Enterprise Products Partners LP (EPD) 2011 Q2 法說會逐字稿

Good morning, my name is Sara and I will be your conference operator today. At this time I would like to welcome everyone to the Enterprise Products Partners and Duncan Energy Partners second quarter 2011 earnings call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question and answer session. (Operator Instructions) Thank you, Mr. Burkhalter, you may begin your conference.

Thank you, Sara. Good morning and welcome to the Enterprise Products Partners and Duncan Energy Partners joint conference call to discuss second quarter earnings. Our speakers today will be Mike Creel, President and CEO of Enterprise's General Partner, followed by Jim Teague, Executive Vice President and Chief Operating Officer, and Bryan Bulawa, Senior Vice President and Treasurer for the General Partner of Enterprise. Randy Fowler, who normally covers the financial discussion and DEP is out ill today. There are also other members of our senior management team 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 management of both Enterprise and Duncan.

Although management believes that the exceptions 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. Before we get started this morning, I would like to also remind everyone that the purpose of this call is to discuss second quarter results and therefore we will not discuss the proposed EPD/DEP merger or entertain any questions regarding that proposed merger. And with that I will turn the call over to Mike.

Thanks, Randy. We're pleased to report new records this quarter for net income, adjusted EBITDA, gross operating margin and distributable cash flow supported by growth in natural gas, NGL and crude oil production in the shale regions and improved NGL's sales margins. We surpassed the records we set last quarter as our diversified and integrated midstream assets continued to perform well and we continued to benefit from increased demand for NGLs by the US petrochemical and international markets. Gross operating margin for the quarter increased 14% to a record $923 million from $809 million in the second quarter of 2010. This led to record adjusted EBITDA of $916 million and record net income of $449 million. Our partnership generated record distributable cash flow of $778 million for the quarter, which provided 1.6 times coverage of the increased cash distribution of $0.605 declared with respect to the second quarter.

Included in distributable cash flow this quarter was $166 million of net proceeds from the sale of $4.45 million Energy Transfer Equity common units. Excluding these proceeds our distribution coverage was still 1.2 times. We retained $284 million of distributable cash flow this quarter and through the first six months of this year we've retained $491 million or roughly one-third of the $1.5 billion of 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 gross operating margin of $498 million, an increase of $57 million or 13% over the second quarter of last year. Our natural gas processing and related NGL marketing business benefited from continued strong demand for NGLs, as higher NGL sales margin and fee-based gas processing revenues led to a $35 million increase in gross operating margin.

We also had a significant increase in fee-based gas processing volumes from the Eagle Ford shale and our Rocky Mountain plants. Equity NGL production was lower this quarter compared to the second quarter of last year, primarily due to two weeks of downtime this quarter at the Pioneer Gas processing plant for maintenance and modifications to improve ethane recoveries. Fee-based gas processing volumes increased 24% to 3.7 billion cubic feet a day in the second quarter of this year compared to 3 billion a day in the second quarter of last year. Gross operating margin for our NGL Pipeline and Storage business increased to $143 million this quarter, a $4 million improvement over the second quarter of last year, primarily due to increased long haul movements at higher tariff rates and lower operating expenses on the Mid-America and Seminole systems, which reported a $10 million increase in gross operating margin.

Total NGL pipeline volumes increased 3% to 2.3 million barrels per day this quarter. We exported 10 million barrels of propane during the quarter, which is 18% higher than in the second quarter of 2010. We successfully concluded an open season during the quarter for the expansion of the Rocky Mountain leg of our Mid-America pipeline system. Shippers executed ten year ship-or-pay transportation agreements for initial commitment of 38,500 barrels a day capacity. Capacity commitments have increased to 50,000 barrels a day and shippers have until the end of the year to exercise options to further increase their commitments to 85,000 barrels a day. We expect that will happen given the significant interest in new and geo takeaway capacity out of the Rockies. We hope to receive FERC approval of the project this month and expect it to begin service in the third quarter of 2014.

Our NGL fractionation business reported record gross operating margin of $52 million, a 52% increase over the $34 million reported in the second quarter of last year. This increase was largely attributable to our new Frac IV unit at Mont Belvieu, which began commercial operations during the fourth quarter of last year and is operating in excess of its name plate capacity of 75,000 barrels a day. Construction continues on our fifth fractionator at Mont Belvieu, which is on schedule to begin operations by the end of the year. And in June we begin construction on our sixth fractionator at Mount Belvieu to accommodate the expected growth of liquids rich natural gas production from the Eagle Ford shale. When this new facility is completed, Enterprise will have more than 450,000 barrels a day of gross NGL fractionation capacity at Mont Belvieu and 940,000 barrels a day of gross NGL fractionation capacity system-wide.

