Enterprise Products Partners LP (EPD) 2009 Q4 法說會逐字稿

Welcome to the Enterprise Products Partners and Duncan Energy Partners fourth-quarter earnings conference call. Thank you for standing by. (Operator Instructions). I would now like to introduce Mr. Randy Burkhalter, Vice President of Investor Relations. You may begin.

Thank you. Good morning and welcome to the Enterprise Products Partners and Duncan Energy Partners conference call to discuss fourth-quarter earnings. Our speakers today will be Mike Creel, President and CEO of Enterprise and General Partner; followed by Jim Teague, Executive Vice President and Chief Commercial Officer, and Randy Fowler, Executive Vice President and Chief Financial Officer will follow Jim, and then Hank Bachmann, President and CEO of Duncan Energy Partners and General Partner, will be our last speaker. Also in attendance for the call today is Dan Duncan, our Chairman, as well as other members of our senior management team. Afterward we will open the call up for 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 by and information currently available to Enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the Securities and Exchange Commission for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call.

And with that, I will turn the call over to Mike Creel.

Thanks, Randy. Good morning and thanks for joining us today. Being mindful of your time and your interest in the current business environment, as well as our growth opportunities, we are going to limit our discussion of items that are covered in detail in our earnings press release this morning. If you have questions on these items, obviously we will be happy to address them in the Q&A.

We are pleased to report another quarter of strong operating and financial results supported by record NGL, crude oil and petrochemical transportation volumes, record equity NGL production and fractionation volumes and increased natural gas transportation volumes. We continue to benefit from our large geographical footprint and our diverse portfolio of integrated businesses that generated record gross operating margin and distributable cash flow for 2009. Based on our continued strong performance, the board approved an increase in the quarterly cash distribution rate to $0.56 per unit, a 5.7% increase over the rate paid with respect to the fourth quarter of 2008 and our 22nd consecutive quarterly distribution increase. Enterprise generated distributable cash flow of $570 million in the fourth quarter of 2009, providing 1.5 times coverage of the distribution declared with respect to that quarter. We retained $164 million or 29% of the distributable cash flow for the quarter.

Distributable cash flow for the year was a record $1.6 billion and provided 1.2 times coverage of the $2.20 per unit declared with respect to 2009, allowing us to retain $264 million for the full year for reinvestment in our business. Since our IPO in 1998, we have retained over $1.1 billion or approximately 15% of the partnership's distributable cash flow. This compares to $783 million paid to our general partner over that same period. I'm not aware of any other MLP that has retained more cash than they paid to their general partner over such an extended period of time. We had record gross operating margin of $865 million in the fourth quarter of 2009. This is a $214 million or 33% increase over the fourth quarter of 2008. Our NGL pipelines and services business was responsible for $157 million of this increase. This segment benefited from record NGL pipeline and fractionation volumes and record aggregate NGL production. Higher natural gas processing margins increased demand for NGLs as a petrochemical feedstock over more costly crude oil derivatives, profits from NGL sales that were completed in the fourth quarter and the settlement of the Mid-America rate case and demand for our NGL export facilities were among the key drivers.

Fundamentals continued to be strong for this segment as we began 2010. Industry NGL inventories are low, particularly ethane, and demand continues to be high resulting in strong natural gas processing margins. Jim Teague will discuss this in more detail a bit later.

Gross operating margin for the onshore natural gas pipelines and services segment declined $27 million in the fourth quarter of 2008, primarily due to our natural gas marketing business and lower gross operating margin from our San Juan, Val Verde, and Carlsbad systems due to lower volumes and higher operating expenses. Our natural gas marketing business was primarily impacted by demand charges for transportation and storage capacity in combination with unusually tight basis of natural gas prices across the country. Some of this will be recouped in the first quarter of 2010 as we delivered gas volumes we owned from storage and recognize profits. Our Texas Intrastate System benefited from the Sherman extension being in full service for the quarter which was partially offset by lower pipeline volumes. Gross operating margin for the offshore pipelines and services segment increased by $44 million or 81%. This included $22 million of insurance recoveries related to hurricanes and the flex-joint repaired independence hub and a $28 million increase in gross operating margin from our offshore crude oil pipelines. The improvement in the results of our offshore crude oil pipelines was primarily attributable to the Shenzi Pipeline, which began operations in April of 2009 and the restoration of service by crude oil pipelines that were negatively affected in the fourth quarter due to Hurricane Ike. The petrochemical and refined product segment reported a $25 million or 30% increase in gross operating margin for the fourth quarter of 2009. Our refined products pipelines and octane enhancement business were responsible for most of this increase. Our butane isomerization and propylene fractionation businesses also had solid quarters.

The integration of the former TEPPCO businesses has gone well with almost all of the management and organizational changes being completed within a week of the merger. We previously stated that we expected about $20 million of immediate synergies almost exclusively from the elimination of redundant public company costs. In addition, we have taken action to capture approximately $35 million per year of opportunities either to increase revenues or reduce expenses that have not been previously identified, including revising tariffs on the Enterprise refined products pipeline system, electing to process certain volumes of natural gas on the Val Verde system and realizing lower interest costs on the $1.1 billion of debt we issued in October of last year. We believe there are more commercial opportunities available to us that would have been difficult to capitalize upon prior to the merger. We also believe that TEPPCO assets will provide additional growth opportunities as we seek to expand their scope and scale. Combining our $164 million of retained distributable cash flow from the fourth quarter of 2009 with the proceeds from our equity offering in the first week of January, we are in a strong position to begin funding our capital investments in 2010 with approximately $2 billion of liquidity.

