Enterprise Products Partners LP (EPD) 2012 Q4 法說會逐字稿

Good morning. My name is Regina and I will be your conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners fourth-quarter 2012 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions) We ask that you please limit yourself to one question and one follow-up, (Operator Instructions).

Thank you. Randy, you may begin.

Thank you, Regina. Good morning, everyone. Welcome to the Enterprise Products Partners conference call to discuss results for the fourth quarter of 2012.

Our speakers today will be Mike Creel, President and CEO of Enterprise's General Partner, followed by Jim Teague, Executive Vice President and Chief Operating Officer, and Randy Fowler, Executive Vice President and CFO. Other members of our senior management team are also in attendance.

During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934, based on the beliefs of the Company as well as assumptions made by and information currently available to Enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, we 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.

Thanks, Randy. 2012 was an exceptional year for Enterprise. We set a number of financial and operating records, which is remarkable, given the challenging ethane and propane commodity markets for much of the year, and the market's uncertainty around the financial problems in Europe and the US elections.

Our record financial performance in 2012 includes net income of $2.4 billion, earnings per unit of $2.71 on a fully diluted basis, gross operating margin of $4.4 billion with improved results in four out of our five business segments, and distributable cash flow of $4.1 billion, which included $1.2 billion of proceeds from the sale of non-core assets. We ended the year with a strong fourth quarter that produced record gross operating margin of $1.2 billion, and adjusted EBITDA of a little over $1.1 billion. This led to net income of $617 million or $0.68 on a fully diluted basis for the quarter.

Net income included losses of $27 million or $0.03 per unit on a fully diluted basis for non-cash impairment and other similar charges. Distributable cash flow provided 1.5 times coverage of the distribution paid with respect to the fourth quarter of 2012.

The NGL Pipelines & Services segment reported gross operating margin of $632 million for the quarter, only slightly below the $635 million for the fourth quarter of 2011. Our natural gas processing and related NGL marketing business reported a $66 million decrease in gross operating margin for the quarter, compared to the fourth quarter of 2011. And this was due in large part to lower processing margins and equity NGL production volumes, primarily from our Rocky Mountain, Permian Basin, and East Texas facilities.

Our fee-based natural gas processing volumes continue to increase, reaching a record 4.7 billion cubic feet a day this quarter. And that's 15% higher than in the fourth quarter of 2011. Our NGL Pipelines & Storage business reported a $50 million or 29% increase in gross operating margin for the quarter, supported by record pipeline volumes of 2.5 million barrels per day.

Enterprise's South Texas NGL Pipelines, which includes the new Eagle Ford NGL Pipeline completed in mid-2012, reported a $27 million increase in gross operating margin on higher volumes. Our NGL fractionation business continues to perform well, earning a record $82 million of gross operating margin this quarter from a record volume of 707,000 barrels per day.

We had a $24 million increase in gross operating margin from our Mont Belvieu NGL fractionators on a 32% increase in volume. Our sixth NGL fractionator at Mont Belvieu began operations in October of 2012. And the seventh and eighth fractionators are on schedule to begin operations in the fourth quarter of this year.

The Onshore Natural Gas Pipelines & Services segment reported gross operating margin of $210 million for the quarter. That's an 8% increase over the fourth quarter of 2011 and another record. We had an $18 million or 29% increase in gross operating margin from our Texas intrastate system, with a 9% increase in volumes, reflecting the strong production increases from the Eagle Ford Shale. Our Acadian Gas system reported a $14 million increase in gross operating margin as a result of a full quarter of operations from its Haynesville extension pipeline that began service in 2011 -- November the 1st of 2011.

Our Onshore Crude Oil Pipelines & Services segment continues to knock it out of the park, reporting record gross operating margins of $135 million on record crude oil pipeline volumes of 897,000 barrels per day. This segment more than doubled the gross operating margin it generated in the fourth quarter of 2011.

Our South Texas crude oil pipeline system, which includes the new 24-inch pipeline from Lyssy to Sealy that began service last June, contributed $27 million. And our share of Seaway's earnings increased by $13 million, with a full quarter of operations after the reversal of the pipeline. We completed modifications and upgrades to the pumps on the Seaway long-haul pipeline earlier this month, which increased the maximum capacity from 150,000 barrels per day to 400,000 barrels per day.

The Offshore Pipelines & Services segment reported gross operating margins of $42 million in the fourth quarter of 2012, compared to $60 million for the fourth quarter of 2011. Lower demand fee revenues and volumes from the Independence Hub and Trail Pipeline led to a $20 million decrease in gross operating margin. The Independence Hub platform earned demand fees of $4.6 million per month from the time it began operations in March of 2007 until the demand fees ended in March of 2012. Partially offsetting this decrease was a $6 million increase in gross operating margin from our offshore crude oil pipelines, which benefited from improved results from the Constitution, Poseidon and Cameron Highway pipelines.

Currently there are 37 deepwater semi-submersible rigs and drillships active in the US Gulf of Mexico, and another nine are expected to arrive by the end of this year. Approximately 45% of these rigs and ships will be focusing on existing fields, many of which are connected to Enterprise assets.

Our Petrochemical and our Refined Product Services segment reported gross operating margin of $143 million in the fourth quarter of 2012, and that's a 4% increase over the fourth quarter of 2011. Our refined product pipelines and related services business reported a $35 million increase in gross operating margin, primarily due to lower pipeline repair and maintenance expenses and improved marketing margins, which more than offset a 25,000 barrel a day decline in pipeline volumes.

