Enterprise Products Partners LP (EPD) 2008 Q4 法說會逐字稿

Good morning and welcome to the Enterprise Products Partners and Duncan Energy Partners fourth quarter earnings conference call. (Operator Instructions). Today's call is being recorded. If you have any objections your may disconnect at this time.

Now I would like to introduce Mr. Randy Burkhalter, Vice President of Investor Relations.

Good morning and welcome to the Enterprise Products Partners and Duncan Energy Partners conference call to discuss fourth quarter earnings. Mike Creel, President and CEO of Enterprise's General Partner will lead the call, followed by Randy Fowler, the Company's Executive Vice President and CFO.

Hank Bachmann, President and CEO of Duncan Energy Partners' General Partner will discuss Duncan Energy's fourth quarter results after Randy Fowler's financial description.

Also included on the call today are other members of our senior management team, including Dan Duncan, our Chairman and Founder; and Jim Teague, our Executive Vice President, Chief Commercial Officer. 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 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. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.

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

With that, I will turn the call over to Mike.

Good morning and thank you for joining us today. I am pleased to report results for the full year 2008, supported by another strong quarter of good operating results and financial performance. Two years ago we reported record results. We surpassed that in 2007, and now again in 2008 we set new high watermarks for volumes, revenues, gross operating margins, EBITDA, net income and distributable cash flow.

We increased the cash distribution per unit paid with respect to 2008 by 6.5% over the amount paid for 2007. At our analyst meeting last March we announced our goal of increasing the annualized cash distribution per common unit to at least $2.12 by the end of the year. We did this while also retaining over $300 million of distributable cash flow, despite the impact of two major hurricanes on our Gulf Coast operations, a global recession and volatile financial markets.

For the fourth quarter of 2008 we reported net income of $228 million or $0.44 per unit, a 41% increase over the $162 million or $0.30 per unit we had for the fourth quarter of 2007.

We also had near year record gross operating margin of $522 million for the quarter, second only to the first quarter of 2008. Gross operating margin this quarter was reduced by total hurricane effects of approximately $36 million.

Our NGL Pipelines & Services segment posted a 56% increase in gross operating margin this quarter over the fourth quarter of last year, with each of its businesses reporting higher quarter to quarter results. NGL transportation volumes were a record 1.9 million barrels per day this quarter compared to 1.8 million barrels per day in the fourth quarter of the prior year. This increase is despite the loss in volumes in our pipelines due to hurricanes.

We also had increased NGL fractionation volumes, equity NGL production, and sea-based natural gas processing volumes this quarter compared with the same quarter of the prior year.

In addition we transported a record 9.1 trillion Btus per day of natural gas in the fourth quarter and 2.1 million barrels per day of NGLs, crude oils and petrochemicals.

We continue to benefit from our diversified business mix that provides multiple earnings and cash flow streams, and from our broad geographical footprint, which supports our energy value chain strategy.

Distributable cash flow for the quarter increased 26% to $331 million from $262 million generated in the fourth quarter of 2007. Our distributable cash flow provided 1.2 times coverage of the $0.53 per unit cash distribution declared with respect to the quarter. For the full year distributable cash flow provided more than 1.3 times coverage for the cash distributions paid to the Limited Partners with respect to 2008.

As a result, we retained a record $313 million of cash in 2008, enhancing our liquidity and providing additional flexibility to fund our growth, while limiting our need to issue additional equity.

In 2008 we also raised $138 million of cash from newly issued units through our distribution reinvestment plan. This also includes $62 million that was reinvested in November by Dan Duncan. The combination of retained cash flow and proceeds received from the distribution reinvestment plan provided Enterprise with approximately $450 million of equity related liquidity in 2008. Dan has also committed to reinvest another $65 million in the distribution reinvestment plan this month, and has indicated his willingness to consider investing up to a total of $260 million in 2009.

We have been proactive in taking steps to significantly increase our liquidity and financial flexibility since the beginning of the credit crunch. Since November 2008 we have raised approximately $1.6 billion of debt and equity capital, including our recent $10.6 million common unit offering in early January, which was the first equity offering in the United States in 2009. As a result, we began 2009 with a solid $1.6 billion of liquidity, including the $226 million of net proceeds from the equity offering last month.

As we look forward to 2009 we intend to continue our disciplined approach to maintaining adequate liquidity and funding our capital projects, debt service and distribution growth. We have evaluated all of our potential capital projects in light of today's capital markets and prioritized those investment opportunities. We currently have approximately $800 million of growth capital expenditures planned for 2009, and expect to spend approximately $180 million of sustaining CapEx for the year.

This is less than the $1.5 billion to $2 billion we have spent in the past on growth projects, but we could increase our capital program if the capital markets become more accessible later in the year, as some economists forecast.

While we have many attractive investment opportunities, we will be deliberate in our approach, and do not intend to get ahead of our ability to prudently fund our growth while maintaining an investment grade balance sheet.

We have three major capital projects that should commence operations this quarter. We're in the final stages of commissioning our new Meeker II cryogenic natural gas processing facility, and expect to begin extracting NGLs by mid-February. In March when both Meeker I and II are available, we expect to be processing approximately 900 million cubic feet a day at the complex. We expect this volume to increase to 1 Bcf to 1.1 Bcf a day in the third quarter, as expansions to our Piceance Basin pipeline system are completed, and gas that is currently being produced is delivered to our plant.

The Exxon Central Treating facility located near our Meeker complex in the Piceance Basin was completed ahead of schedule and under budget, and expected to receive first gas flows from Exxon in March.

The Sherman Extension Natural Gas Pipeline will begin ramping up volumes this month, with volumes expected to increase as compressor commissioning is completed by Enterprise and Boardwalk later in the quarter. We have long-term agreements with shippers for 1 Bcf a day of capacity of the Sherman Extension.

This year we are scheduled to commence operations at new facilities totaling about $2.3 billion of capital investment, including the three projects I just mentioned. Other projects include the Trinity River Basin Gas Pipeline lateral, the Shenzi Oil Pipeline, the Marathon Gathering System, and the Collbran Valley Pipeline. In the second half of the year we expect to begin operations on additional expansions to our Piceance Basin and our Texas Intrastate Pipeline Systems as well.

With that, I would like to review a few business highlights for the quarter. As I mentioned earlier, gross operating margin for our NGL Pipelines and Services business increased 56% over the fourth quarter of 2007. Estimated lost business for this segment in the fourth quarter of 2008 due to hurricanes was approximately $11 million, while gross operating margin for the fourth quarter of 2007 benefited from $9 million of business interruption insurance proceeds.