Our board adopted equity ownership guidelines effective January 1 of this year that require our directors and executive officers to own significant amounts of Enterprise common units within three years. Most, if not all of our executive officers probably already meet this requirement, but the board and management felt it was important to show our commitment through our continued ownership of equity in the partnership to reinforce our alignment of interests with those of our public unitholders.

Before I turn the call over to Jim, I would like to say once again how pleased we are with the strong results for the quarter and for 2009. Our employees have done an outstanding job in a stressful business and economic environment, and the Enterprise management team has done a remarkable job of quickly and efficiently integrating the TEPPCO businesses within Enterprise. We believe for the foreseeable future we have great opportunities to deploy capital to expand our integrated midstream system, including 48,000 miles of pipeline through organic growth. We believe organic growth will continue to offer greater returns on capital than acquisitions of discrete assets. Recently we were told there are 24 private equity teams chasing acquisitions in the midstream space. It sounds like the acquisition market is going to be expensive again and probably will rely on leveraged returns. We believe our focus on the organic growth available to us around our system and managing our cash cost of capital will continue to enable us to provide our partners with growth and distributable cash flow per unit.

And with that, I would like to turn the call over to Jim.

Thank you, Mike. What a difference a year makes. This time last year when we were reviewing December 2008 and the fourth quarter 2008 we were faced with the WTI crude price of $41, Henry Hub natural gas at $5.80 or 81% of crude on a BTU basis.

In December of 2008, the annualized production of ethylene from US ethylene producers was 34 billion pounds, as low as I have seen it in 20 years. They were consuming 546,000 barrels a day of ethane, a total of 700,000 barrels a day of total NGLs. Ethane was selling at $0.355 a gallon. Our processing margin at Meeker was $0.04, and we were in rejection much of the month of December of '08, and ethane inventories were growing rapidly.

As we come out of December of '09, we came out of a period where natural gas was selling relative to crude oil at 41%. Ethylene annualized production in the month of December was at 51 billion pounds, and ethane use in petrochemicals was 840,000 barrels a day. Total NGL used almost 1.3 million barrels a day. Our processing margin at Meeker on ethane was $0.50 a gallon, and ethane inventories were being drawn dramatically, reflecting the fact that petrochemicals were consuming more than the US NGL business could produce. We believe changes in the price relationships of crude oil, crude oil derivatives, natural gas and NGLs in the past year have led to a long-term structural change in the petrochemical industry. Natural gas and NGLs enjoy a significant price advantage of more costly crude oil derived feedstocks. This has been driven by a decline in global crude oil production, more acreage being off-limits to the private E&P sector, geopolitical risk, growing demand for crude by China and other developing nations, the globalization of natural gas prices and more LNG facilities becoming operational, and in my mind, most importantly, the technological breakthroughs around the development of natural gas shale plays in the US.

For US producers this has meant that ethane and propane were their most consistently profitable feedstocks in 2009 and are forecasted to be sold this year. The feedstock cost advantage and a weak US dollar provided US ethylene producers with a competitive advantage globally, especially relative to naphtha crackers in Europe and Asia.

According to CMAI, approximately 24% of 2009 domestic production of high density polyethylene, low density polyethylene and PVC were for the export market. US ethylene producers responded, they rationalize some of their facilities and invested capital to modify their traditional naphtha crackers cracking furnaces to crack more NGL feedstocks. We estimate that domestic crackers are in the process or have added approximately 100,000 barrels a day of new capacity to crack ethane and propane through modifications to their traditional naphtha cracking furnaces. We have worked closely with these customers to provide them with incremental supplies of ethane and propane and related logistical services.

In addition, the international ethylene crackers have reacted to the NGL feedstock cost advantage by importing LPG to traditional naphtha crackers. Since July of last year, our LPG export terminal in the Houston Ship Channel has been fully utilized, exporting approximately 3 million barrels per month of LPG primarily propane, that either directly or indirectly supplied a portion of traditional naphtha crackers for use or substitution of LPG to other parts of the world. Export ethylene derivative demand remains strong in early 2010, but as Middle East production increases, US export volumes are expected to slip. Chemical margins in the US are forecasted to compress due to increased competition, but overall demand for domestically produced ethylene is only expected to slip about 1.5% in 2010 according to CMAI and then increase almost 2.5% back to 50 billion pounds a year or greater in 2011. With a global recession abating, domestic demand is forecast to increase consuming the production that was going overseas in 2008 and 2009.

