in the Haynesville. Could you elaborate a little bit? Are you looking at -- do you think there's more pipeline opportunities? Is that more midstream, NGL?

Sure Michael, kind of all of the above. But clearly with the Haynesville, there's an opportunity for pipeline infrastructure. We think we have some solutions that should be very attractive to the industry players. Chris or Jim, do you want to say any more on that?

Nope.

Is that a near-term opportunity or are you thinking more 2010, 2011? Just any feel for that?

Well it depends on what you mean. There's opportunities currently and then there will be opportunities for the next several years.

Are you getting a sense you're not going to get a full answer on this, Michael?

That's what I'm feeling. That's the vibe I'm getting. Alright, I'll try another one.

Mike, I think you made a comment also that you think the NGL export market will remain strong for the remainder of '09 and into 2010. Maybe you or Jim, could you talk about what dynamics you think are going to drive that in the future?

Yes, Michael. You know, I've been around a long time and I've not seen this kind of a volume being exported this time of the year. Usually, this is an import season for us.

We are literally sold out across our export terminal in August, virtually sold out in September. And if the transactions we are working on fall into place, we will be sold out through the end of the year and well into 2010.

I think a lot of what's driving this is just as ethylene plants in the US are tweaking everything they can to be able to use more NGLs, so are ethylene plants in other parts of the world. So I think a lot of this is being driven by LPG substituting for naphtha in places like Northwest Europe.

That doesn't mean our cargoes are going into a new facility at some place in the Netherlands. It means our cargoes are taking the place of cargoes that would have otherwise gone to the locations our cargoes are going to allow for those out of Sonatrach or wherever to go into the crackers.

I think that a lot of what it is. I think if you look at what we are doing here on the Gulf Coast in terms of providing ethane to traditional naphtha crackers as well as what we are doing on our export volume, we are moving ahead of a lot of US natural gas BTUs into new markets made up of primarily traditional naphtha crackers.

Jim, just a follow-up to that. Is there a physical limit or limitation to how much the crackers can take the light feedstocks versus the heavies? Obviously we are seeing the shift. But is there some sort of physical limitation where they just can't take any more light and are we getting near that?

I don't know. I'm going to go back 12 years. You know where I came from and our cracker in Europe at the time could use about 50,000 barrels a day of LPG.

They produced I think 2 billion pounds a year of ethylene. So that was probably about 50%. I may be wrong.

If anything -- so that's 1.5 million barrels a month. If anything, they probably improved on that. I think -- I'm going to look at in large part it could be back-end constrained rather than front end constraint. It's probably an off-line question.

John Edwards, Morgan Keegan.

What were the volumes? Maybe you mentioned in the comments but maybe I missed -- what were the volumes you were processing on Independence?

We are right at 891 billion BTUs a day, about 900 million cubic feet a day.

And then I was curious on the way you were representing the adjusted EBITDA. I think on the press release, you had $16 million was backed out but you didn't back out the $34 million for Tops. So I was just curious why that was.

On adjusted EBITDA, if you will recall, our definition of adjusted EBITDA is we subtract equity earnings from unconsolidated affiliates and then add back actual cash distribution among consolidated affiliates. When you go through that step of subtracting equity earnings, you in essence excluded that forfeiture right off on top on the oil port.

Because you only had a third of it?

It goes through equity earnings (multiple speakers)

And then on your maintenance CapEx, are you expecting to catch up later in the year? Because it looked like at $33 million, it was a little bit light.

It's hard to tell. We may but there's a good possibility that we may come in a little short of what we expected.

So I guess what's a good run rate then for the rest of the year?

I would still look for about $180 million for the whole year and that's probably off $10 million from if you had asked us this six months ago.

So it's going to be a little bit lower than what you're expecting for -- okay. And then I was curious, going through your [DCF] numbers, the equity in income adjustment has typically been negative but reversed to positive this quarter and what was behind that?

That would be when we subtracted the equity earnings. Again, that's the charge-off on the Texas oil port.