Our Onshore Natural Gas Pipeline and Services segment had a $54 million or 51% increase in gross operating margin this quarter. Approximately $32 million of the increase was from three systems -- the Texas Intrastate system, which benefited from higher firm capacity reservation fees and volumes; the State Line gathering system, which we acquired in May of 2010; and the San Juan gathering system that had higher volumes and fee based revenues. Natural gas marketing had a $27 million improvement due primarily to changes in the market value of certain derivative contracts and higher margins realized on physical contracts. Total onshore natural gas pipeline volumes increased 4% to 11.9 trillion BTUs per day for the second quarter of 2011.

We're pleased with the progress of the Acadian Haynesville extension pipeline, which is on schedule to begin flowing volumes in late September, with demand charges expected to begin the first of October. And Jim will talk a little bit more about the Haynesville extension in his remarks.

Gross operating margin for the Onshore Crude Oil Pipeline and Services segment increased 161% to $68 million for the second quarter of 2011 from $26 million for the second quarter of 2010. We had increased throughput on all of our onshore crude oil pipelines except for Seaway, which continues to be impacted by the lack of demand for northbound transportation to the oversupplied Cushing hub. Increased drilling activity in the Eagle Ford shale led to high volumes on our South Texas system, while increased production in the Barnett Shale benefited our Red River gathering system. Crude Oil Marketing margins improved significantly over the second quarter of last year, due to more favorable crude differentials, contango market opportunities and the integration of pipeline expansion projects.

Excluding $10 million of insurance proceeds received in the second quarter of last year, our Offshore Pipelines and Services segment had a $19 million decrease in gross operating margin due in large part to the slowdown in permitting for exploration and development activity in the Gulf of Mexico. Naturally occurring production declines have not been offset by new drilling. Our Independence hub platform and Independence Trail pipeline reported an $8 million decrease in gross operating margin on a 25% reduction in volumes. We expect to receive additional volumes into the Independence and Cameron highway pipelines in the fourth quarter of this year associated with initial production from a new well and the restart of other wells that were down for recompletion or facility maintenance. Gross operating margin from the Petrochemical and Refined Products Services segment was $140 million this quarter compared to $158 million for the same quarter of last year.

The Propylene Fractionation business had a $36 million decline from the second quarter of 2010, which was far and away one of propylene's best quarters ever due to lower sales volumes and sales margins. Propylene Fractionation volumes were 13% lower this quarter due to refinery turnarounds and planned maintenance activities, as well as new supply entering the market. The Refined Products Pipeline business had a $9 million decrease in gross operate margin, primarily due to higher maintenance and pipeline integrity expenses, as well as lower transportation volumes from the Gulf Coast to the midwest and northeast markets. Pipeline volumes for the Refined Products Pipelines were 11% lower this quarter. Structural shifts in population and refinery production at PADD II have led to a decline in demand for transportation of Refined Products from the Gulf Coast to the midwest.

According to EIA overall demand for refined products in PADD II has dropped by 5% from 2008 levels. We view this as primarily a result of the lingering effects of the recession, conservation and shifts in population. Additionally, several significant refinery expansions are beginning to come on line that are benefiting from cheaper West Texas intermediate crude prices, leading to an increase in refined products production in the midwest. Our octane enhancement business reported a $26 million increase in gross operating margin to a record $37 million in the second quarter of this year, largely due to higher margins, increased volumes and contributions from the high purity isobutylene plant that we acquired out of bankruptcy in November of 2010. We recently announced an increase in our quarterly cash distribution to $0.605 per unit or $2.42 an annualized basis. This is a 5.2% increase over the distribution declared with the respect to the second quarter of 2010. This is our 28th consecutive quarterly distribution increase and our 37th increase since our IPO in July of 1998.

We're proud of the strong results our businesses produced this quarter and of our employees who made it happen. With the continued development of shale and other non conventional plays around our assets, the growing demand for NGLs versus crude oil derivative feedstocks by our petrochemical customers and the wide crude oil price differentials between Cushing and the US Gulf Coast, we have clear visibility to our growth drivers for the next few years. We currently have about $6 billion of major growth capital projects under construction that will begin coming on-line later this year and continue through 2014. These new assets will deliver important services for our customers, as well as generate new sources of distributable cash flow for our partners. We remain excited about the opportunities available to the partnership, as well as our future prospects. And with that I'll turn the call over to Jim.