And new ethylene capacity in the Middle East has received a lot of attention due to the low-cost feedstock advantage over production in other regions. Along with the low-cost stranded ethane, however, a significant amount of propane and heavier feedstocks, primarily natural gasoline, will also be used by the Middle East crackers. Those feeds are actively exported and are valued to those Middle East crackers based on international pricing. As a result, Middle East propane feedstock costs are significantly higher than cracking stranded ethane and are nearly at parity with US ethane cracking economics according to CMAI. Middle East production will undoubtedly affect US crackers, but we believe the cost advantage of cracking light feedstocks, the return of domestic demand growth and our continued competitive position in the international marketplace will keep US ethylene production steady to growing over the coming years. We at Enterprise are well positioned to help the US chemical industry remain competitive by providing reliable NGL feedstock supplies and services. We are planning for the future by increasing our frac capacity, expanding our natural gas pipeline and processing infrastructure and growing our distribution networks.

During the fourth quarter, ethylene plants operated at an annual production rate of approximately 52 billion pounds, which equals the average production rate for the last five years. Ethane demand was approximately 860,000 barrels a day for the fourth quarter, the highest since the fourth quarter of 2000. We project daily ethane volumes could be up to 900,000 barrels per day, and we have already seen it happen a few days in January. We think there is a 30,000 to 40,000 barrel per day shortfall between current NGL production and cracker demand. Consequently this is pulling ethane inventories down rapidly.

Fractionation capacity remains tight. Our fractionators at Mont Belvieu and Hobbs are running at full capacity with overflow volumes going to our Louisiana fractionators. Our fractionation volumes have increased by more than 50% over the last three years, and additional capacity will be needed to accommodate NGL volume growth expected from the emerging shale plays. We announced construction of a new 75,000 barrel per day fractionator at Mont Belvieu similar to one we built at Hobbs in 2008. Construction of that fractionator should be completed this time next year. Additional capacity may be needed to accommodate incremental volumes that we see from production out of the Eagle Ford shale play in Southwest Texas.

A question we frequently have gotten from our investors over the last nine months has been, what have you done to hedge natural gas processing margins for 2010? The issue that has frustrated our efforts for 2010 is that forward natural gas prices have typically been in contango, while forward NGL prices have been backwardated, which compresses that forward processing spread. Then when the production month arrives, the natural gas processing spread increases either because natural gas goes down or NGL prices go up. We made the decision that we were going to be patient waiting for opportunities to hedge. That patience has begun to pay off. Recently we took advantage to hedge approximately 28% of our 2010 equity NGL production at attractive levels. Most was for the first and second quarters. Approximately 25% of our Rockies keepwhole production has been hedged at a gross margin of around $0.60 a gallon. About 43% of our percent-of-liquids production has been hedged at NGL prices averaging between $1.25 and $1.30 per gallon with about half of those barrels being hedged being butanes and natural gasoline. We are going to continue to be patient, continue to look for opportunities to put on additional hedges.

We are also excited about our Haynesville extension pipeline we announced last October. Originally it was designed as a 36-inch, 1.4 Bcf a day natural gas pipeline to extend our Acadian system into the Haynesville shale play in North Louisiana. However, the amount of long-term commitments we received exceeded the capacity of the 36-inch line. So in December we announced that we would increase the size of the extension up to 42 inches with an ultimate capacity approaching 2.1 Bcf. With the Haynesville extension serving as a backbone trunk line through the heart of the play, we believe more producers will come to us to provide them transportation gathering and treating services. We also have the flexibility to provide producers northbound capacity on the 42-inch extension to reach the corridor of competing pipelines going east to Perryville on which many producers have commitments. More importantly, we provide producers with exclusive southbound capacity to get them to the interstate pipeline such as Florida gas, Transco, TEPPCO, as well as end use markets in South Louisiana. We think this will provide producers with higher net backs because we think there is a going to be a glut of gas at Perryville. We also believe producers like the flow insurance offered by this pipe by directly connecting to the Mississippi River corridor industrial market. We expect to complete this pipeline in September of 2011.

Another exciting area is the emerging Eagle Ford Shale play in South Texas. We have an extensive network of natural gas, NGL and crude oil assets in this region, including pipe that goes through the heart of the play. Our goal is to participate in all aspects of the Eagle Ford -- rich and lean gas, crude oil and condensate. We have already completed approximately $60 million of projects that will bring 300 million cubic foot a day of Eagle Ford natural gas into our system and top off our South Texas natural gas processing plants. We are now proceeding with a 34-mile, 24-inch diameter pipe, which is the first segment of a major east-west Eagle Ford Shale mainline.

The Eagle Ford is more than a natural gas play. It will produce NGLs, crude oil and condensate. Some of the gas will be extremely rich averaging 4 to 9 gallons of liquids per Mcf. This gas will need to be processed, and NGLs will need to be fractionated and transported to market. We will be incrementally expanding our system to provide midstream services. The key will be to stay ahead of the producers who have had early success and in some cases are accelerating their drilling programs. We are evaluating the meeting and timing for additional NGL gas pipeline and processing and NGL pipeline infrastructure.

Earlier Mike mentioned the commercial opportunities from the integration of the TEPPCO businesses. We hit the ground running after the merger closed. We incorporated our value chain philosophy around TEPPCO's businesses and assets. As Mike mentioned, we have had early success, but we believe there's much more to come.