Our Gas Processing business reported the largest increase in gross operating margin of the three businesses from this segment, an 82% increase to $204 million in the fourth quarter compared with $112 million of gross operating margin recorded in the fourth quarter of 2007. This business had a 27% increase in equity NGL production, increased NGL marketing activities, and strong natural gas processing margins, in part provided by hedging activity. We hedged approximately 75% of our 2008 equity NGL production at prices that were significantly lower than prices actually seen during most of the year. We also hedged approximately 67% of our expected 2009 equity NGL production in 2008.

The increase in equity NGL production was primarily attributable to the higher volumes extracted at the Meeker processing plant and the Pioneer plant, which began commercial operations in February of last year. Combined, these two plants are currently extracting an average of 63,000 barrels per day of NGL.

NGL demand for petrochemical production was down in the fourth quarter, as you would expect given the downtime due to Hurricane Ike and inventory management in light of reduced demand for petrochemical by-products. Ethylene crackers operated at 72% of capacity in November, producing ethylene at an annual rate of 45 billion pounds. According to the Hodson Report they operated at 57% of capacity in December and an estimated 59% of capacity in January.

The good news is February industry operating rates are expected to increase as up to five ethylene plants that were idled due to economic or maintenance reasons are in the process of coming back online, according to industry consultants. These plants, which have a combined 10 billion pounds of capacity, could increase ethane cracking by as much as 125,000 barrels a day to 675,000 barrels per day, which compares to average ethane cracking in all of 2008 of 715,000 barrels per day.

Gross operating margins from our NGL Pipelines and Storage business increased 32% to $116 million in the fourth quarter of 2008 compared with $88 million in the fourth quarter of 2007. This increase was primarily due to higher transportation volumes on the Dixie and Lou-Tex NGL Pipeline Systems, a 25,000 barrel per day increase in NGL transportation volumes, and higher tariffs that went into effect in mid 2008 for our Mid-America and Seminole Pipelines, and lower pipeline integrity expenses on our South Louisiana pipeline. Gross operating margins from our NGL storage business at Mont Belvieu also increased $7 million.

Volumes associated with the NGL Pipelines and Storage business totaled 1.9 million barrels per day in the fourth quarter of 2008 compared with 1.8 million barrels per day at the same quarter last year. Our NGL marketing business is utilizing our storage facilities to take advantage of the current contango market and lock in at least $40 million of margins for 2009.

Gross operating margin from our NGL fractionation business was $27 million in the fourth quarter of 2008 compared with $23 million in the fourth quarter of the prior year. NGL fractionation volumes increased 10% over the prior year to a record 444,000 barrels per day this quarter, with most of that increase coming from our Hobbs, South Texas and our Mont Belvieu fractionators.

Our Onshore Natural Gas Pipelines and Services segment reported gross operating margin of $90 million from the fourth quarter 2008 compared with $101 million for the fourth quarter of 2007. Gross operating margins for the stand-alone system decreased $16 million this quarter due to lower revenues from transportation fees indexed to natural gas prices and condensate sales.

San Juan natural gas prices averaged $3.91 per MMbtu for the quarter versus $5.89 per MMbtu for the fourth quarter of 2007.

Our Natural Gas Marketing business reported a $7 million increase in gross operating margin this quarter compared to the fourth quarter of the prior year. Total onshore natural gas transportation volumes increased 15% to a record 7.8 trillion Btus per day in the fourth quarter of 2008, surpassing the record set in the previous quarter of 7.6 trillion Btus per day.

Gross operating margins for the Offshore Pipelines and Services segment was $54 million in the fourth quarter of 2008 compared with $74 million in the fourth quarter of the prior year. Gross operating margin was impacted by $25 million this quarter from hurricanes, including $23 million for lost business.

Independence Hub and Trail contributed a record $56 million to gross operating margin this quarter, averaging 894,000 MMbtus per day. This compares to $48 million of gross operating margin reported in the fourth quarter of 2007 on an average throughput of 719,000 MMbtus per day. This improvement was more than offset by lower demand revenues and lower volumes at the Falcon platform and lower volumes from our other platforms and offshore gas and oil pipelines due to disruptions caused by the hurricanes.

We estimate the impact of lost business related to Hurricane Ike in the first quarter of 2009 will be a decrease of approximately $15 million to $20 million in gross operating margin before any future recoveries from business interruption insurance.

Our Petrochemical Services segment reported gross operating margin of $31 million in the fourth quarter of 2008, $2 million less than in the fourth quarter of the prior year, primarily due to weaker results from our butane isomerization plants and our octane enhancement facilities.

Before I turn the call over to Randy, I would like to say again that we're very pleased with our performance this quarter, especially given the negative impact on our businesses from the hurricanes early in the quarter and the weakness in the economy. Our strong performance enabled us to continue our impressive track record of increasing the quarterly distributions for the 27th time since our IPO, while also retaining cash flow to provide us with additional financial flexibility.

I am particularly pleased that we were able to raise $1.6 billion in the capital markets over the last three months, increasing our liquidity during these volatile and uncertain financial markets. We continue to believe that our strong fundamentals distinguish us from many other MLPs, particularly in today's market. The quality of our assets, our large diversified footprint, and our portfolio of organic growth opportunities positions us well for the future growth. Our lower cost of capital and our ability to raise capital in challenging markets should enable us, not only to weather these times better than many of our peers, but to actually prosper as a result.

At a time when some other partnerships have stopped increasing their distributions, or in some cases reduce them, we're proud of our track record of 18 consecutive quarters in which we have increased our quarterly cash distribution per unit. We will continue to manage our business with a long-term view. And we believe our investors will be rewarded for our consistent performance, solid results and financial discipline.

With that, I will turn the call over to Randy Fowler for a financial review of the quarter.

Good morning and thank you for joining us today. As Mike mentioned, we're pleased with the performance of our businesses and the solid results this quarter. I would like to start my discussion with items below the gross operating margin on the income statement.

Depreciation and amortization expense in the operating costs and expenses section for the fourth quarter of 2008 increased $147 million from $139 million for the fourth quarter of 2007, primarily due to increased property, plant and equipment from the additions of the Meeker and Pioneer processing facilities, the expansion of the Mid-America Pipeline from Skellytown to Conway, and the Petal natural gas storage cavern in Mississippi.

G&A expense increased to $24 million this quarter from $21 million in the fourth quarter last year, primarily due to higher employee expenses, which includes the reclassification of certain salaries and benefits that were classified as operating expenses last year.