Okay, so that is the charge-off there. Okay, great. And, let's see. And the cash distribution from the unconsolidated affiliates, it looked like that came down quite a bit year-over-year. What was behind that?

Probably two things. Two of the larger unconsolidated affiliates are the Marco Polo platform and then also the Cameron Highway oil pipeline. And just as a result of that estimated loss of business, you're seeing some of that flow through those joint ventures.

All right. And then in terms of your balance sheet, where would you like your leverage ratio to be? You mentioned you came in at 4.3 times, you'll hit 3.9 times by the end of this year. Would you prefer to be somewhere more in the 3.5 times range or what's --

What we talked about and our goal is to come in and try to keep it between 3.5 and 4 times.

And then on the Eagle Ford, you were talking about it as an opportunity. What -- are you looking at -- in terms of how you would contract for that, are you looking at similar to what was done with Meeker, it was mostly keep whole or are you looking at a different type of structure there? If you could give a little bit of color on that.

Yes, I think we are in discussions with people but really don't have anything to lay out for you right now.

Okay, great.

Whatever it is, it's going to be beneficial to us and the producer.

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

Mark Easterbrook, RBC Capital Markets.

Just got two quick questions on the NGL Pipeline segment. One, the fee-based processing volumes came down first quarter to second quarter. Is that a good run rate going forward? I think it's about 2.7 Bcf per day.

Mark, this is Jim. I'm absolutely clueless right now about this, deer caught in the headlights look on my face. Could this be because we saw some declines in South Texas (multiple speakers) I think it's because we saw some declines in South Texas and probably some elections down there that were conditioning elections, Mark.

So that 2.7 is probably a good run rate for the next quarter or two?

Probably.

Then the second question on that is, you mentioned or highlighted the marketing business as a good contributor to that segment. Roughly how much in gross margins did the marketing segment contribute?

Mark, we didn't break that out separately.

One of the reasons that we don't do that is because we are optimizing the assets and really it's kind of hard to say this is really marketing or this is just the marketing group utilizing an asset that we own and kind of where do you draw that line. In our mind, it's really just extracting all the value out of the assets that we have.

Then is there a particular geographic area where the marketing business really aided the quarter?

I think along the Gulf Coast -- well, I think it's the whole system, in reality. You know, I started to say the Gulf Coast, Mark, but the more I think of it; we are one of the largest customers off of the Mid-America system up there and our ability to take advantage of the options between the Midwest and the Gulf coast out of Hobbs is directly related to that. So I know it's not one geographical area. It's all of the above.

Okay. Thanks guys.

John Tysseland, Citigroup.

Good quarter. Just a couple of quick questions on fractionation. Looking on the fractionation margins, it appears that these margins on a per barrel basis have been increasing over the last couple of quarters. Can you give us just a little bit more color on that market and on Belvieu and also on Hobbs and what you have been seeing in terms of tightness and utilization rates on those assets?

We are full. We are -- hi, John. We are chockerblock full. And in terms of the fees, it's really an issue of supply-demand. And you know, a few years ago, you couldn't give those services away. Now it's in a high level of demand.

Is it Mont Belvieu or is it really all over?

It's primarily Mont Belvieu. But we are using every drop of fractionation capacity we have to make sure that producers' volumes flow and that includes what we have in other regions to take care of these guys.

And are the margins there -- is that something -- are the margins that you're seeing in that business at a rate where you would be worried about competitors coming in or do you think you still have a pretty big advantage of just expanding your capacity? And if so, where would you look at expanding?

I think Mike may have given you a hint from his comments in the opening remarks. We would probably look at Mount Belvieu. Given that we have a fractionator that we have recently built at Hobbs, I bet you we might have the engineering all but done.

So it's not -- we don't have a lot of lead time. It takes a couple of years to build one of these things. We think these margins have staying power. If we had one on today, it would be full.

John, I would say that we're always concerned about competition. We never take it for granted. We want to make sure that we have cost-effective service services for our customers.