We realized as we put this together that we needed additional expertise to run and expand some of the TEPPCO businesses. In January Mark Hurley has agreed to join us as Senior Vice President of our onshore and offshore crude oil transportation and storage assets, as well as our offshore platforms and natural gas pipelines. Mark has a great reputation in our industry, and he is going to fit in great with our team of result-oriented culture. Mark has served as President of Shell pipeline company from 2005 to 2009. His understanding of all aspects of the crude business and his knowledge of natural gas, NGLs petrochemicals and refined products will be important as we look to capitalize on new opportunities. Mark will be on board March 2. As you can tell, we are pretty excited by our prospects and continue to grow enterprise.

Now I will turn the call over to Randy.

Thank you, Jim. I will briefly discuss some noteworthy income, liquidity and capitalization items. As Mike mentioned, I will skip items where we provided detail or various analysis in the press release. If you have any questions, we will cover those in Q&A.

G&A expense for the entire year of 2009 increased by $35 million to $172 million on a recast basis. Approximately 28% of this increase was merger-related costs incurred by both Enterprise and TEPPCO. The provision for income taxes for the fourth quarter of 2009 was a benefit of $1.5 million compared to a tax expense of $11 million for the fourth quarter of 2008. Accruals for the Texas margin tax decreased by $11 million this quarter compared to the fourth quarter of 2008 due to less earnings being attributable to Texas. We expect to invest approximately $1.5 billion for growth capital expenditures and another $250 million on sustaining capital expenditures in 2010. Some of the larger approved capital projects for 2010 include the Haynesville extension pipeline, the Mont Belvieu NGL fractionator, the Trinity River basin lateral and projects in the Eagle Ford. We expect sustaining capital expenditures will be abnormally high in 2010. This is mainly related to some larger pipeline integrity projects, including $17 million for the Tri-State's NGL pipeline, and as well as $6 million to build a new substation in Baytown. We expect 2011 sustaining capital expenditures to return to a more normalized level of $210 million to $220 million. Of note, if you look at Enterprise and TEPPCO capital expenditures in 2008, sustaining capital expenditures, were approximately $235 million.

Adjusted EBITDA for the 12 months ended December 31, 2009 was $2.7 billion. Adjusted EBITDA is defined as EBITDA less equity earnings plus actual cash distributions received from unconsolidated affiliates. Our consolidated leverage ratio of debt to adjusted EBITDA for December 31, 2009 was 3.9 times with debt being adjusted by 50% for the equity content in the hybrid junior subordinated debt securities.

Our floating interest rate exposure was approximately 12% at the end of the fourth quarter. This is a little lower than our typical high teens to 20% level due to the application of proceeds against our revolver that we received from our recent equity offering and working capital that was returned to us in the fourth quarter as forward sales of natural gas liquids were settled. The average tenure of our debt was nine years, which incorporates the first call date for the hybrids, and our effective interest cost of debt was 6.1%. We have $554 million of debt maturing in 2010, which includes a $54 million 8.7% note due March 1 and a $500 million 4.95% senior note due in June 2010. As Mike mentioned, we had liquidity of approximately $2 billion to begin 2010.

With that, I will turn the call over to Hank Bachmann to discuss Duncan Energy Partners' quarter.

Thank you, Randy. I'm pleased to report record results for Duncan Energy Partners in 2009, our second full year of operations, supported by yet another quarter of strong operating and financial performance of our businesses.

At the time of our IPO in 2007, we told prospective investors that we expected our annual cash distribution growth rate to range from 2% to 3%, and a year later at the time of our second drop-down transaction in December 2008, we stated that we expected our annual distribution growth rate to be around 3%. This year we were able to exceed both of these goals by increasing the cash distributions declared with respect to 2009 by 4.3% over those declared for 2008.

In 2009 our partnership benefited from cash flow generated by the DEP II businesses, which we acquired from Enterprise products in our second drop-down transaction in December 2008. In 2009 these businesses generated $86.5 million of distributable cash flow or an average of $21.6 million per quarter based on our 11.85% preferred return in 2009, which will increase by 2% to 12.09% for 2010.

As a result of our increased preferred return in 2010 on our $730 million investment in the DEP II mainstream businesses, we expect to receive distributable cash flow from these businesses of at least $22 million each quarter in 2010.

Turning to our fourth-quarter 2009 results, we reported net income attributable to Duncan Energy Partners of $23.2 million or $0.40 per common unit on a fully diluted basis compared to $10.7 million or $0.39 per common unit on a fully diluted basis for the fourth quarter of 2008. The DEP II midstream businesses contributed earnings of $13.7 million in the fourth quarter of 2009 compared to $4.5 million in the fourth quarter of 2008.

It should be noted that the fourth-quarter 2008 results for the DEP II business included only the 24-day period from the closing date of the DEP II drop-down transaction December 8 to December 31, 2008.

Distributable cash flow for the fourth quarter of 2009 increased to $34.5 million from $15.6 million for the fourth quarter last year, again resulting primarily from the $16 million increase from cash distributions received from the DEP II businesses, which we owned for the entire fourth quarter of 2009 versus only 24 days in the fourth quarter of 2008.