We reported $110 million of interest expense this quarter compared to $92 million for the fourth quarter of last year. Average debt outstanding increased to $8.8 billion this quarter from $6.9 billion in the fourth quarter of 2007, due to debt incurred to fund growth capital investments and also working capital.

The provision for income taxes increased to $9 million for the fourth quarter of 2008 from $6 million for the fourth quarter of 2007. This increase was primarily due to higher Texas margin tax accruals.

Turning to capital expenditures, we invested approximately $670 million in growth capital projects and acquisitions, and spent $59 million in sustaining capital expenditures in the fourth quarter of 2008. The majority of the growth capital spent this quarter was attributable to the Sherman Extension Pipeline, the Meeker II cryogenic processing plant, the Mont Belvieu well utilization program, and the Shenzi Oil Pipeline. During the quarter we also completed three smaller acquisitions of natural gas pipeline and interest in some natural gas liquid pipelines. Those three together totaled approximately $180 million.

In 2008 we invested approximately $2.1 billion in growth capital expenditures and $189 million in maintenance capital expenditures. At December 31, 2008 we had $9 billion of debt, including 100% of our $1.23 billion of hybrid securities and $484 million of debt at Duncan Energy.

Enterprise had liquidity of approximately $1.4 billion at December 31, 2008, which included availability under the Partnership's credit facilities and unrestricted cash. We also had about $182 million of restricted cash at December 31, 2008 that is associated with our natural gas processing hedges that will revert back to the Company on a month-to-month basis in 2009.

During the first week of January, as Mike mentioned, EPD received proceeds -- net proceeds of about $226 million from the issuance of 10.6 million common units. Adjusted for those proceeds, Enterprise's liquidity at December 31 was more about $1.6 billion.

In November 2008 we took advantage of the dislocation in the debt capital market by retiring $17 million of our 7.034% junior subordinated notes -- these were part of the hybrid security -- at a significant discount, resulting in a $7 million gain. This is included -- as far as floating interest rate exposure, was approximately 20% at the end of the quarter. And the average life of our debt was approximately eight years, and our effective average cost of debt was 5.7%.

At December 31, our consolidated debt balance was $9 billion. This consolidated debt balance includes the debt of Duncan Energy, for which Enterprise does not have the payment obligation.

Adjusted EBITDA for 2008, which is EBITDA after adjusting for equity earnings and actual cash distributions received from unconsolidated affiliates, was $2 billion, which is a 39% increase from that of 2007. Our consolidated leverage ratio of debt, adjusted for the 50% equity content in the hybrid to the adjusted EBITDA for the last 12 months, was about 4.2 times at December 31.

Including the January 2009 equity offering, pro forma debt to adjusted EBITDA would have been about 4.1 times. Again, that EBITDA, as we had mentioned earlier, was impacted -- negatively impacted by about $123 million of hurricane effects in 2008, which could have further -- without those effects, could have further lowered debt to EBITDA to about 3.9 times.

Also, keep in mind that our leverage ratio was a bit elevated due to debt balances reflecting a significant amount of the capital costs for the Sherman Extension Natural Gas Pipeline, the Meeker II natural gas processing plant, the Shenzi Oil Pipeline, and the Exxon Central Treating facility, which are complete or substantially complete, but not yet contributing to EBITDA.

With that, I will turn the call over to Hank to discuss Duncan Energy.

This was a pretty exciting quarter for our partnership. Not only did we report significantly higher net income and distributable cash flow for the fourth quarter of 2008 than that reported by the partnership for the fourth quarter of 2007, but we also completed in early December our second drop-down transaction by acquiring controlling interest in three Enterprise Midstream Energy subsidiaries, which we sometimes refer to as DEP II.

This $730 million transaction is important to our partnership as it significantly expands our base of midstream energy assets in Texas, provides additional opportunities for us to develop organic projects, and diversifies our sources of fee-based cash flow.

The natural gas pipelines and related assets acquired in this transaction are strategically located in high demand areas, with access to prolific natural gas supply regions in Texas, including the Barnett Shale play.

An example of new organic projects which were included in the acquired businesses is the new Sherman Extension Gas Pipeline that runs right through the heart of the Barnett Shale region, and interconnects with Boardwalk's Gulf Crossing Pipeline. As Mike mentioned earlier, this 178 mile natural gas pipeline is almost fully subscribed, with agreements in place for 1 billion cubic feet per day of its 1.1 billion cubic feet per day of capacity.

Finally, the businesses acquired in this drop-down transaction also provides Duncan Energy with control of a significant portion of the supply sources for the businesses we acquired from Enterprise in our initial public offering.

For instance, we now control not only the NGLs transportation systems that transport a mixed NGL stream from various South Texas gas processing plants to our Shoup and Armstrong NGL fractionators, which provide the NGLs that are then transported by our South Texas NGL pipeline system and are stored in our Mont Belvieu NGL storage facilities. The partnerships receive fees from all of these services.

Before we get into the partnership's financial and operational results for the 2008 fourth quarter and year, I would like to discuss the accounting treatment of the recent DEP II drop-down transaction.

Because of Enterprise's historical common control of the partnership and the businesses acquired in the drop-down transaction, our financial and operating results for the three months and years ended December 31, 2008 and 2007 have been recast in accordance with generally accepted accounting principles to include the results from these midstream energy companies, as if we had owned these businesses since January 1, 2007, even though the partnership has only owned these businesses since December 8, 2008.

Therefore, all historical financial and operating data reported today, other than distributable cash flow, includes the financial and operating results of the newly acquired businesses, and will not be comparable to the financial results for the corresponding period that the partnership published prior to December 2008. However, we have added a significant amount of information in the exhibits to our earnings release, and hope it will be helpful in evaluating the effects of this recast.

Now on to a discussion of our financial and operating results. We reported for the fourth quarter of 2008 a 58% increase in net income to $10.8 million or $0.39 per common unit, from $6.8 million or $0.30 per common unit for the fourth quarter of 2007.

As good as that was, the partnership did even better with respect to distributable cash flow. Distributable cash flow for the fourth quarter of 2008 increased 63% to $15.4 million compared to $9.4 million in the fourth quarter of the prior year.

Distributable cash flow in the fourth quarter of 2008 included $5.6 million from the DEP II midstream businesses for the 24 day period until the end of 2008. On an annualized basis, this represents an approximate 12% return on our investment in these businesses.