Thank you, Mike. As you can tell from our results that Mike has just gone over, market fundamentals continue to support midstream margins and investments in this segment are racing to keep pace with upstream and downstream announcements. Expansions range from new drilling and growing upstream production for natural gas, NGLs and oil, midstream processing, fractionation, storage and transportation and, interestingly, downstream chemical plant expansions. Led by shale gas and shale oil, we're in a period of tremendous growth for the entire midstream sector. Benchmarks by which we always measured industry performance in the past are now in unchartered territory. At the start of this year crackers consumed record volumes of ethane, topping one million barrels a day. In May, US producers saw record high NGL production volumes from natural gas that exceeded 2.2 million barrels a day.

In April, US LPG export volumes reached an all-time high of over five million barrels. In May, unplanned cracker outages tightened the ethane markets considerably, boosting olefin prices and cracker margins to historically high levels, despite operating rates only dipping into the upper 80s and low 90s. And then by the end of June cracker operators were above 95% operating rates with supplies balanced by opportunistic exports. Margin is driving this behavior for producers and consumers alike. Ethane prices, for example, are low enough that cracker operators have all but maxed out consumption of this feedstock, which not only topped a million barrels a day at the start of the year, but also topped the million barrel a day mark last month. On the flip side, NGL prices are also high enough that producers continue to maximize drilling in NGL rich plays.

Propane exports from the US has been another area of tremendous growth, with the same production fundamentals driving propane extraction at natural gas processing plants to a record high 620,000 barrels a day in May. On the demand side propane into crackers, as well as propane dehydrogenation, has increased. But the largest increase has been seen in exports where, of course, we have an expansion underway. As with ethane, propane is affordable enough for chemical plants to post solid margins from propane, but attractive and international markets and at the same time provides US producers with attractive upstream margins. Products like the expansion of our Rocky Mountain segment that Mike mentioned, the expansion of our propylene fractionation capacity at Mont Belvieu and our sixth frac train that is expected to be online in early 2013, we continue to pursue projects that meet customer needs but also complement our existing assets.

As an example we're in the process of implementing projects we had previously announced. First our Acadian Haynesville extension. The 270 mile pipeline project continues to make rapid progress. We expect to begin testing the pipeline in just a few days with first flows in September and full commissioning by October 1. We continue to believe our Haynesville assets are in the premier area of the play, DeSoto, Sabine and Red River Parishes, as evidenced by the rig counts, where 67 of 121 of all Haynesville rigs are in close proximity to our footprint. The Haynesville shale continues to be one of the most prolific natural gas plays in the country, with 6 Bcf a day of production from 1600 wells. Our analysis indicates about 250 wells that have been drilled and are either waiting on completion or pipeline connections. And the Haynesville could ultimately produce 10 Bcf a day when fully developed.

Our pipeline project is supported by long-term, ten-year commitments and has a multitude of interconnects and integrates well with our existing natural gas assets in Louisiana. We're also nearing completion of two new gathering and treating system totaling 140 miles of pipeline that will integrate with our State Line gathering and treating system. These systems expand our gathering footprint to cover 500,000 acres in the core of the Haynesville and Bossier shale trends in Red River, DeSoto, Sabine and Acadian Parishes. Those gathering systems have the capability of delivering approximately 1 Bcf a day into the Haynesville extension. In our Eagle Ford developments the implementation of several significant projects is in full swing and proceeding.

In addition to numerous bridge and expansion projects already completed along our network of natural gas and processing assets in South Texas, several large gas and crude projects are progressing rapidly. 300 miles of rich and lean large diameter natural gas pipelines, 600 million cubic feet a day cryogenic gas processing plant and we're already in the planning stage to expand that by another 300 million a day, 127 mile NGL pipeline to take products to Mont Belvieu, 75,000 barrel a day NGL fractionation coming on at the end of the year, our fifth train, and as Mike mentioned, our sixth train, 75,000 barrels a day due on the first quarter of 2013. 220 miles of crude oil pipelines, including our Phase II extension further into South Texas near Gardendale and over 5 million barrels of storage capacity reaching from South Texas to the Houston area, terminating at our new ECHO terminal in Houston that will have connectivity to every Houston area refinery and barge access to the entire Gulf Coast.

