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Enterprise Products Partners L.P. (NYSE:EPD)

Q4 2009 Earnings Call Transcript

February 1, 2010 9:00 am ET

Executives

Randy Burkholter – Vice President, Investor Relations

Mike Creel – President and CEO

Jim Teague – EVP and Chief Commercial Officer

Randall Fowler – EVP and CFO

Hank Bachman – President and CEO of Duncan Energy Partners

Dan Duncan – Chairman

Analysts

Mark Reichman – Madison Williams

Brian Zarin [ph] – Barclays Capital

Steven Moresco [ph] – Morgan Stanley

Darren Horowitz – Raymond James

Michael Blum – Wells Fargo

Sharon Lui – Wells Fargo

John Edwards – Morgan Keegan

Ross Payne – Wells Fargo

Operator

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

Randy Burkholter

Thank you, Celeste. 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’s general partner; followed by Jim Teague, Executive Vice President and Chief Commercial Officer; then Randy Fowler, our Executive Vice President and Chief Financial Officer will follow Jim. And then Hank Bachman, President and CEO of Duncan Energy Partners 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. Afterwards, we will open the call up for your questions.

During this call, we will make forward-looking statements within the meaning of section 21-E of the Securities and Exchange Act of 1934 based on the beliefs of the company as well as assumptions made by and information currently available to Enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such expectations will prove to be correct.

Please refer to our latest filings with the Securities and Exchange Commission for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. And with that, I'll turn the call over to Mike Creel.

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're 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 equity NGL production. Higher natural gas processing margins increased demand for NGLs as petrochemical feedstock over more costly crude oil derivates, profits from NGL sales that were completed in the fourth quarter and the settlement of the Mid-America rate case and the 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 pipeline in the services segment declined $27 million for 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 bases of natural gas prices across the country. Some of this will be recouped in the first quarter of 2010 as we deliver gas volumes we own from storage and recognize profits. Our Texas Intrastate System benefited from the Sherman Extension being in full service for the quarter, but this was partially offset by lower pipeline volumes.

Gross operating margin for the Offshore Pipelines & Services segment increased by $44 million or 81%. This included $22 million of insurance recoveries related to Hurricanes and 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 & Refined Product segment reported a $25 million or 30% increase in gross operating margin for the fourth quarter of 2009. Our refined products pipeline 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. These are increased revenues or reduced expenses that have not been previously identified, including revising tariffs on the Enterprise refined products pipeline system, (inaudible) certain volumes of natural gas from the (inaudible) 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 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 1st of this year that requires 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 to our continued ownership of equity in the partnership to reinforce our alignment of interest 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 were 24 private equity teams chasing acquisitions in the midstream space.

It sounds like the acquisition market is going to be expensive again, and probably we 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 like to turn the call over to Jim.

Jim Teague

Thank you Mike. What a difference a year makes. This time last year, when we were reviewing December 2008 in the fourth quarter of 2008, we were faced with a WTI crude price of $41 and we had Henry Hub natural gas at 580 or 81% of crude on a Btu basis.

In December of 2008, the annualized production of ethylene from the US ethylene producers was £34 billion, the lowest I have seen it in 20 years. There were consuming 546 thousand barrels a day of ethylene, a total of 700,000 barrels a day of total NGLs; ethylene was selling at $0.355 a gallon. Our processing margin at (inaudible) was $0.04, and we are 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, and ethane use in petrochemicals was 840,000 barrels a day, total NGLs use almost 1.3 billion barrels a day.

Our processing margin at ethane [ph] was $0.50 a gallon, and ethane inventories were being drawn dramatically with selecting 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, and 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 with more LNG facilitates 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 so this year. The feedstock cost advantage in 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 production, domestic production of high-density polyethylene, low-density polyethylene and PVC were for the export market. US ethylene producers responded, they rationalized some of their facilities and invested capital to modify their traditional naphtha 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’ve worked closely with these customers to provide them with incremental supplies of ethane and propane and related logistical services. In addition to the international ethylene crackers, have reacted to the NGL feedstock cost advantage by importing LPG through traditional naphtha crackers. Since July of last year, our LPG export terminal and 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 use or substitution of LPG to other parts of the world.

Export ethylene derivative demand remained strong in early 2010, but as Middle East production increases US export volumes are expected to slip. Chemical margins in the US are forecast 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 a year or greater in 2011.