In 2009 each of Duncan Energy and Enterprise expect to receive cash distributions from the DEP II businesses of approximately $87 million, representing an approximate 12% priority return, with any excess cash flow being shared 98% to Enterprise and 2% to Duncan Energy.

The distributable cash flow generated in 2008 from these businesses should support our goal of increasing our annual distribution rate in 2009 by 3%. Of course, the cash flow generated from this priority return is in addition to cash generated from the businesses acquired by Duncan Energy in connection with our IPO.

On January 9, 2009 the Board of Directors of Duncan Energy's General Partner declared a quarterly cash distribution of $0.4275 per common unit, a 4.3% increase from the $0.41 per common unit paid in respect to the fourth quarter of 2007.

Distributable cash flow for the quarter provided 1.2 times coverage of the cash distribution to be paid on February 9, 2009 with respect to the fourth quarter of 2008, with 1.1 times coverage for all of 2008.

We will now turn to segment performance. As I mentioned earlier, except for distributable cash flow, the financial and operating results for the partnership have been recast for the fourth quarters and years ending December 31, 2008 and 2007 to include results from the DEP II midstream businesses for the entire period, even though the partnership only owned these assets since December 8, 2008.

The Onshore Natural Gas Pipeline business segment reported gross operating margin of $33.3 million for the fourth quarter of 2008 compared to $41.2 million for the fourth quarter of 2007. The Texas Intrastate Gas System, a DEP II business, reported an $8.9 million decrease in gross operating margin, primarily due to a favorable gas imbalance settlement received by that business in the fourth quarter of 2007.

The Acadian Gas Pipeline System reported a $1.6 million decrease in gross operating margins in the fourth quarter of 2008, primarily due to slightly higher operating expenses during that quarter, and a gain received by Acadian on forward sales of natural gas in the fourth quarter of 2007 that was not received by Acadian in the fourth quarter of 2008.

Partially offsetting these decreases in gross operating margin were higher transportation volumes and fees from the Texas Intrastate System, and increased gross operating margin from our Wilson gas storage facility, which had operational issues in the fourth quarter of 2007.

Natural gas throughput volumes increased 17% to 4.9 trillion British Thermal Units, BTUs, per day compared to 4.2 trillion BTUs per day in the fourth quarter of 2007.

Our NGL Pipelines and Services business reported gross operating margin of $25.1 million for the fourth quarter of 2008, up from $24.9 million reported in the fourth quarter of 2007. Net of operational measurement gains and losses from the partnership's Mont Belvieu NGL storage complex, which are allocated to Enterprise and reflected on our financial statements as an adjustment to parent interest.

Gross operating margin was $28.1 million for the fourth quarter last year, compared to $23.6 million in the same quarter of 2007. This quarter to quarter increase was primarily due to higher storage revenues from increased excess throughput storage fees and volumes, and increased fractionation volumes at the partnership's fractionators in South Texas.

In addition to the Sherman Extension discussed earlier, another of our growth projects this year is the expansion of our Shoup NGL fractionator in South Texas. Together with Enterprise, we are investing approximately $13 million to increase the fractionator's capacity by 10% to 77,000 barrels per day. We expect to complete this expansion late in the second quarter of this year.

While NGL transportation volumes were 124,000 barrels per day in the fourth quarter 2008, compared to 136,000 barrels per day in the fourth quarter of 2007, fractionation volumes increased 13% to 81,000 barrels per day for the fourth quarter of 2008 from 71,000 barrels per day in the same quarter of 2007.

Sustaining capital expenditures on a 100% basis from both the DEP and DEP II assets were $15.8 million for the fourth quarter of 2008 and $54.2 million for all of 2008. This compares to $16.9 million and $62.6 million of maintenance capital expenditures spent for the three months and year ended December 31, 2007.

Interest expense increased $1.1 million to $3.6 million for the fourth quarter of 2008 due to higher average debt outstanding as a result of Duncan Energy's borrowing of $282 million in December of 2008 under a new bank term loan in order to fund the cash portion of the consideration paid to Enterprise in the DEP II drop-down transaction. Total debt principal outstanding at the end of 2008 was $484.3 million, compared to $200 million at the end of 2007, primarily as result of that borrowing.

We had total liquidity of approximately $110 million at December 31, 2008, which includes availability under the partnership's $300 million revolving credit facility, as well as unrestricted cash which was $10 million higher than at the end of 2007.

In closing, we had a very eventful and successful fourth quarter. We look forward to what we expect to be a solid year in 2009. Randy, we're now ready to take questions on Enterprise or Duncan Energy.

Valerie, we're ready to take questions from the audience now.

(Operator Instructions). Gabe Moreen, Banc of America / Merrill Lynch.

A question on expansion plans in the Piceance. In light of what a lot of the producers out there have been saying on their fourth quarter calls, you still feel pretty good about near-term expansions there, as well as earning a return on that capital you'll be spending?

This is Jim Teague. We feel pretty comfortable with where we are in the Piceance. If you take a look at -- what we're doing is we are expanding our Piceance Gathering System to tie into production that in some cases is already there, shutting down other facilities in order to bring that gas to our plant, and tying into wells that have been drilled and is waiting on our pipeline. I think Mike said in his comments, we expect by the end of the year to be in the neighborhood of 1.1 Bcf a day of processing at the Piceance.

I don't know, Mike, if you can comment in terms of -- or Randy, if you can comment in terms of what pricing levels you are hedged for NGL this year, and whether you have layer anything on for 2010 as well?

No, we don't give those numbers out. And frankly we continue to look at the markets and as those change as we go forward, we may actually put on more hedges. But suffice it to say, we did mention that we had laid on hedges for 2009 in 2008, so you can -- at least the prices are better than they were at the end of the year.

Mark Afrasiabi, PIMCO.

Just a couple of things. Let's see, on your hybrid securities you mentioned you had repurchased some. I guess there are two tranches, a pretty significant amount. They have been trading in the sort of $50 pricewise, sort of 16% to 19% yield, if you think of them on a yield to First Call. And that was how they were sold and everybody's assuming it is a par call on the first par call date as they were kind of initially issued.

The question is, given 16% to 19% kind of yields, those would be unlevered returns to you if you were to buy them back. Why wouldn't you be doing more of that? It would seem to make a lot of sense. It is a presumably higher return than a lot of your organic growth projects.

In November we did see a, if you would, a chunky piece of those securities -- again $17 million offered. And when we did see it, I think we bought it at about $0.58 on the dollar. So you're right, I think yield to First Call was about 16%. We did view that as attractive. And while in December you may have seen some of those trade down lowered in the 50s, they have since rebounded backup into the high 50s, low 60s. But frankly, while it may be quoted at that, there is not whole lot of volume at that.