On January 12, 2010, the Board of Directors of DEP's general partner declared a quarterly cash distribution rate of $0.445 per common unit, which represents a 4.1% increase from the 0.4275% common unit paid with respect to the fourth quarter of 2008. It represents the fifth consecutive increase in the quarterly cash distributions paid to our partners. Distributable cash flow for the quarter provided 1.3 times coverage of this increased cash distribution.

Now I would like to briefly discuss the performance of our segments for the fourth quarter of 2009. Gross operating margin from our onshore natural gas pipeline business segment for the fourth quarter of 2009 increased 16% quarter over quarter to $38.7 million from $33.3 million recorded in the fourth quarter of 2008. The partnership's Texas Intrastate System contributed $3.4 million to the quarter to quarter increase, primarily as a result of higher firm capacity reservation fees from the Sherman extension pipeline, which began full commercial service in August 2009. This was partially offset by lower revenues from a decrease in firm and interruptible transportation volumes on the remainder of the Texas Intrastate pipeline.

Earlier Jim mentioned the Haynesville extension pipeline and the increase in the pipeline's capacity to 2.1 Bcf per day. We are very excited about this project and the fact that we are the only natural gas takeaway route south out of the Haynesville Shale play. This extension of our Acadian system will provide shippers access to the end-user markets along the Mississippi River corridor into nine other intrastate pipelines. Natural gas being shipped on the Haynesville extension pipeline will also have access to Acadian's rapid-cycle salt dome storage cavern located near Napoleonville, Louisiana. It can be physically delivered into the Henry Hub via our Acadian pipeline system. We believe that this pipeline extension project will help continue our growth for years to come.

Our NGL pipelines and services business segment reported gross operating margin of $30.1 million for the fourth quarter of 2009 compared to $25.2 million for the fourth quarter of 2008. After adjusting for measurement gains and losses associated with the partnership's Mont Belvieu NGL and petrochemical storage complex, gross operating margin for the fourth quarter of 2009 increased to $30 million from $28.2 million in the fourth quarter of 2008. The increase is primarily attributable to higher fees and volumes at our Mont Belvieu complex.

As a reminder, operational measurement gains and losses at our Mont Belvieu storage complex are allocated to Enterprise and are reflected on our financial statements as an adjustment to non-controlling interests.

NGL transportation volumes decreased to 110,000 barrels per day in the fourth quarter of 2009 from 124,000 barrels per day in the fourth quarter of 2008, and NGL fractionation volumes were 4,000 barrels per day lower for the fourth quarter of 2009 versus the same quarter of 2008. These decreases were primarily associated with production declines from conventional natural gas production in South Texas. We believe these declines will be short-lived as rich Eagle Ford Shale volumes begin to ramp up.

Our petrochemical services business segment reported a slight increase in gross operating margin to $2.6 million for the fourth quarter. General and administrative expenses were $2.4 million in the fourth quarter of 2009, $1.8 million lower than the G&A expense reported in the fourth quarter of 2008. This was primarily due to higher costs for outside professional services in the fourth quarter of 2008 related to the drop-down transaction we did in December of '08. Sustaining capital expenditures were $11.4 million in the fourth quarter of 2009 compared to $15.7 million spent in the fourth quarter of 2008. For the year we spent $48.4 million of sustaining capital expenditures compared to $54.2 million spent in 2008. Approximately $35 million of the $48.4 million was for the DEP II businesses and as a result had less of an effect on our distributable cash flow because of our preference return.

For 2010 we expect sustaining capital expenditures to be approximately $55 million with the split between the DEP I and DEP II businesses being approximately $20 million and $35 million respectively. We had total liquidity of approximately $120 million at December 31, 2009, which includes cash and availability under our revolving credit facility.

In closing, we were pleased with the performance of our businesses and the record distributable cash flow generated by the partnership, which provided solid coverage of the cash distributions declared in 2009. We are excited about the prospect of additional cash flows being generated from our Haynesville extension pipeline project beginning in 2011 and continued strong performance of our existing assets in 2010 to support future increases in the cash distributions to our partners. And, as I have said in the last few quarters, we are pleased to report yet another quarter of solid results and strong coverage of the cash distributions paid to our partners.

Randy, we are now ready to take questions on Enterprise or Duncan Energy.

Okay. I think we are ready to begin our Q&A.

(Operator Instructions). Mark Reichman, Madison Williams.

Very solid quarter. The Eagle Ford Shale appears to be developing in a very favorable way, and I was just wondering what additional investment opportunities you see developing in that region beyond the projects that you announced? For example, do you see many opportunities to expand the crude oil infrastructure, or is it mainly natural gas and NGL?

I think, as Jim said, we see opportunities in all areas, including the dry and the rich gas, and we are looking at developing our system into a dry system and a wet system to accommodate those streams. But also crude and condensate to the extent that we can attract producers. We certainly have assets that we think are in the right position. We are ready, willing and able to spend money to expand the system, to accommodate their needs.

Jim, anything else to add?

No, that is it.

Okay. And then second I was just wondering if you could elaborate a little bit on -- provide an update on the Acadian gas pipeline, how that project, the development and the financing is being shared between, say, Enterprise and Duncan?

At this point in time, we are still evaluating that split. Duncan Energy owns 66% of Acadian and EPD owns 34%. So I mean it is a good project, and we think good projects are easy to finance.