With the global recession abetting, domestic demand is forecast to increase, consuming the production that was going overseas in 2008 and 2009. The new ethylene capacity in the Middle East received a lot of attention due to the low cost feedstock advantage over production in other regions. Along with 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 in Enterprise are well positioned to help the US chemical industry remain competitive by providing reliable NGL feedstock suppliers and services.

We are planning to the future by increasing our crack capacity, expanding our natural gas pipeline and processing infrastructure, and growing our distribution networks. During the fourth quarter, ethylene plants operated in an annual production rate of approximately £52 billion, 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 3 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 the 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 south Texas.

A question we have frequently gotten from our investors over the last nine months have 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 backward dated, which compresses that forward processing spread.

Than 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 (inaudible) 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 with about half of those barrels detains [ph] in natural gasoline. We're 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 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 we would increase the size of the extension up to 42 inches with the ultimate capacity approaching 2.1 BCF a day.

With the Haynesville extension serving as a backbone frontline 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, which many producers have commitments.

More importantly, we provide producers with exclusive southbound capacity to get them to the Perryville as well as other pipes in South Louisiana, such as Florida Gas, TransCo, (inaudible) as well as in use markets in South Louisiana. We think this will provide producers with higher netbacks, because we think there is going to be (inaudible) Perryville.

We also believe producers like the flow assurance 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 shell 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, in top of 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 the 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’ve had early success. We believe there is 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 in natural gas, NGLs, petrochemicals and refined products will be important as we look to capitalize on new opportunities. Mark will be on board March the 2nd.

As you can tell, we're pretty excited about our prospects in continuing to grow Enterprise. Now I will turn the call over to Randy.

Randy Fowler

Thank you Jim. I will briefly discuss some noteworthy income, liquidity and capitalization items. As Mike mentioned, I will skip items where we provided detailed at variance 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 (inaudible) basis.

Approximately 28% of this increase was merger-related cost 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. Approvals 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 to grow 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, 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-States NGL Pipeline as well as $6 million to build a new substation in (inaudible).

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, they were approximately $235 million.

Adjusted EBITDA for the 12 months ended December 31, 2009, was $2.7 billion. Adjusted EBITDA is defined as EBITDA plus 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 was a little lower than our typical high teens to 20% level due to the applications of proceeds 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 lot 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 maturity in 2010, which includes a $54 million 8.7% note due March 1st, and $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 Bachman to discuss Duncan Energy Partners’ quarter.

Hank Bachman

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 strong quarter of strong operating and financial performance from our businesses. At the time of our IPL 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 them 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 two [ph] business, 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 $26.6 million per quarter, based on our 11.85% preferred return in 2009, which will increase by 2%, 12.09% for 2010. As a result of our increased preferred return in 2010 on our $730 million investment in the DEP two midstream 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 two midstream businesses contributed to 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 two businesses included only the 24-day period from the closing date of the DEP two drop down transaction, December 8th 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 in cash distributions received from the DEP two 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 cents 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 partnerships 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're 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 Acadian system will provide shippers access to the end-user markets along the Mississippi River corridor and to nine other intrastate pipelines.

Natural gas being shipped on the Haynesville extension pipeline will also have access to the Acadian’s rapid cycle salt dome storage cavern located near (inaudible) Louisiana, and can be physically delivered into the Henry Hub via our Acadian pipeline system. We believe that this pipeline extension project will help to continue our growth for years to come.

Our NGL Pipelines & 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 was 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 interest.

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 2008 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 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 cost 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 $11.8 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 in sustaining capital expenditures compared to $54.2 million spent in 2008. Approximately $35 million of the $48.4 million was for the DEP two businesses, and as a result had less of an effect on our distributable cash flow because of our preference return [ph].

For 2010, we expect sustaining capital expenditures to be approximately $55 million. With the split between the DEP one [ph] and DEP two 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 cash distributions to our partners.

And as I’ve 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 no ready to take questions for Enterprise or Duncan Energy.

Randy Burkholter

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

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Mark Reichman with Madison Williams.

Mark Reichman – Madison Williams

Good morning. 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, you know, the projects that you announced. For example, do you see much -- many opportunities to expand the crude oil infrastructure or is it mainly natural gas and NGL?

Mike Creel

I think as Jim said, we see opportunities in all areas, including the dry (inaudible), and we're looking at developing our system into a dry system and a wet system to accommodate both streams, but also crude and condensate to the extent that we can attract producers. We certainly have assets that we think are in a right position, we're ready, willing, and able to spend money to expand the system to accommodate their needs. Jim, anything else to add?

Jim Teague

No, that's it.