This pipeline will also have access to Cushing through our Seaway pipeline. The Eagle Ford continues to exceed expectations relative to drilling, production and reserve projections in both the rich gas and crude oil areas. There are currently about 180 rigs working in the Eagle Ford, about 1100 producing wells, and about 400 wells waiting on completion of crude and natural gas pipelines and gas processing. All of our existing natural gas pipelines and gas processing facilities are completely full and we're running over 125 crude oil trucks in order to keep up with the needs of our producer customers. It continues to be an exciting story that's already having a very meaningful impact on our bottom line. We're going to shift gears a little bit now and speak to some of the projects that we are pursuing. We remain hopeful that our crude oil pipeline from Cushing to Houston continues to gain traction.

Given the magnitude of the economics, our timeline attributes and the synergies of our Cushing storage and the connectivity of our new Houston ECHO storage and terminal, we continue to push the project. We have a number of producers highly supportive of this project and given the upside potential to the threshold we require is not a fully subscribed pipeline. We're not there yet, but are determined to continue to push forward to the accretive threshold we need and, if achieved, will sanction that project. The recent string of downstream petrochemical announcements calling for significant expansions to domestic ethylene production and growing production and reserve projections for the Marcellus and the Utica, it has become more and more apparent that Marcellus ethane producers need Gulf Coast chemical companies and those chemical companies on the Gulf Coast need Marcellus ethane.

We have a pretty exciting project to bring this Marcellus ethane to the heart of the US chemical hub in Mont Belvieu and our discussions with shippers continue to advance and are gaining a lot of traction. As with the Cushing to Houston pipeline, the upside of this project makes us comfortable with a commitment threshold that's not fully subscribed but is accretive. In addition, and finally, we have a separate but very complementary project we're discussing with Gulf Coast petrochemical producers that would provide an extensive ethane header system that would literally stretch 550-miles from Corpus Christi to the Mississippi River. This impressive project can be accomplished by utilizing existing pipes and adding a modest amount of new pipes. Our Marcellus project would connect into this new header allowing Marcellus ethane to flow throughout the Gulf Coast.

If we are successful with this project, chemical plants across the entire Gulf Coast could literally float their ethane needs on our header system giving them access to growing ethane supplies all the way from the Rockies, including the growing Uinta and DJ basins and growing rich gas supplies from the Permian to the Eagle Ford into the Marcellus. And this project would be backed by our 100 million barrel NGL storage facility in Mont Belvieu, with connectivity from Corpus Christi to the Mississippi River supported by our fractionation storage and interconnectivity at Mont Belvieu, Enterprise would be able to provide services that give consumers flexibility and resource diversity and producers unparalleled flow assurance and market choices. And with that I'll turn it over to Randy.

Actually Bryan.

Thanks, Jim. I would like to take a few minutes and discuss additional income items. First starting with general and administrative costs. Our G&A costs were $50 million in the second quarter of 2011, which was $10 million higher than the G&A costs in the second quarter of 2010, primarily due to increase employee expenses and costs associated with the pending merger with DEP.

Moving to interest expense. Interest expense increased to $188 million this quarter from $179 million reported for the second quarter last year. Average debt balances were $14.2 billion and $13 billion for the second quarters of 2011 and 2010 respectively. Also contributing to the increase in interest expense was $12 million of mark-to-market expense associated with interest rate swaps assumed in the DEP merger. Partially off setting the increase in interest expense this quarter was higher capitalized interest. Capitalized interest this quarter was $26 million versus $11 million for the second quarter of 2010. For 2011 we estimated capitalized interest will increase to approximately $100 million to $110 million from $47 million recorded in the 2010 due to increased levels of construction activity.

Total capital expenditures were $1 billion this quarter, which included $916 million for growth projects. Approximately 84% of the growth capital expenditures this quarter were for the Haynesville and Eagle Ford related projects. Through the first half of the year we have spent $1.6 billion on growth capital projects and for the year we expect to invest approximately $3.7 billion in growth capital, primarily for our Haynesville and Eagle Ford projects. Currently we have accumulative investment of approximately $2.3 billion on major growth capital projects not yet completed. In the fourth quarter of this year, approximately $1.4 billion of this will roll off, as we bring the Haynesville extension pipeline into service. Sustaining capital expenditures were $84 million this quarter and $137 million for the first six months. We still expect to spend approximately $250 million to $260 million for sustaining capital expenditures this year.