So you guys are going to keep looking at that trade?

Yes, I mean, we will come in and take a look at that, because you're right, 16% to 18% return on that. And if you would, to a degree at those kind of levels, again, I think we will be deliberate in it, but you are coming in and trading, if you would, 50% equity credit for 10 years, you are basically trading that for call it 40%, 42% equity credit permanently. So that is attractive to us also.

One other thing then. In terms of the contracts with the processing, keep-whole and percentage of proceeds contracts, I was just wondering if you could just tell us the most up-to-date average contract length, and how long it would take you, if you will -- if you wanted to sort of free up the whole business and free up the assets, how long that would take you to run off the existing POP and keep-whole contracts?

I think if you look at the way those contracts are set up, and frankly you look at the production, we don't have necessarily long-term contracts for fixed periods of time. A lot of these are percent of proceeds the field, and so it really depends on how long that production continues.

In terms of our keep-whole exposure, virtually the only place we have any real keep-whole exposure is in the Rockies. That is what you had to do to get the business up there. If you remember, we've got two benefits from our position in the Rockies. First of all, we put in a lot of flexibility in those plants to be able to turn them down pretty dramatically. An example is one train at Meeker full out production and full recovery, it is about 35,000 barrels a day. When we turn that back to dew point, we are producing in the neighborhood at 3,000 barrels a day, still meeting downstream gas pipeline specs.

The other thing though is we have a pretty strong basis advantages in the Rockies. We feel like our basis advantage out there -- and our plants will be the last to be turned off and the first ones to be turned on. Even through this -- what we have been through in the fourth quarter, I don't think we were in rejection more than two days, so those plants continue to produce full out.

Everywhere else in South Texas we are primarily percent of proceeds and fee-based. In Louisiana we are primarily fee-based, percent of proceeds. And if you'll recall, a margin ban with our largest producer, whereby they -- below a floor they take the hit, about a ceiling they get the benefit. We get everything that is in the middle.

Darren Horowitz, Raymond James.

Congratulations on a good quarter. Jim, on the NGL side the business you discussed the five ethylene crackers coming online. Can you give us a sense of what you think that does to the domestic ethylene market, and also what it means to the supply demand balance?

I think Mike said in his quotes -- in his comments that we're talking about if those crackers come up in an ethane preferred mode, we would -- which we expect them to -- that it would be about 715,000 barrels a day of ethane. That is ethane from gas processing plants.

A lot of times what you see in the Hodson report, you'll see higher ethane numbers. They include in that the off gas that comes off of refinery units as an ethane. So when Mike says 715,000 barrels a day of ethane use, that is from gas processing. I would expect -- I'm going to ask Ordemann to help me -- I think probably if you look at the capability to produce in the 725 to 740 range, if everybody is full out producing ethane for processing. I will get the number for you.

If you look at where the petrochemical industry is and you look at the cost of producing ethylene today, ethane is the most advantaged feedstock by a long shot. It is some $0.15 a pound better off than naphtha. If you look at 1 billion pound a year ethylene plant, and you calculate that out, that is $150 million in the course of one year.

We expect as these crackers come back online, we think ethane will be preferred. We ran our models for our budget this year at about an 80% runrate for petrochemical plants. That would equate to somewhere between 750,000 and 800,000 barrels a day of ethane use from gas processing. We get in that level, we feel pretty good.

So you still feel pretty comfortable that the demand is going to be there?

I feel pretty comfortable that -- well, whenever you come out of a month where they ran at 57% -- I spent the first two weeks in a fetal position in the corner of my office. What we are seeing is we are seeing these guys come back up. I think we're seeing them run at about 72% -- about 70%, 75% we are expecting in February.

What we do is we go and we look backward. And when you look at the troughs that we have experienced in the past, an 80% runrate is a deep trough, and it is pretty traditionally where they run.

Dan will point out to you that the last trough we had, they ran at about 80%, but they were running heavy liquids at a better than -- at 100% of their capability. The difference this time is that the NGLs are the preferred feedstock. So We feel pretty good that we're going to get back to those levels. Those aren't barnburning levels, but the levels that we feel comfortable with and we feel like we will be fine at.

I appreciate the insight. Randy, just one big picture question for you. When you look at your liquidity profile as it sits today, and a lot of expectations out there for you guys to generate somewhere around $350 million in excess of what you distribute in 2009, can you give us a sense of how you consider balancing distribution growth versus retaining cash? Is that target of 5.5% to 6.5% year-over-year Bcf growth range still intact?

This is Mike. When we look at the distribution rates that we pay each quarter, we really look at amount of distribute cash flow we've got. We look at the CapEx that we've got. We look at where we are in the cycle of our construction projects. And clearly, if we are in the middle of a big growth cycle, where we've got a lot of capital employed and projects that haven't yet starting generating cash flow, our distribution coverage ratio is going to be a little lower.

We purposely have restrained distribution growth. We met our objectives, and we plan to continue to increase our distributions. But until we get more stable financial markets, we're not going to be heroes. We're going to continue to do what we have been doing, building facilities and increasing distributions on a quarterly basis.

Just one final question for you, Mike. And this builds off your prepared commentary. When you look at the external markets specifically for acquisitions, can you give us a sense right now of how wide the bid/ask rate is on multiples?

We haven't gotten into a bidding situation lately. But just looking at the assets that are on the market today, our view is that the sellers are perhaps a bit unrealistic about the multiples is going to take to clear the market. We do think, as we get deeper into 2009, that that bid/ask spread is going to narrow. And hopefully if the financial markets are cooperative, there may be some additional opportunities for a company like Enterprise with a strong balance sheet and a lot of liquidity.

Sharon Lui, Wachovia.

This question relates to DEP. There are several organic growth opportunities tied to the assets of that partnership acquired, including I guess the Wilson storage project, the fractionator that you mentioned. I was just wondering if you could maybe provide some color on what DEP's CapEx may look like in 2009 and 2010?

Right now I think -- I believe that Wilson storage is not actually included in the DEP II businesses. Those are still owned by Enterprise. At some point when those are completed, we would have the ability to invest in our share of those assets.

But again, we do have -- we're still finishing up right now the Sherman Extension Pipeline. We have the Shoup fractionator. We're looking at -- there is an extension off of the Sherman Extension that we would have the opportunity to participate in. So I think right now our capital program for 2009 looks pretty robust.