One of the reasons that is true is because of the ownership of the pipeline between Duncan Energy Partners and Enterprise, it is one of those where we will likely get the audit committees of both partnerships involved to make sure that unitholders are protected.

Okay. And then lastly, the $1.5 billion capital budget for 2010, I was just wondering if you are able to break that out in a little more detail by project and then how that will be spent over the next 12 months?

We do not break it out by project. We have in a couple of press releases talked about some of our capital projects. But the capital will be spent fairly ratably over that time period, maybe a little bit more in the first and second quarters than in the third and fourth quarter. But I would caution you that that $1.5 billion that we referred to really are projects that we have already approved and that we are committed to and does not include new projects that we may find over the course of the year.

Brian Zarahn, Barclays Capital.

It seems like you are making good progress with the TEPPCO integration. Can you give a little color as to what kind of commercial opportunities do you see? Is it in crude oil marketing and storage, or can you provide a little more color?

Well, let me let Jim answer that, but I will just say on the front end that from our standpoint TEPPCO was a bit constrained because of their lack of financial wherewithal to grow their businesses, and, as we have said before, we have the value chain approach and we are looking to apply that to all of the TEPPCO businesses, including the crude oil and refined products business.

I think you said it. We see opportunities for growth in the refined products sector. We have brought some people in. We mentioned Mark Hurley that we brought him in crude oil, but we brought in some people on the refined product side working for Lynn Bourdon to take a look at that and try to extend that value chain. We see crude as an area that we want to grow. We see some opportunities to tie in what Enterprise has with what TEPPCO has to create more of a value chain. So we are going to be pretty focused on the crude section, as well as the refined products area.

Okay. I'm looking at the Haynesville extension. Is the cost estimate still what you believed originally, and can you give a little detail as to what kind of contracts you have with your contractors? Are they fixed-price contracts?

I will jump in. The cost estimate and everything we have not given out a firm number, but we are still on target and where our original intentions were. All the contracts that we have in place with the seven different producers are 10-year agreements. All demand charges with very little commodity, more the intrastate model, it is about 98% demand, 1% or 2% commodity-related. But they are all 10-year firm agreements.

So your costs for steel and labor, are those in your agreements with the contractors, are they fixed price, or are they to control your costs?

As far as controlling the costs, we have all the steel bought at this point in time. We just bought the last segment of steel here last week, in fact. Prices came in surprisingly under what we expected even in the AFE. So our steel prices were all locked in, and we were very happy with what our price of steel is. We have got the engineering contractors, the right-of-way contractors, and on the project as it speaks, we have not yet bid out the actual construction insulation. We will be doing that as the year goes on and obviously trying to get some fixed-price costs on those.

Okay. And finally on Independence, can you give an update on what kind of volumes you are seeing this quarter?

Well, at the moment we are still seeing volumes which are running about 700 to 715 million cubic foot a day. The anticipation is from the producer that they continue to work over a couple of wells after the first quarter. So it should be second quarter to mid-year, and hopefully they are still looking at developing a few wells that they have development plans on toward the end of the year. But our anticipation is that it should stay around the 700 potentially declining a small bit toward the end of the year.

Stephen Maresca, Morgan Stanley.

Thanks a lot, Jim, for the detail on NGL. It was much appreciated, and I have a question on that. I thought you talked about at one point chemical margins possibly compressing a little bit this year, and I think you said demand slipping a little bit in 2010 on ethylene of 1.5%. I guess my question is, am I right on that? What is driving that, and what do you think the impact, if any, on NGL price is for this year?

Yes, you are right on that, and that is according to CMAI. We subscribe to them as does most of the petrochemical industry. CMAI is forecasting that you will see some compression on things like low density polyethylene, high density polyethylene as Middle East crackers come on stream that are scheduled to come online this year, but that the impact on the US will only be about a 1.5% shrink.

In terms of NGL prices, you know the fact is the petrochemical industry has been drawing inventory pretty dramatically primarily on ethane because they are using more than we are producing. We still think that they are going to use north of 800,000 barrels a day. As long as ethane is preferred, we expect it to continue to be preferred. Use of that level of volume, they are using what we produce. And we really do not see a heck of a lot of downside on our ethane margins for the balance of the year.

In fact, they are using more than we are producing.

Right.

Okay. Thanks. Switching quickly to the onshore natural gas pipeline segment, you saw a little bit of volume growth during the quarter, but obviously operating margins slipped a little bit. Can you just elaborate as to why?

The volume growth was up in more the White River hub and due to this stuff out in the Rockies related to -- which is a very low margin oriented business -- it is a $0.015 kind of throughput rate.

With regards to South Texas, we experienced some pretty good declines down there in the conventional wells as Hank talked about in his comments, close to 15% to 20%. What offset part of that in Texas was the expansion of the Sherman lateral coming on service and getting the flows and the demand dollars coming in from there. So it did not volumetrically flow as much, but we got the demand dollars coming in off the Sherman.

Okay. And then a final quick question. On the Haynesville extension, the 2.1 Bcf capacity, what of that is contracted or committed -- spoken for?