Great color. Thanks guys.

Yves Siegel, Credit Suisse.

Just follow-up, please. As it relates to the potential fractionator at Mount Belvieu, how much would one of those go for?

More than it did 10 years ago.

Would it be comparable to the Hobbs?

Yes. I think it would be comparable to Hobbs.

How much did you spend on Hobbs?

Now, Yves --

Yves, you do good (multiple speakers)

A lot of it depends on how we size it and it's not just kind of off-the-shelf one-size-fits-all.

It depends on what other supporting infrastructure you have to put in andaround that pipelines and such, Yves.

Okay, well do you have opportunities in terms of contract renewals given that you're full? Does that give you some leverage and how much -- what percentage of capacity will roll in any given year?

What percentage of capacity will what? (multiple speakers)

It's not a -- it varies depending on the year. But we are putting our -- we're structuring our deals so that both the producer and Enterprise win on these things. We're giving -- we give the producer a level of flexibility but probably not as much flexibility as we would have five or six years ago. We are in the process of addressing all of our contracts regardless of their term and trying to lock up these volumes longer term.

Not to be Clinton-eque, but is longer term more than three years?

I'm 64 years old. Three years sounds like a long time to me.

Okay, just to wrap up too, on the NGL marketing side, I recognize that you don't disclose it, but when you think about the inventory that has moved up and the fact that you've entered into forward contracts, two-part question. Number one, have you booked any of that -- what is the timing of when you will realize the gains from that arbitrage opportunity? And is it fair to say that the magnitude of that opportunity is greater than it has been in past years?

We booked the revenue when we actually deliver the product, sell it and deliver it. And yes, we've got a lot of working capital, as Randy indicated, tied up in inventory that we sold forward. And so you could conclude from that that the gains from that are going to be bigger than we have seen historically.

And that will probably be fourth quarter?

Maybe some in the third, maybe some in the fourth, maybe some in 2010.

And then final couple of thoughts. When you think about the Haynesville opportunity and you think about Eagle Ford opportunity, what is the potential in terms of dollars that you might spend there? And the other way to -- I think Michael asked the question about timing on the Haynesville. I would think that if you wanted to move on that, you would have to move relatively quickly because of competitive pressures.

I think there's a lot of factors that play here, Yves. One is this isn't something we have total control of. We actually need customers.

And so it depends on what they want. We constantly look at all of our opportunities to deploy capital and look for where it makes the most sense for the Partnership. And certainly as we are focusing on the gas pipeline side, those are two areas that are very appealing to us, but they're not the only areas.

Magnitude of capital that you might have to empoly?

Couldn't tell you. But it's probably bigger than a bread box.

Bigger than $900 million? All right; thanks, guys.

Noah Lerner, Hartz Capital.

Quick question -- on the increase in demand for the NGLs input for the use as the feedstock, I was wondering if you guys are noticing -- is the increase in demand purely from the switchover from leaving that over to the NGLs? Were you actually seeing a real pickup in demand for the feedstock and the operations by the different petrochemical companies and facilities?

I'll start and and let Jim pick it up. I think the answer is yes. It -- certainly demand has picked up from the end of last year and the beginning of this year.

We have seen some of the heavier plants consuming more of the lighter [ends], trying to cheapen their feedstock costs and certainly the light end plants are probably running about as hard as they can. Jim, you got anything to add (multiple speakers)

You nailed it. Light ends are running as hard as they can, heavy crackers are trying to move harder to NGLs.

Do you guys read anything into this pickup in demand from an overall economic and [just starting the] cycle that maybe you're starting to see an improvement in the economy because of the demand for these -- for the feedstocks and the -- by the petrochemical industry and that will feed on itself and increase -- create more demand as the economy kicks in? Or do you think it's too early to say it's having an impact to be able to read into the economy?