Moving to capitalization. Adjusted EBITDA for the 12 months ended June 30, 2011 was $3.4 billion. As a reminder, we define adjusted EBITDA as EBITDA less equity earnings plus actual distributions received from unconsolidated affiliates. Our balance sheet is transparent. What you see is what you get with approximately 99.4% of our total debt being on the face of our balance sheet. Our consolidated leverage ratio of debt principal to adjusted EBITDA was 3.92 times for the 12 months ended June 30, 2011, after adjusting for the 50% equity treatment of the hybrids. Our floating interest rate exposure is approximately 13% of the total debt portfolio. The average debt life was ten years using the first call date for the hybrids and our effective average cost of debt was 5.5%.

At June 30, 2011 we had consolidated liquidity of approximately $2.2 billion, which included availability under EPD's and DEP's credit facilities, as well as unrestricted cash. Later today EPD will launch the formal syndication of a $3.25 billion five year bank credit facility. We've already received $3.2 billion of written commitments from our largest banks for this new facility. This facility will replace EPD's existing $1.75 billion credit facility, which matures in the fourth quarter of 2012. We would like to take this opportunity to thank our bank group. They've been a strong and consistent supporter of our partnership.

Now turning to Duncan Energy Partners. This quarter DEP had $33.8 million of distributable cash flow, which provided 1.26 times coverage of the $0.46 per unit cash distribution that will be paid tomorrow, August 10 to unit holders of record on July 29. Cash flow from fee-based assets enabled us to increase the cash distribution to our partners for the 11th consecutive quarter. DEP had total liquidity of approximately $394 million at June 30, 2011, including availability under its revolving credit facility and cash. With that, Randy, we're ready for questions.

Thank you, Bryan. Sara, we're ready to take questions now.

(Operator Instructions) Brian Zarahn with Barclays.

In your onshore crude oil business can you give a little more color on the gross operating margin given the volume decline. Talk a little bit more about the marketing contribution to the segment?

This is Mark Hurley. We had both good results on both the transportation side and the marketing side, mainly around the shale plays in South Texas and West Texas and so all of those volumes were up and really volumes were only down on Seaway, elsewhere in the system we hit record volumes on all of our pipelines. The marketing side was helped due to the fact that pricing was supported by very strained logistics in the systems, as well as strong demand for the crude coming out of those markets along the Gulf Coast.

Do you expect those fundamentals to continue for the rest of the year? This is a very high-performing quarter for onshore crude oil business.

I think it will continue to be a strong business environment for the rest of the year. We had some contango opportunities in the second quarter. Those really aren't there now, but I do think overall the business climate will be pretty strong.

I appreciate the color on the Cushing to Houston pipeline project. Can you give us any little more detail as to discussions with shippers on this project?

Really not beyond what we've already indicated. We're coming up on the end of our opening commitment period this Friday and we'll see how that shakes out.

And then the final question from me is incremental cash flow should be quite strong from the Eagle Ford and Haynesville projects. What are your thoughts looking out to 2012 on distribution growth? Are you still leaning towards running very high coverage or is there a chance you could see a little bit higher bump in the distribution?

Well, I think there's two things here. One is that we continue to have a lot of opportunities to invest in new projects and to the extent we can retain some of that cash flow for investment it lightens our need to go back to the capital market. Second, if you look at the second quarter our distribution coverage, excluding the sale of those ETE units, was 1.2 times. As we said before, we look at it every year and every quarter, what is our excess distributable cash flow, what is our need for capital for our growth projects and we determine our distribution based on that. But, I wouldn't expect any dramatic changes in what we've been doing.

Thanks, Mike.

Bradley Olson with Tudor, Pickering Holt.

So, on the project you guys mentioned to take ethane from the Marcellus down to the Gulf Coast, do you have any thoughts about -- there's been kind of a vague cryptic announcement from Shell about a potential cracker up there and there's been a discussion of back hauling some of that stuff to Sarnia as well as a project which is currently going through an open season. Do you guys, looking at the size of the market up there, have a feel for how big that market could get? Could it be 150,000 barrels a day of ethane and do you think there's enough room for all of these projects or do things have to start getting bumped?

This is Jim. We think there's room for those projects. We think that the project to Sarnia probably has to go. It's only about 40,000 barrels a day. We think the opportunity is north of 150.

That's helpful. Thanks. And as far as propane exports, you guys mentioned year-over-year volumes. Have those trended upwards quarter-over-quarter or have you kind of hit the ceiling in terms of capacity on the Houston ship channel?

We pretty well hit the ceiling on what we're capable of loading, which is why we have got an expansion underway.