We have not announced how much of that is committed. We do have contracts with seven shippers. We have some capacity left. Frankly, we are not in a rush to sell that. The project is not scheduled to go into service until September or so of 2011. So we think we are in a great position.

Okay. Well, thanks a lot and good quarter.

Darren Horowitz, Raymond James.

Congratulations on the quarter. Just a couple of quick questions. The first for you, Jim. On your 2010 equity NGL hedges, you mentioned that you do not see a lot of downside on ethane margins this year, and we tend to agree with you if NGL frac volumes and NGL production continue to run at record levels. How do you balance layering in additional hedges versus keeping spot exposure?

I look at Dan, and if he winks, I hedge. (laughter)

I think a lot of this has to do with the fact that we are pretty conservative by nature. When we see spreads that we think are attractive, we are going to take advantage of that to reduce volatility in a partnership's cash flow. We hedged in 2008 and 2009. We did not hedge at the peak of prices for those years. But we think we are doing the right thing by our unitholders by taking a conservative approach and not trying to guess where the peak is.

Jim, you mentioned about 100,000 barrels of capacity that has moved over to crack the light ends. How much incremental capacity do you think from this point forward can convert from cracking heavies to lights?

I saw something that EnVantage put out recently, and that is a consultant we use pretty often. And I think what they said is that of the, say, 60 billion pounds of ethylene-producing capacity, about 53 billion pounds had the wherewithal to use some NGLs. I mean some of them can use normal butane. Most of them can use ethane and propane. But there's probably about what is that -- 7 billion pounds a year of additional capacity that is still restricted to naphtha type crude oil to our feedstocks.

Okay, I appreciate the color. And then just one final question, more housekeeping in nature. Similar to what was realized in the fourth quarter, have you taken ownership of any NGLs and sold them forward for delivery, and if so how much?

Are you talking about contango plays?

Exactly, yes.

No. It had not been there. In fact, we have been doing backwardation plays.

Okay. Thanks, guys, I appreciate it.

Michael Blum, Wells Fargo.

Mike, going back to your comments on it looks like you're going to be favoring organic growth over acquisitions, can you just talk about overall in the portfolio what types of returns you would expect on your organic capital and then contrast that with what you're seeing in the acquisition market in terms of EBITDA multiples?

Well, it is kind of hard to say what the current acquisition market is going for. But with 24 private equity players and a lot of MLPs that do not have a lot of organic growth prospects, you would think it would tend to get kind of frothy again.

Just in terms of the returns that we expect to see on our projects, it is probably no different than what we have expected over the last several years. When you have a regulated pipeline that is contracted, stable cash flows, you are going to be looking in the low double digits. Some of our processing and fractionation assets discreetly might be in the mid-teens. But again, when you couple that with our downstream assets, then you can get some pretty robust returns.

Okay. The second question was just on the marine transportation business that came along with the TEPPCO assets. The fundamentals have obviously been under pressure in that business. Can you just talk about your thoughts longer-term, and is that a business you look to grow, shrink, maintain, etc.?

It is definitely an area that we expect to grow. I think under TEPPCO again they were a bit constrained by liquidity. Our view is trying to integrate that into the enterprise businesses, including those TEPPCO businesses that we acquired. We think that it could be a very interesting fit for our NGL marketing business, for our crude business as we continue to expand that, as well as refine products. So we are looking at ways to integrate that and to create more value.

This is Dan. I would like to comment on the TEPPCO deal, too. The people and TEPPCO, along with the offshore side of the deal, -- and it's a question you just asked -- they were not only restrained in their ability to raise capital, but their cost of capital was a good bit higher in 10%, 15%, 20% more cost of capital than the Enterprise cost of capital is. So that was another big difference that restrained TEPPCO. Even with exactly the same people, Enterprise would have a bigger growth area to grow into and get a better return than TEPPCO would have had. And that was one of the reasons for the merger being put together is to capture the cost of capital at the lowest cost of capital of all of our products, and that is the same reason that DEP was formed is to be able to have a lower cost of capital than most of our peer group if not the best cost of capital of anybody in the peer group deal because of our high split cut off at 25%, and because DEP has no high split at all. And so we look at our total cost of capital on determining what asset goes where and how do we capitalize that asset and especially the returns.

Sharon Lui, Wells Fargo.

The question relates to DEP. Just looking at the maintenance CapEx guidance for next year, can you just comment on the increase for DEP I?

I think it is higher pipeline integrity costs to some extent on Acadian.

Okay. And then I guess just looking at the distribution curve at DEP, you have a pretty strong coverage ratio. What are your thoughts in terms of accelerating distribution growth, or are you comfortable at the 3% to 4% range?

I think right now we are comfortable with the 3% to 4% range. We do have some small capital projects that we need to use some of our excess distributable cash flow for. So again, we want a conservative model and make sure we have liquidity to be able to pay for our capital projects, which again will be helped I think also by our distribution reinvestment program which begins this month. (multiple speakers)

I guess excluding the Acadian extension, what is your growth CapEx budget for 2010 at DEP?

I believe it is about $15 million, $16 million this year, primarily in the NGL pipelines and services segment.