Mark Reichman – Madison Williams

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

Mike Creel

Mark, at this point in time we're still evaluating that split, I mean, Duncan Energy owns 66% of Acadian and EPD owns 34%. So we made a good project and you know, we think good projects are easy to finance.

Randy Fowler

One of the things that because of the ownership of the pipeline between Duncan Energy Partners Enterprise, it's one of those where we will likely get the (inaudible) committees of both partnerships involved to make sure that (inaudible) unitholders are protected.

Mark Reichman – Madison Williams

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

Mike Creel

We don't break it out by project. We have in the press release, they are chunkier 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, but I'd caution you that $1.5 billion that we referred to, it really are projects that we have already approved and that we are committed to and that does not include new projects that we may find over the course of the year.

Mark Reichman – Madison Williams

Okay, thank you. I appreciate that.

Operator

Your next question comes from the line of Brian Zarin [ph] with Barclays Capital.

Brian Zarin - Barclays Capital

Good morning.

Mike Creel

Good morning Brian.

Brian Zarin - Barclays Capital

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 that include oil marketing and storage or, can you provide a little more color?

Mike Creel

Well, let me, let Jim answer that but I'll 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've said before we have that value chain approach and we're looking to apply that to all of the Teppco businesses, including the crude oil and refined products business.

Jim Teague

I mean, I think you said it. We see opportunities for growth in the refined products sector. We brought some people in. We mentioned Mark earlier that we brought in crude oil, we brought in some people on the refined products 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 and what enterprise has, with what Teppco has to create more of a value chain. So, we're going to be pretty focused on the crude section as well as refined products area.

Brian Zarin - Barclays Capital

Again 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?

Randy Fowler

I will jump in. The cost estimate and everything, we haven't given out a firm number, but we're still on target and plan with where we -- our original intentions were. All the contracts that we have in place with the seven different producers are ten-year agreements, all demand charges with very little commodity more the interstate model. It's about 98% demand, 1% or 2% commodity related, but they're all ten-year firm agreements.

Brian Zarin - Barclays Capital

They (inaudible) are those -- your agreements with the contractors, are they fixed-price -- are they to control your costs?

Mike Creel

As far as controlling the cost, 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 ASE [ph]. Our steel prices were all locked in and we were very happy what our price of steel is. We've got the engineering contractors, the right away contractors and on the project, as it peaks. We've not yet bid out the actual construction and installation. We will be doing that as the year goes on and obviously trying to get some fixed-price costs on those.

Brian Zarin - Barclays Capital

Okay, and then finally on independence, can you give an update on what kind of volumes you're seeing this quarter?

Mike Creel

Jim?

Jim Teague

Well, at the moment we're still seeing volumes, which are running about 700 to 15 million cubic per day. The anticipation is from the producer that there is continue to work over a couple of well after the first quarter. So, it should be second-quarter to mid-year, and hopefully they're still looking at developing a few wells that they have development plans on towards the end of the year, but our anticipation is that it should stay around the 700, potentially declining a small bit towards the end of the year.

Brian Zarin - Barclays Capital

Thank you.

Operator

Your next question comes from the line of Steven Moresco [ph] with Morgan Stanley.

Steven Moresco - Morgan Stanley

Good morning guys.

Mike Creel

Hi Steve.

Steven Moresco - Morgan Stanley

Thanks a lot Jim for the detail on NGL. That is 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 then 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 prices for this year?

Jim Teague

Yes, you're right on that, and that's according to, Steve, that's according to CMAI. We subscribe to them and as do most petrochemical industry. CMAI is forecasting that you’ll 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 1.5% shrink. In terms of NGL prices, yes, the fact is the petrochemical industry, has been drawing inventory pretty dramatically primarily on ethane, because they use it 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 for use of that level of volumes or use of what we produce. So, we really don't see a heck of a lot of downside on our ethane margins for the balance of the year.

Mike Creel

In fact they're using more than we're producing.

Jim Teague

Right.

Steven Moresco - Morgan Stanley

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 you know, as to why?

Mike Creel

The volume growth was up in more the White River Hub and due to the step out in the Rockies related to which is a very low margin oriented business. It's a $0.015 kind of throughput rate. With regards to South Texas, you know, we experienced some pretty good declines down there in the conventional wells as Hank talked about in his comments close to 15% to 20%. So what has 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 that didn't biometrically flow as much, but we got the demand dollars coming in of the Sherman.

Steven Moresco - Morgan Stanley

Okay, and then final quick question. On the Haynesville extension the 2.1 bcf capacity, what of that is contracted or committed (inaudible)?