Great. Just one last question and this is kind of hitting on what Brian hit on. As far as the crude segment, I realize that there's a high premium being paid for trucking services, especially in West Texas and the Eagle Ford, but can you guys just roughly break out how much of the performance in crude comes from gathering pipelines versus kind of pipeline alternatives like trucks?

We don't get down to that level of detail, but I would tell you that the reason that we're doing it in trucks is because we're building pipelines that will ultimately go in service and take that capacity. Whether you're picking it up in trucks or you are doing it through a pipeline and benefiting from downstream storage, I think that we've got a pretty consistent story.

And so ultimately you guys are seeing that the pipelines actually supplant the truck volumes?

Yes, certainly the trucking transportation is kind of an integral part of what is going on now, but pipelines are being extended and gathering systems are being built to replace a lot of that truck transportation.

So if I'm planning on buying a truck and driving it down to the Eagle Ford you're telling me I should probably hold off.

Buy a truck and we'll hire you.

Okay. Thanks a lot for the color, guys.

And you'll get a lot of work over the next year.

Darren Horowitz with Raymond James.

Jim, with Pioneer back up and running and getting better ethane recoveries, is it correct if I'm assuming that you guys are getting north of 60% of your equity NGL barrels coming from the Rockies?

It's a big percentage, I don't know if it's 60%, Darren. Is that right?

Yes, you're in the ballpark.

And then I'm trying to get a sense, because I know there's been a shift to more fee-based processing revenue versus POL. As I'm thinking about what is coming out of the Rockies, do you have that mix?

We don't have it in front of us, Darren, can Randy get back to you with that.

Yes, it's no problem. Jim, I'm curious as to how you're thinking about that 10% of US ethylene capacity that's forecast to be offline in September and October for planned maintain. It seems like just looking at the data that spot ethylene prices have run in advance of a lot of these big turnarounds. So, I am curious as to your thoughts on what impact you think that could have on ethylene prices In the back half of this year.

Of course, we watched that ethylene market and we've seen that ourselves and think that the demand for ethylene is being played out in the prices and we think it's -- we think it's reflective.

You think it's possible that we see north of one million barrels a day of ethane demand.

Not instantaneously in the fourth quarter, because of the outages. But it's important to note that those outages are not ethane only crackers, they're mixed feed crackers as well.

I appreciate the color, guys, thanks

John Tysseland with Citigroup.

Can you give us a little more color on the derivatives gain in the natural gas marketing group and maybe provide kind of what the intention was for entering that position and what happened to generate that amount of upside.

John, let me touch on it briefly and I'll let Chris get in more detail. There's about an $18.2 million gain on derivatives that we look at as economic hedges. They just don't meet the requirement that you need for hedge accounting.

That's exactly it. Mike hit it right on the head. It's mostly from our northern border position. It's the [Aco] to Chicago spread. We've laid off that risk on the northern border contract for the next two years and we have that spread on at more than covering all our costs and the spreads have come in drastically in the market and there's been some liquidation in the basis market with the volatility here. What we locked in as a $0.60 spread is now currently getting marked inside well of $0.30 and you're realizing that money thanks to our former friends in the business that started mark-to-market accounting.

John, we kind of look at this as not letting accounting drive our business. So if we can put on an economic hedge, even if we don't get the hedge accounting, we're going to do it because we think that's the right thing to take risk out of the business and that's worked. We've had some mark-to-market losses in previous periods, but since they are economic hedges they're going to turn around and this is indicative of what happens.

So if that spread winds back out, should we expect a loss or is that position pretty much closed now?

It will be a mark-to-market loss. It won't close until they roll off. So each month the contract goes to its expiration it will roll off at that point and time. That's mark-to-market accounting in its purest sense. It's stupid, but it's the rule. (laughter)

You don't (inaudible) higher period that those hedges are in place. The net effect of the mark-to-market gains and losses is you're going to have some gains.

Well said, Chris. Thanks for the color on that. (laughter) And then also, on the -- Jim, can you provide some detail on how you look at the propane export market and how deep that market is. I mean, is it really as easy as the more we produce, the more we can export or is there any kind of limitation on that capability?

I think it all comes back to the gas to crude spread, which makes this an attractive market to source LPG from. And to give you some flavor and I'm going to look Lynn, I think we're sold out through next year.

We're sold out through 2012. We're continuing to sell through 2013 and beyond. We continue to have inquiries in. I would say the market is sufficiently deep to absorb the expansion that we have coming on-line at the start of next year.

That's sold out even on the expansion, correct?