Would you be able to quantify what DEP's capital requirements would be?

Randy, do you want to --?

I think we're in pretty good shape. You come in and you look -- I want to say probably at the end of the quarter the liquidity at DEP was around $90,000 to $100 million. So I think we are pretty good shape on that front. I think for the most part with DEP's ownership percentage and the way the partnership agreement works, DEP could elect to invest more or less in projects like the Trinity River Basin project, and it would just work off that priority return.

In the Shoup fractionator, again, I think that is a modest size, that is only a $13 million growth CapEx project. And DEP would do about 66% of that. Again, I think it is all manageable from a DEP standpoint.

Ross Payne, Wachovia.

Randy, you gave us the leverage numbers with the hybrid and then pro forma for your equity offering here. You obviously did incur a lot of debt with the Sherman Extension, Meeker II and Shenzi. If that EBITDA were rolled into -- rolled up, what would the pro forma leverage look like with that added cash flow?

It would look better. We would love to put those numbers in a press release, but unfortunately the lawyers and the accountants would have a heart attack. Obviously with over $2 billion of capital going into service in 2009, we have spent a lot of money that, as you point out, isn't generating cash flow yet. But obviously if you did the kind of pro forma, including the 12 months of cash flow associated with those projects, as Randy said, it would look considerably better.

Can you give me maybe a rough idea what the debt associated with those projects was that was not currently -- which is not currently generating cash flow, maybe just a ballpark?

In coming in and looking at it, I want to say you probably -- about everything is baked in. From a standpoint of Sherman, again, we're just finalizing that project, so maybe call it $460 million or so of that project has already been spent. You come in and you look at Meeker, maybe about $470 million has been spent. If you come in and you look at the Shenzi Oil Pipeline, maybe about $150 million has been spent. Those are the chunkiest ones.

Then I will just apply a multiple that I think is reasonable to the back end of that.

We have also got the Exxon central feeding facility that is complete, just waiting on gas.

This is Dan. If you add all those things up Randy was talking about, it is about $1.6 billion to $1.8 billion that we would start making EBITDA on in 2009 that we did not make in 2008. Some of that comes on beginning in first quarter. The majority of it will probably come on in first quarter. A lot it will come on -- a little bit of it will come on the second quarter, and some in the third quarter.

Michael Blum, Wachovia.

Just a quick one. The $800 million that you have slated for '09, I guess jumping on Ross' question, can you just break that out a little bit in terms of what the big buckets are?

And then in terms of return, can you talk about ballpark what that looks like? And then going forward for incremental projects, does that change in terms of what the hurdle rate is on new investments?

Let me take the last half of that, and I will let Randy give you an idea of what the projects are. In terms of the returns that we have on specific projects, we don't give that. But, as it may have been a leading question, obviously in todasys market we expect, as do all of our peers expect, higher returns on assets. And that is not only for newly constructed assets, but it is for existing assets when they come up for contract renewal.

Then as far in 2009 probably the chunkier pieces of that would be the Trinity River Basin lateral, which is about $225 million, call it. Completing the Sherman Extension is probably about another $40 million. If you come in and you look at the Marathon Gathering and the other Piceance Basin natural gas pipeline work that we're doing, that is probably about $165 million. That is sort of the chunkiest ones. Everything else sort of gets down to $20 million here, $30 million there.

Brian Zarahn, Barclays Capital.

A lot of MLPs are looking at cost savings in 2009, can you comment on anything you're looking at?

2009 is probably not that different from the last half of 2008. We try to maintain a pretty tight partnership in terms of costs, but clearly in this market a couple of things are working for us. One is that we have got a substantially smaller CapEx budget. So we've got a lot of people that we had used as contractors that frankly we don't need with a smaller CapEx budget.

We have also had a large number of open positions, and really across all of our disciplines, primarily I guess in engineering, operations, IT and accounting. And frankly had a very difficult time filling those positions. Now we're going back and reevaluating all of our open positions to see if we still need them. So to the extent that they are critical, we will fill them. To the extent we don't need them in this kind of environment, we're not going to fill them. And we are requiring everybody that has those open positions to go back and rejustify them.

We're also looking across the Company at staffing levels and making sure that if perhaps we have overstaffing in certain areas and understaffing in others that we move people around to balance that out. So we're doing things that make sense for our partnership today.

We're also continuing to look at the cost of our equipment and our capital items. Steel costs have gone down. Our procurement guys do a great job of sourcing materials at the lowest cost. And they are pushing on our vendors to get costs down as well.

I think we're taking the same kind of steps that most other partnerships and companies are taking, for that matter, but we try to do that every year regardless of the financial markets.

And looking at Duncan, can me remind me what the distribution growth target is? I heard it early in the call. Is it 3% or --?

3%. The rate -- the going growth rate is 3%.

Versus full year 2008?

Yes.

Steve Maresca, Morgan Stanley.

A lot of my questions have been already asked, but you mentioned obviously in the light of the current environment that you are being more specific and prudent in terms of where you spend your money for growth CapEx. If the markets do open back up and things do improve throughout the year, where are the areas that you're looking at other projects -- where are those opportunities, what segments, what areas are you looking at?

I think that they are really across the board for our natural gas liquids pipeline and services and for our natural gas pipelines and services. That is probably the two areas that we're going to focus on the most. Not a whole lot planned on petrochemical or the offshore, although we have -- obviously the TOPS is a big project for us, and that probably is enough to say grace over there.

Then just a quick follow-up. Obviously you mentioned a couple of minutes ago we had a higher capital cost environment, and you are requiring higher rates of return on assets. How does that translate specifically when you are entering into these new projects? Are you just requiring more upfront from counterparties and customers, charging higher rates? How does that where in practice, given your debt and equity costs with where they are now?

I think it is across the board. I think it is the fees that we charge for our services primarily. But clearly we've got a lot of assets. We have contracts are coming up for renewal. Some of our storage assets in Mont Belvieu, we have been successful in increasing the rates there. And frankly our customers understand the need for it.

John Tysseland, Citi.

Great quarter. Real quick, a couple of questions, just could you guys discuss EPD's NGL inventories at the end of the year, and how those might have changed from third quarter to fourth quarter? And then also how much of those inventories have you really sold forward with kind of your previous comments?

In terms of EPD inventories, John, as you know, we have a policy of a flat pricing book, so we are not out growing inventories, other than you heard Mike mention our contango play. We built inventories with that, but we have sold those forward to retain the flatness of our book.