This is Dan Duncan again. I would like to also comment under our distribution policy that we have kind of set up for all the companies. We look at -- we always look in three, five, 10 years out, and we want to make sure that we hopefully never have to cut our distribution. We are looking for long-term growth deals. Basically we are conservative on the amount of cash that we put out for distributable cash flow. And it is the usual deal that we have talked about over the last 10 or 11, 12 years is that if we can hold -- if we are consistent with our distribution increases on all of the Enterprise companies and we can hold those to a consistent increase every year, which is what we have tried to do, and we feel that long range that people -- the unitholder that stays with us long range rather than one or two years will come out ahead by us holding back some of the distributions that most other MLPs distribute out, mainly because they want to put as much as they can into their general partner MLP side rather than going back into the unitholders. And we have no problem with their concept. We just operate with a different concept.

Thanks for the color, Dan.

John Edwards, Morgan Keegan.

If maybe Jim could give a little more details on the Eagle Ford Shale opportunity as far as NGL volumes, about what you expect to get out of it and as far as timing goes.

You know, one of the things we have here is we have a reservoir group that, frankly, are quite conservative, and I have been a little bit surprised that they seem to have lost some of their conservative nature as it relates to the Eagle Ford. So, in that respect, we are pretty excited.

We know exactly what we want to do in the Eagle Ford as production develops. We know, for example, that market is well served on the liquids. Liquids are not going to stay down in South Texas. They are going to have to be moved out. We know exactly what we need to do to move that out if the production reflects the need to do that or support that. On the crude oil side, we know exactly what we want to do. We are in active negotiations with producers, and we expect some of those projects to come to fruition. We think if what we see developing materializes, you could very well have another frac expansion at Mont Belvieu supported by Eagle Ford production.

I think the key is that it is not entirely up to us. It is up to the producers that own the production, and it is our job to build the facilities and be the best service provider so that we are the logical choice when it comes to servicing their production.

Yes, I understand. We are just trying to do a better job of modeling it out. I mean otherwise it is a bit of a moving target here.

Okay. And then for Randy, you mentioned floating-rate debt is only about 12%. What -- you are normally about 20% -- so do you expect to increase the amount of floating-rate debt, I guess, particularly when some of these issues are coming due this year?

Yes, John, I think just as we spend capital this year and certainly with the small note issue that comes due in March we will just finance that with borrowings on the credit facility, and that will increase the floating exposure.

Great. Thank you very much. Great quarter.

Ross Payne, Wells Fargo.

The real question I have got here is it looks like you're using some of your Louisiana fractionation capacity as excess capacity when things get full in the Gulf. If you can speak to what kind of capacity utilization you are on the Louisiana fractionator, how you think about that business. And, second of all --

Hey, Ross.

Can you hear me?

You are breaking up a little bit, but are you asking what our capacity utilization is on our fracs? (multiple speakers)

Yes, in Louisiana and also how Haynesville extension might impact any of that?

Well, the Haynesville probably will not impact it because it is dry gas. So there's not many -- there are not liquids that come out of that. I don't know. We are moving -- I guess I can say what we move -- we are moving on average probably 50,000 -- it was really 50,000 barrels a day to Louisiana that we are primarily topping off Promix and Norco with.

Alright. So you got plenty -- I mean do you have plenty of capacity in Louisiana to continue to do that on an as needed basis?

Yes, we are in pretty good shape.

For now. I mean we do have some projects -- the Anaconda extension that we are looking at, and depending on what happens with McMoran and their production we could be seeing some big changes.

Yes, we have got some things going on -- I guess I would -- yes, we are in pretty good shape. We twitch every once in a while, but we manage to get it done.

This is Dan again. We feel and Jim and them feel and his people feel, along with Rudy Nix, who is in charge of that particular phase of the business, that in the range of $50,000 a day, we will keep our Texas -- all of our product from the Rockies, South Texas and all the rest of Texas for this year. We think by hopefully January or late early February we will have the 75,000 or really an 80,000 a day fractionator, new fractionator at Belvieu. Then that gives us an additional -- at that time we back all that probably back into Texas, and we still have the 50,000 to 60,000 a day fractionation that is available in Louisiana.

On top of that, if we need to, we can go into Dow Chemical 50% of the Promix and pick up another 20,000 or 30,000 barrels a day by using Dow's portion of the Promix deal. So theoretically we feel that we can go through this year and through the next couple of years, and we are also expanding our Texas to Louisiana pipeline really by 25,000 barrels a day?

Yes, we are going from about 65,000 barrels a day. Now we will be doing about 83,000 to 87,000 barrels a day by late March.

So we feel definitely this year and the following year we can stay ahead again on the fractionation. We also have heard that Targa is expanding their fractionator to take care of some one-off volume coming down from Oklahoma. So we think the industry is in real good shape to handle all the new volume coming on.

(Operator Instructions).

So I think that we can probably go ahead and give our listeners the replay information for the call.

Okay. Thank you for participating in today's fourth-quarter earnings conference call. This call will be available beginning at 10:00 AM Eastern time today through 11:59 PM on Friday, February 8, 2010. The conference ID number for the replay is 51242739. The number to dial for the replay is 1-800-642-1687 or 706-645-9291.

Thank you and thank you all for joining us today on our call, and have a good day. Good-bye.