I personally think it's too early. I don't think you're starting to see the pull from an economic recovery yet. You've got car companies that have been in bankruptcy that are trying to run down their inventory. Once that production starts up, once the economy starts to recover, people actually start to consume, then you will see that pull.

Okay, great. I guess my other question is on the San Juan gathering where the revenue went down so dramatically because of -- it's tied to the price of the natural gas, just curious, it seems then I'm reading into that you guys do not hedge any part of those volumes. If so, I'm just curious why you don't.

We've talked about in the past that we have a natural hedge, if you will, between those gas index contracts and other of our facilities where we have plants that consume natural gas or we have [keep hold] contracts where we have PTR and so you have that natural hedge. And so as I kind of alluded to in the comments, while gross operating margin declined at San Juan, other parts of our business benefited from that, intended to offset it.

We use about 35 million, 40 million a day at Mount Belvieu. So to the extent the price goes down, we benefit on our fuel costs at Mont Belvieu relative to what we loose on San Juan. We feel like there's a balance there.

Okay, great. Is it safe to presume that the $45 million that is mentioned in the press release to recover from the business interruption insurance, that's all going to fall to DCF. So that's akin to more additional cushion or excess cash flow to be retained possibly by the Partnership above and beyond what's been reported since last year's hurricanes?

I kind of term it a different way. Even with the business interruption and without recoveries from business interruption insurance, we are able to continue to increase our distribution and have a healthy coverage. When we get the recoveries from the business interruption, we would not expect to pay that out in distributions. We look at kind of what our normalized cash flow run rate is.

So then it hasn't been factored in anywhere. So it is additional future DCF, just probably retained?

It is additional distributable cash flow and we would not expect to pay out one-time cash receipts.

Great. Thank you for your time.

Sam McGraity, Delaware Investments.

Actually the question about the San Juan basin transportation feed indexed to natural gas, that's been kind of asked and I appreciate the answer. Just kind of -- how common is it within the industry or is this something specific to EPD that you guys have these kinds of contracts?

I think in different parts of the country, it's probably more standard than it is on the Gulf Coast. If you remember, we had -- San Juan has been around quite some time. So those contracts were put together well over 20 years and we inherited it when we acquired GulfTerra.

So at the moment or going forward, do you plan on seeing or do you expect to see more of these kinds of contracts in place?

I doubt it.

The other question I have is, given the changing winds and sentiment of the capital markets, have you guys changed or modified your stance on what is the proper amount of leverage, the treatment of unitholders etc. on a going forward basis?

I don't think that we have changed our view. We've consistently said over the last probably four or five years at 3.5 to 4 times debt EBITDA is probably the right place to be. What we have done and you probably noticed as we were going into 2009 is that we've moderated our CapEx.

We took advantage of some windows of opportunity in the fourth quarter last year. We issued equity and equity content this year. We raised fixed income when it was opportunistic to do so and we have continued to be very opportunistic about when we access the markets, always mindful that we want to maintain that investment-grade credit rating.

Thanks very much for your time.

John Edwards, Morgan Keegan.

Just a follow-up. I missed your answer on how much marketing contributed to natural gas.

You didn't mention it. We just didn't get it.

I got -- I was -- my phone was blocked out.

Yes John. Similarly on natural gas liquids and on the natural gas side, we view the marketing functions as part of the business as opposed to a separate business apart from the assets. And so it really is in both cases a way for us to fully optimize the assets that we own.

Then just another kind of housekeeping, again on the tops writedown. Did you in the natural gas segment, did you -- does the segment margin you reported, does that include that writedown?

That's in our Offshore Pipelines & Services segment.

I mean offshore, sorry. Okay. So you did include writing that down in that segment, correct?

That's correct.

That concludes our question-and-answer session.

Lexi, if you would, would you provide our listeners with the replay information?

Yes, thank you for participating in today's call. The instant replay from the call may be accessed one hour after the call concludes by dialing 1-800-731-6039. (Operator Instructions)

Okay; thank you, Lexi. And thank you for joining us today and have a nice day.