Mike Creel

We've not announced how much of that is committed. We didn't 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're in a great position.

Steven Moresco - Morgan Stanley

Okay. Well, thanks a lot and good quarter.

Mike Creel

Thanks.

Operator

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

Darren Horowitz – Raymond James

Guys, good morning. Congratulations on the quarter. Just a couple quick questions, the first for you Jim. On your 2010 equity NGL hedges, you mentioned that you don't see a lot of downside on ethylene margins this year and you know, we tend to agree with you NGL frac points and NGL production continued to run at record levels. How do you balance layering in additional hedges versus keeping spot exposure?

Jim Teague

I look at Dan and if he winks, I will hedge.

Mike Creel

Darren, I think a lot of it has to do with the fact that we're pretty conservative by nature. When we see spreads that we think are attractive, we're going to take advantage of that to reduce volatility and the 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.

Darren Horowitz – Raymond James

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

Jim Teague

You know, I saw something that (inaudible) put out recently, and that's 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's still restricted to (inaudible).

Darren Horowitz – Raymond James

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 delivering, and if so how much?

Mike Creel

You are talking about contango plays, no?

Darren Horowitz – Raymond James

Exactly, yes.

Mike Creel

No. It hadn't been there. In fact, we've been doing backwardation plays.

Darren Horowitz – Raymond James

Okay, thanks guys. I appreciate it.

Mike Creel

Thank you Darren.

Operator

Your next question comes from the line of Michael Blum with Wells Fargo.

Michael Blum - Wells Fargo

Good morning everyone.

Mike Creel

Good morning Michael.

Michael Blum - Wells Fargo

Mike, going back to your comments on, looks like you're going to be favoring organic growth over acquisition. Can you just talk about overall in the portfolio what type of the returns do you expect on your organic capital, and then contrast that with what you're seeing in the acquisition market in terms of EBITDA multiple?

Mike Creel

It's kind of hard to say what the current acquisition market is going forward, but with 24 private equity players and a lot of MLPs that don't have a lot of organic growth prospects, you think it tend to gets kind of frothy again. Just in terms of the returns that we expect to see on our projects probably no different than what we have expected over the last several years, when you have a regulated pipeline that has contracted stable cash flows. You're 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.

Michael Blum - Wells Fargo

Okay. Second question was just on the marine transportation business that came along with our Teppco assets, the fundamentals have obviously been under pressure in that business. Can you just talk about your stocks, longer terms, and is that a business you look to grow, shrink, maintain, et cetera?

Mike Creel

It is definitely an area that we expect to grow. I think under Teppco again with -- they were a bit constrained by liquidity. Our view is again 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 businesses, as we continue to expand that as well as refined products. So, we are looking at ways to integrate that and to create more value.

Dan Duncan

Michael, this is Dan. I'd like to comment on the Teppco deal too. The people in Teppco along with the offshore side of the deal, and that the 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 than the 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's the same reason that DEP was born, 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. Because of our high split cutoff [ph] at 25%, because of the DEP has no high split at all. So we look at our total cost of capital and determine what asset goes where and how do we capitalize that asset and especially the return.

Michael Blum - Wells Fargo

Great, thank you Dan.

Operator

Your next question comes from the line of Sharon Lui with Wells Fargo.

Sharon Lui - Wells Fargo

Hi, good morning. This question relates the DEP. Just looking at the maintenance CapEx guidance for next year, can you just comment on the increase for DEP one?

Mike Creel

(inaudible).

Randy Fowler

I think it is higher pipeline integrity cost to some extent, I think it's on Acadian.

Mike Creel

I think it is on Acadian also.

Sharon Lui - Wells Fargo

Okay, and then I guess just looking at the distribution growth 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?

Mike Creel

I think right now we're comfortable with 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 to consolidate model and make sure that we have liquidity. We'd be able to pay for our capital projects, which again will be helped I think also by our distribution reinvestment program, which comes into being this month.

Dan Duncan

This is Dan.

Sharon Lui - Wells Fargo

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

Mike Creel

I believe it's about $15 million, $16 million this year, primarily in NGL pipelines and services segments.

Sharon Lui - Wells Fargo

Okay, great. Thank you.

Dan Duncan

This is Dan Duncan again. I'd like to also comment on our distribution policy that we kind of set up for all the countries. We look at -- we're always looking 3, 5, 10 years out, and we will make sure that we hopefully never have to cut our distribution that we are looking for long-term growth deals, and basically we are conservative on the amount of cash that we put out for distributable cash flow, and it's the usual deal that we've talked about over the life 10, 11, 12 years.