We're not fully sold out on the expansion in the far forward market. We're going to be sold out on the front part of the market. I shouldn't say sold out, we have a tremendous amount of interest for the expansion capacity on the front end of that.

And then you've got some interest in multi-year contracts?

We've done some multi-year contracts and we're talking with most parties about multi-year contracts for that expansion.

Are there any optimizing profits through those exports or is it purely a fee-based at this point?

It's fee-based.

And then lastly, and I will wrap it up, is, Jim, are you seeing any kind of destocking given recent volatility that you've seen in the markets. I mean, obviously, things have been weak for a little while. Obviously, the markets being extraordinarily weak over the last week. Have you seen any destocking activity from the petchems here recently or are they still just a low cost feedstock provider and running full out at this point?

We haven't seen them back off on their run rates, of course, we're two weeks into this mess. So we'll see.

I think the latest En*Vantage report indicated maybe there had been some destocking in China, but that may be short term.

Okay. Thanks, guys, appreciate it.

Ted Durbin with Goldman Sachs.

Wondering if you can just talk a little bit about the Marcellus pipeline more. What are you physically doing to move down there and then assuming you're using existing pipe, what kind of revenues or what not might you be foregoing by actually moving ethane on the pipe?

This is Jim Collingsworth. From a conceptual phase or scope, project scope we're going to be laying about 640 miles from the Mark West plant, if we get the project done, back to about the Calvert City area where the Westlake cracker is and then we'll take the existing 16 inch TEPPCO line and reverse that so we can go back into Mont Belvieu with the ethane. It's way too early in the project now to talk about revenues.

I think what he's talking about is, are you losing any revenues and I think the answer to that is no.

We'll use our Centennial loop to get the other products that we can't move in the 16-inch back up into the marketplace and distribute it.

I see. That makes sense. And just thinking about modeling here on the Acadian pipeline as you bring it on. Will it start up full. Is there any timing that we should plan for over the new few quarters as that comes on?

This is Chris. You're going to see a slow ramp up here in the month of September as we go online, but starting October 1 and for the next ten years it's all demand. 99.3% demand charges about 7/10 of 1% commodity. Pretty steady state and it's good, solid, backed by companies.

Got it, thanks, Chris, and then last one just if you could comment a little bit more on the recent market volatility. How does that make you think about liquidity, financing and maybe even potentially acquisitions?

Well, with acquisitions that's not been high on our list for some time. From time to time we're opportunistic and we find assets that fit us that may not fit somebody else. But, frankly, those few and far between and pretty small in dollar size. In terms of liquidity, we finished the quarter with a little over $2 billion of liquidity. As Brian indicated, we're going out today for a $3.25 billion revolver, so we'll have additional liquidity there. And we've already got commitments for $3.2 billion of that. I think we're going to be okay there. And just in terms of our continued growth, we finished the quarter again at under four times debt to EBITDA, so we're pretty comfortable with that. When Haynesville comes on it should help us to lower that a bit. Frankly, we feel petty good about where we are. We've done all that this year without raising the equity. We have sold some of our ETE holdings and that helps. But we think that this market uncertainly right now is more reflected in the equity markets. It seems that there's still plenty of liquidity in the banking system and plenty of appetite for our paper.

Okay, that's it for me. Thanks.

Ross Payne with Wells Fargo.

First question is are you seeing much of a shift to more fee-based maybe out of the Rockies in particular and second of all, with the number of NGL lines coming in that have been announced kind of from the Permian to Mont Belvieu, how do you kind of view that potentially impacting your system?

I think from a fee-based -- this is Jim, Ross. From a fee-based prospective you couldn't get a keepwhole contract right now if your life depended on it. The producer wants that exposure, which is fine with us because that gives us certainty. In terms of all of the announcements out of the Permian and wherever --

Jim, what I would say Ross, is how it impacts our system was the question. You look at our system and our tariffs are $0.015 to $0.02 a gallon to get from West Texas to Belvieu. The economics on all the new systems are going to need something north of $0.045. So I think we'll stay full and on allocation.

Sounds good. All right, thanks, guys.

John Edwards with Morgan Keegan.

Just could you repeat -- I think you mentioned what the growth CapEx you were expecting now for the year. I didn't catch that.

For the balance of the year?

For the balance of the year.

$1.6 billion.

And then --.

I had it backwards, John. We said $1.6 billion, we have got $2.2 billion left.

$2.2 billion left, okay. All right and then just on the propylene, I think you came down from the record from 60 to 31. Is that basically kind of a better run rate now looking forward?