Then in light of the current environment where you saw some of the petrochemical companies coming down or reducing utilization rates, do you see that changing at all in 2009 in terms of being able to take advantage of any opportunies, or do you expect to just kind of keep on what you have been doing and maintaining that flat book, and just playing it real conservative?

We're going to keep doing what we're doing. That is a policy of ours. But the system is -- our system is quite dynamic, and it gives us the opportunity to arb the system either within locations, between locations, or timing, and that is what we have been doing. We see ourselves continuing to do that to the extent the market gives it to us.

As we said earlier, we have seen increased pools from petrochemicals beginning in February that we think is pretty positive, and we expect it to continue. In addition, we have seen unbelievable activity on our export docks, as Mike said, at higher fees than traditionally we have charged. Just so far in January and February and what we have locked in March, we're right at 7 million barrels. And we are seeing fees of $0.07 to $0.08 a gallon, where traditionally that would have been more like, Dan, $0.025? In that range, $0.025 to $0.03 a gallon.

So validating what Mike said, what we're doing is we're getting higher fees. And what happens in the system is whenever we see problems in one area, it is almost like it is inherent, John, there are opportunities in other areas.

That is great clarity. I appreciate it. Thanks, Jim.

This is Dan. Let me give you a little bit more color to it. There is industry publications that showed inventories of natural gas liquids, and along with natural gas and crude oil and everything, if you go back to industry publications, they talk in inventories in total, versus what we talk about as what Enterprise's inventories are.

If you go to EIA, propane is probably up 10% to 15% over last year's (technical difficulty). If you go to API on ethane, it is probably up 50% to 75% on total. Butanes are up. All you NGLs are up. So if you look at total inventories on an API type deal, which comes out once a month, about a month late, it is probably -- natural gas liquids inventory, to your question that you asked, it is probably up close to 75%, 80%, which is basically what crude oil is up in -- like cushion, I think cushion is at all-time high on crude oil right now.

I think if you looked at Mont Belvieu from an industry prospective deal, probably Mont Belvieu is at an all-time high, or close to being an all-time high on natural gas liquids. That doesn't mean that we feel that natural gas liquids will be weak next year. If we go back, Jim mentioned before, for 2002, 2003 (inaudible) when we was operating at 80% of capacity, the heavy end of the package then, because of crude oil being cheap, they was operating at over 100% capacity. Where the light end at that time, I will call it gas, was high-priced relative to crude oil, gas was operating about 55% or 60% of capacity.

What we see now in the petrochemical market this year is based on today's prices of natural gas, and based on today's prices of crude oil, once you skip -- you get by the one month, which has been affected by WTI. Or if you look at the Brent crude oil, which is now more the actual probably crude oil posting that the international market is looking at instead of looking at WTI, we feel that the natural gas liquids market, which is a light end market petrochemical, would be operating at 100% to 110% plus of nominal capacity. Nominal capacity gives them a downtime probably 30 days every year. But they can operate 15 and 18 months at all out capacity, and [I appraise] basically 110% of our actual capacity on liquids. So we think that will happen this year only because of the ratio between crude oil and natural gas.

John Edwards, Morgan Keegan & Co.

Just to clarify, I think in the release you indicated an increase in the gas marketing business over the prior year. Just I didn't see what the number was, if you could --.

In the natural gas marketing business?

Yes.

It was about $6 million or $7 million. But remember in the fourth quarter of 2007 it was still under development.

That is what I wanted to confirm. So it was basically $7 million against zero?

About that, yes.

In terms of -- you mentioned you've got $800 million of announced CapEx with a healthy backlog. Can you -- any quantification about roughly what that backlog of potential projects might be should capital markets ease up a bit?

When we went through looking at 2009 capital budgets, we had our commercial guys kind of list everything that they would like to do, the projects that they thought would be attractive for Enterprise. And we pared that back from about $3.5 billion to about $800 million. So it is a big backlog. The good news is most of those projects aren't going away. So if the markets come back to us, we have plenty to draw upon, and they certainly are there for 2010 and beyond.

Then on acquisitions, obviously there are distressed assets -- some distressed players our there. Maybe you could comment on potential consolidation this year.

We get that question frequently. It seems like every year we get it. But you are right, in this year there are more distressed players. It is difficult for us to think about doing a merger with another MLP simply because probably can't find an MLP where we like all of the assets, or that we would actually be able to keep all the assets and not being forced to divest by the FTC. So I think what is more probable for us is looking at discrete assets that companies or partnerships might be selling as a way to raise liquidity. And frankly, that would be more attractive to us right now.

With regard to the distribution, you have been raising at $0.0075 per unit per quarter for awhile, is it safe to assume you're likely to continue doing that for '09? Because I didn't hear you mention a target exit rate for '09, like for '08 I think you had targeted $2.12, which you have kept to.

We haven't given a target for exit rate in 2009, but your assumption wouldn't seem unreasonable to me.

Yves Siegel, Arroyo Capital.

Could you just elaborate a little bit on the natural gas marketing as it relates to, one, invested dollars? Number two, given the winter summer spread, what kind of opportunity that might present? And within the context of the first two questions, is $7 million a reasonable runrate to the next quarters going into '09 or would you expect to build significantly upon that?

This is Chris. With regards to first part of that question, the $7 million runrate for the fourth quarter, as typical in the gas marketing business -- and you hit the nail on the head in regards to the winter/summer spread. We ought to recognize probably 50% to 75% of our earnings in the first and fourth quarter, and the balance over the second and third quarter.

With the spreads meds opening up right now, as we went in through '08 we only had 7 Bcf of total storage capacity leased. As we look into '09, we're looking to have around 12 to Bcf of storage. So with regards to working capital, I don't think we have peaked above $40 million last year in total working capital. And that with a $10 gas environment in the spring. Now we are looking at a $4 gas environment.

Even though we're (technical difficulty) [dulling] our capacity, I don't think our working capital requirements are going to be at all (technical difficulty). We're very favorable with regards to the $2 and $2.20 spreads front to back. We're very active. Much like Jim said earlier in the NGL business, we run a flat book, so we have plenty of assets to arbitrage and take advantage of price through the assets as opposed to having picked flat price risk.

Let me add some color to what Chris is (technical difficulty). His department is not only is in the deal of marketing natural gas and building up that market, his (technical difficulty). That also gets into our (technical difficulty). We also get involved on pipeline (technical difficulty). So the amount of money that we were looking at, like $7 million, that only related to what the profit he made as a marketing company on things that he's doing. It did not relate to all the value that he brought to the Enterprise (technical difficulty) that he is coming into Enterprise in the future. A lot of the gas throughput that we're now getting that we would have if he had not [bid in] here.