And if we can hold, if we are consistent with our distribution increases on all of the enterprise companies, and if we can hold those to a consistent increase every year, which is what we've tried to do, then we feel that long range of people, the unitholders that have stayed with long-range rather than one or two years, would come out of ahead by us holding back some of the distribution that most of the 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 unit holders, and we have no problem with their concept. We just operate with a different concept.

Sharon Lui - Wells Fargo

Thanks for the color, Dan.

Operator

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

John Edwards - Morgan Keegan

Yes, good morning everybody.

Mike Creel

Good morning John.

John Edwards - Morgan Keegan

Just on the -- if maybe Jim could give little more detail on the Eagle Ford shale opportunity as far as NGL volumes, you know, about what do you expect to get out of it and as far as timing goes?

Jim Teague

You know, one of the things we have here is we have a reservoir group that frankly are quite conservative, and I've been a little bit surprised at, they seem to have lost some of their conservative nature as it relates to the Eagle Ford. So in that respect we're 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 liquids. Liquids aren't going to stay down in South Texas. They're 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 supports that. On the crude oil side, we know exactly what we want to do. We're 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.

Mike Creel

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

John Edwards - Morgan Keegan

Yes, I understand. Just trying to do, you know, more a better job of you know, modeling it out. I mean, I realize it is a bit of a moving target here. Okay, and then for Randy you mentioned floating rate debt is only about 12%. You're 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?

Randy Fowler

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

John Edwards - Morgan Keegan

Okay, great. Thank you very much. Great quarter. That's all I had.

Mike Creel

Thank you John.

Operator

(Operator instructions) Your next question comes from the line of Ross Payne with Wells Fargo.

Ross Payne - Wells Fargo

How are doing guys?

Mike Creel

Hi Ross.

Ross Payne - Wells Fargo

The real question I've got here is it looks like you're using some of your Louisiana fractionation capacity as excess capacity, when things get full on the gulf. If you can speak to what kind of capacity utilization you are on the Louisiana fractionators. How you kind of think about that business and second of all, are you still --

Mike Creel

Hi, Ross.

Ross Payne - Wells Fargo

Can you hear me?

Mike Creel

You're breaking up a little bit, but are you asking what our capacity utilization is on our fracs?

Ross Payne - Wells Fargo

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

Mike Creel

Well, the Haynesville probably won't impact because it is dry gas. So, there is not liquids that come out of that, I don't know. We're moving, I guess I'm (inaudible) -- we're moving on average probably really 50,000 barrels a day at Louisiana that were primarily topping of Promix and Norco with.

Ross Payne - Wells Fargo

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

Mike Creel

Yes, we're in pretty good shape.

Randy Fowler

Now, I mean, we do have some projects and kind of extension that we're looking at, and depending on what happens with (inaudible) and their production, we could be seeing some big changes.

Mike Creel

Yes, we've got some things going on. I guess it's – yes, we are in pretty good shape. We twitch every once in a while, but we managed to get it done.

Dan Duncan

Ross, this is Dan again. And Jim is feeling, and his people are feeling along with (inaudible) in charge of that. The face of the dividend, in the range of 50,000 barrels a day. We will keep our Texas, all of our products in the market, 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 barrel a day (inaudible) Belvieu, and that gives us an additional -- at that time, we back all of the products back into Texas, and we feel that they did a 60,000 barrel a day vaccination that is available in Louisiana.

On the top of that if we need to, we can go into dark chemicals, 50% of Promix, and take up another 20,000 or 30,000 barrels a day by using their 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 also expanding our Texas to Louisiana pipeline possibly by 25,000 barrels a day.

Mike Creel

Yes, sir. We are going from about 55,000 barrels a day now, we'll be doing about 83,000 to 87,000 barrels a day by late March.

Dan Duncan

So, we feel definitely this year and the forward year, we can stay and have the game on the fractionation. We also have heard that Target [ph] is expanding their fractionator to take care of some one-off volume coming down from Oklahoma. So, we thank the industry is in real good shape to panel all the new volume coming in.

Ross Payne - Wells Fargo

Great, thanks.

Operator

(Operator instructions).

Mike Creel

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

Operator

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. Again the conference ID number for the replay is 51242739. The number to dial for the replay is 1800-642-1687 or 706-645-9291.

Randy Burkholter

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

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Source: Enterprise Products Partners L.P. Q4 2009 Earnings Call Transcript
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