I don't know if it's a better run rate. I kind of liked the old one. Unrealistic to say that.

Is that more realistic?

Yes, last year was unbelievable. That's what it boils down.

And then the equity NGL production was down a little bit year-over-year. Could you give a little more detail on why that happened, because obviously we're expecting that.

I think equity NGL production was down 5,000 barrels a day for the quarter. 4,000 barrels a day of that was because of the downtime at Pioneer.

All right, so you're expecting that to basically ramp back up?

Yes. And then to the extent we have higher ethane extractions we may get a little bit more out of it in of.

And then is frac VI already sold out?

Yes. If I look at what we expect from the Eagle Ford, we'll be full on frac VI, Tom?

Yes.

Great, that's all I had.

Becca Followill with US Capital Advisors.

Back to Marcellus pipeline. People have been talking for years about an ethane solution, yet the producers haven't been willing to commit. Do you see a greater sense of urgency or the producers finally coming to the table?

We're beginning, Becca, to see people that we were talking to once a month we're now talking to three times a week, how's that?

That's good. But what is driving their change?

The reason we're seeing the behavioral change is they were so focused on the short-term problem they had, they needed to solve a 30,000 to 40,000 barrel a day problem. They've done that with the Sun Line going to Sarnia. So now they're focused on the long-term issue.

And for them to finally commit do you think we're three months away, six months away?

Yes. (laughter)

Which one?

I'm very encouraged that we're going to get this put to bed pretty soon.

Okay. Thank you.

Michael Blum with Wells Fargo.

Question on the ethane, the potential ethane header project. Would you be looking for commitments from the petrochemical guys or the producers to move forward with that project. And if you did, ballpark what kind of capital would you need for that?

Well we're probably not going to give you the capital, Michael, but it's not as much as what the size of the system would indicate in that we're using a lot of existing pipe, swapping services. You're probably looking to the petrochemicals to make the commitments on that, but it's reflective of how we think. I mean it's a standalone project regardless of Marcellus, but we focus always on giving the producer and the consumer a solution to the end use market.

And then, Jim, the other question I had was if we are heading into a period of weaker economic environment, both globally and also domestically, how do you think that's going to change the petrochemicals decision making process in terms of whether they're going to go head with new steam crackers in the Gulf Coast and the timing of that?

Who knows, but I think expansions can continue. It really boils down to you're going to have some ethylene produced, how competitive are you globally and the situation here is they're extremely competitive and so it's not necessarily these crackers that turn back. Back to your previous question, they'll just nudge me on that ethane header system. Only about 30% of that entire system is new pipe. Maybe somebody defers a new bill, Michael, I don't know. I do know this. Just in the Dow Chemicals case and they made the announcements just on expanding existing crackers they can add 85,000 barrels a day of ethane demand.

And (inaudible) have to be looking forward because these things don't get built right away. It takes a pretty long lead time.

Great, thank you.

(Operator Instructions) Yves Siegel with Credit Suisse.

If I could just ask you about that ethane header system again, what is the industrial logic in terms of the demand side of the equation. Is it just to give the crackers the optionality to get supply or how do you think about the market need?

We think about making money --

The old-fashioned way.

As these guys expand, they are lacking the infrastructure to access the ethane beyond what they currently use. We think that this system has the wherewithal to give them access to that ethane. It's a pretty neat system when you think about it. I was pretty proud of the guys to come up with the concept. When you have an ethane header from Corpus Christi to the Mississippi River and tied to a huge storage location that takes Y grade from all over and produces a heck of a lot of ethane, that's sexy as heck when you think about the ability to just float on that system.

And how do you see your role within that? Will you help contract for the supply or will you just be the transportation conduit?

We'll do either.

Just make money.

You notice how things are sexy at my age that ordinarily wouldn't be?

I'm not going to go there. And then two other quick ones. As you look at the potential size of the capital budget in 2012, what ballpark number do you think we'll be at?

It's kind of hard to say, Yves, I think we have got about $2.5 billion targeted for 2012 of approved projects today.

Of that, how much is just completing projects from this year?

Over half.

Yes. Okay and then my last question is when you look at the credit facility that you're negotiating, any significant change in the terms that you're looking at?

No. No, there aren't. It's pretty much the same structure, a five year structure, pricing will be closer to what market is today versus what it was pre-Lehman crisis.

That means it's a little bit more expensive.

Right.

Thanks, guys.

At the time there are no further questions.

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