A lot of his value (technical difficulty) that we've got, and that is leading a lot of our other assets with an increase from this year over last year. In fact, I think last month, just to pick a number, I think January he come in and we had never done this before, other than last year, we went to gas daily on all of our fuel. And a lot of our [PTO] rather than going to that first. So that was several million dollars that he made in the month of January that doesn't show up with him as a marketing company, but it does show up on our book.

We keep a running scale of what every department does. So we count as Jim Teague and his deal and Bill Ordemann in there. Bill is in charge of all of the assets and the cost of them, where Jim is in the marketing side.

We keep those type of things within the Company to figure out how our people are doing and how they are doing things relative to all of our peer groups. That is where he has come into play also. I just wanted to get that color out.

In addition to that, Chris has storage -- from our storage subsidiary that he pays for, so that is a cost to him. It is income to the storage affiliate. The same thing with the pipeline, where he is saying pipeline rates for capacity, it is showing up as revenue for the pipeline affiliates and a cost for him. So the $7 million is after all of that.

Just two follow-ups to that. Number one, Chris, how much does it cost today to cycle gas from storage?

On a variable basis or what the rental fee for the actual capacity for the storage itself?

The latter. I'm trying to handicap how much can you actually bring to the bottom line on a $2 spread?

On a salt facility -- on a salt dome facility you need more than $2 spreads to make money. On a traditional reservoir a $2 spread will make you money. Typically your under lease -- typical reservoir storage winter/summer, you're looking at about $1.80 is your cost.

So by the time you get your carrying cost and all the things in there, it is about a breakeven proposition to be honest. It is a matter of how do you use that facility, and don't worry about the winter/summer spread as much as the weekend/weekday cash market and futures market our -- moves at a difference speed. If cash and the futures move in the same in unison with each other, storage is less valuable.

But like, for example, you will see weekends at Waha, that will it will go down to -- in the middle in December we were buying gas at $2.80 out at Waha on the weekends and selling it at $3.80 doing the weekdays. So a $1 spread weekend to weekday, where the futures as you see in the NYMEX looking on the newspaper every day, you see that $2 spread, and say, well, that is good money. That is good money, but it is how you use it on a daily basis is where really the value is.

I promise, my last couple of questions here. One is is there need for additional storage capacity? And do you think Enterprise will boost the budget to do that? The second is, could you just elaborate why expenses are going up on the intra and the Texas Intrastate System?

Let me take the first crack at the storage. There's a lot of new storage facilities that are being put in play. We've got record amounts of gas, it seems, that are in storage every week. But we have decided not to do a lot more in developing additional storage at Petal or some of our other facilities. We do expect that Chris will continue to look at storage assets owned by third-parties and contract for some of that capacity in locations where it fits his business. But right now we don't see a need to own substantially more.

As far as your question on -- as far as the expenses on the Texas Intrastate, a couple of things. One, as Hank mentioned in his notes on DEP there was actually an imbalance settlement in the fourth quarter of 2007. And that is a favorable settlement, so if you would, that reduced operating expenses in the fourth quarter of 2007 compared to 2008. So it wasn't necessarily that you were seeing a big increase in other operating expenses. Pipeline integrity expense was up a little bit, but not that much. It was mainly more attributable to that settlement.

[Shaumo Sadhukan], Lotus Partners.

My question is are you guys seeing any situations where, because of low gas prices, producers a cutting back drilling? I understand that you have -- you have your pipelines basically fully subscribed out for the next five or six quarters. But are there any situations where, if I look say eight or ten quarters out, we could have a situation where producers are cutting back drilling because of lower commodity prices, and now once your pipelines -- once the five or six quarters that you have where you are fully subscribed, once that runs out, you may be running at less than 100% capacity or something below your ideal capacity, because they're just isn't as much gas coming on at lower commodity prices?

This is Jim. I think our view is if prices go too low and too many rigs are laid down, the price boomerangs and rigs come back up. And that is the reality of the market. So, no, I'm not really concerned about three years down the road not having anything in the pipe.

Jim also had mentioned earlier that there are a number of wells that have already been drilled and waiting on assets to get complete so that they could connect. There is no reason to expect that is not going to happen. That is new gas supply.

What is the price at which your incremental capacity is coming through your pipe? Meaning, at what price do you feel like you need to where the pipes are basically fully subscribed over long periods of time?

It is really more of a function of what is the price of gas and which locations.

It varies by location. If you are -- in one location you may need $4. If you are in another location $3 works. I guess also you probably hadn't seen the service companies' fees coming down yet. As those come down then that price you need becomes even lower.

And the finding and development costs make a difference too. And frankly, we're focused more in the areas with a lower finding and development cost.

This is Dan. Let me add a little bit of color on the natural gas liquids, which also affect the amount of gas that is produced. If the drilling activities continues to go down, and let's say they do produce less gas -- we don't think they will. They may not grow a lot of natural gas, but we don't think it would be reduced by any sizable amount.

But if they do reduce gas and you do get less natural gas liquids, then there's a lot of natural gas coming on in the Persian Gulf, in Qatar and Egypt, and West Africa. [At those times] those also (inaudible) on natural gas liquids over there. So if you do back off gas here, and you back off liquids, then we have the only major import terminal that feeds the total industry, not only the petrochemical industry, but the refining industry too, and the home heating [build]. So those volumes would be brought in to our import terminal. And based on that, we make the same amount of money off of our import terminal or export terminal, every which way we would go, as we would from the (inaudible) liquids that comes on in Wyoming and Colorado. We have the same revenue stream coming into us based on the overall demand in the United States.

Now if you take the worst-case deal you could dream of, and everybody goes down in the United States, I think the whole economy to some extent would be affected. But I think under that particular case, we would be affected to some extent, but we would probably be less affected than the company that in the business. So I think anybody that is in the pipeline business gets less affected.

But if we lose that last 10% volume in our pipeline, that is not a major profit. That first 10% is a major profit on the pipeline, because of moving either gas, crude oil or natural gas liquids through a pipeline. When you get into that what we call full pipeline, you make very little profit off of them on that last increment because of your operating cost.

Thanks for the color. I appreciate it.

Valerie, this is Randy. We have time for one more question.

Sir, there are no further questions.

Valerie, if you would, would you give our listeners the replay information?

The replay number for this call is 1-866-501-0094. Once again that is 1-866-501-0094. Thank you for participating in today's conference call. You may disconnect at this time.