Partially offsetting this were lower propylene fractionation volumes and sales margins, decreased butane isomerization volumes, and revenues from the sale of by-products, and lower volumes from our octane enhancement facility. Collectively, these businesses reported a $31 million decrease in gross operating margin this quarter, compared with the fourth quarter of 2011.

We normally do our turnaround on the octane enhancement facility in the first quarter of the year. However, in this year of 2012, we started early on the 2013 turnaround and started in December instead. And so we had a decline in the gross operating margin from that business, simply because of the timing of the turnaround. That facility did resume full operations in mid-January of this year.

We had $2.9 billion of major capital projects that began service in 2012 and started generating fee-based cash flows. We expect to complete another $2.4 billion of projects this year, and we have an additional $4.8 billion of projects under construction that are scheduled to be completed in 2014 and the first half of 2015. The revenues from these projects will be predominantly fee-based and supported by long-term contracts. In addition to building new projects, we're also repurposing certain assets to enhance our return on those assets, meet customer needs, and provide solutions for industry bottlenecks.

Last May, we reversed service on the jointly-owned Seaway crude oil pipeline, reducing the bottleneck at Cushing, and providing much-needed domestic crude oil for the refineries along the Texas Gulf Coast. This month, we've completed modifications to the remaining pumps along the pipeline to enable it to transport up to 400,000 barrels a day.

Another project utilizing existing assets to meet customer needs is the development of our ATEX pipeline to move ethane from the Marcellus/Utica Shale areas to the US Gulf Coast. We're building a new pipeline from the producing area to an interconnect in Indiana with an existing refined products pipeline that we own, that will be converted to flow ethane south to the Gulf Coast. Through ATEX, producers will have access to the largest ethane markets along the Gulf Coast. Our commercial engineering and operations teams are doing a great job in developing growth and expansion opportunities for our partnership, and to meet the needs of our customers.

Our disciplined approach to managing the balance sheet includes retention of cash to lessen the need to access the equity capital markets. We retained approximately $1.9 billion of cash flow in 2012. And since our IPO, we have retained $5.3 billion or 29% of the total distributable cash flow generated during that period. We continue to have strong coverage of the cash distribution paid to our partners, with distributable cash flow providing 1.9 times coverage of the cash distribution paid with respect to 2012. Excluding the $1.2 billion of cash proceeds from the sale of non-core assets, our coverage was 1.3 times.

The record distributable cash flow generated by our fee-based businesses enabled us to increase the cash distribution to our partners each quarter in 2012, extending our track record of distribution increases to 34 consecutive quarters. The distribution we declared with respect to the fourth quarter of 2012 will be paid on February 7. And it's 6.5% higher than the distribution with respect to the fourth quarter of 2011.

In addition to our growth story, we also set some important safety records. Enterprise had a very good record with respect to safety performance, with total recordable incident rates that easily beat industry averages and continue to improve year-over-year. Safety is a core value at Enterprise, and we have a strong top-led, employee-driven safety culture. At Enterprise, safety has been and will continue to be a primary focus. And while we are proud of the safety accomplishments of our employees, our goal is to have no incidents.

We continue to provide our unitholders with attractive returns. With our three, five and 10-year total returns of 23.5%, 16.7%, and 17.3%, respectively, we outperformed nine other diverse asset classes that we track, including the Alerian MLP Index. Our disciplined approach to allocating capital in managing our assets has served us well, and we are pleased that our accomplishments have been recognized.

In 2012, our investment grade credit ratings were upgraded to BAA2 and BBB flat by Moody's and Standard & Poor's, and both of the agencies maintained their favorable outlook for our partnership. Enterprise was also recently recognized as one of the most honored companies by Institutional Investor Magazine in the natural gas MLP sector. These accomplishments would not have been possible without the dedication and hard work of our employees and the disciplined leadership of our management team.

Our team is focused on the common goal of providing the best total return possible to our partners, which includes our employees. Our senior management team and our employees are also investors in Enterprise, so you can rest assured that our interests and goals continue to be closely aligned with those of our public unitholders.

Before I turn the call over to Jim, I'd like to thank our debt and equity investors, our customers, and our bankers for their continued support. 2012 was an exceptional year for our partnership, and we look forward to new opportunities in 2013.

And with that, I'll turn the call over to Jim.

Thank you, Mike. In order to address where we are, I'd like to take a moment to reflect on where we've been. In 2005, Louisiana was devastated by Hurricane Katrina. During that storm, all of our Louisiana operations were impacted, some for as long as a year. Revenue from assets like Pascagoula, Promix, Norco, Calumet, Neptune -- virtually all our assets in Louisiana--revenue came to a standstill.

However, a problem in one area invariably creates opportunities in others, and we capitalized on those other opportunities and we achieved our financial goals. In 2008, when the financial meltdown hit, crude oil went to $35 a barrel and ethylene plant operating rates went to 55%. While our processing spreads collapsed, we found other opportunities. We captured those opportunities and we achieved our financial goals.

In February 2011, when we suffered a devastating fire at our West storage site at Mont Belvieu, that would have crippled most other companies, we found ways to overcome the effects of this event. And we did that in days -- not weeks, not months -- and we met that quarter's financial goals. Now we're in the midst of another storm. This time it's a tsunami. It's the tsunami of natural gas liquids, especially in the light end of the barrel.

The old axiom that price creates supply certainly proved to be the case in NGLs. But price also creates demand, as evidenced by ethylene plant furnace conversions to use more NGLs, and the announcement of new crackers and significant expansions by companies like Dow, Exxon, Sasol, Formosa, Chevron Phillips -- virtually every ethylene producer is expanding for more NGLs.

Price will create demand, but not overnight. Consequently, ethane extraction economics for the next couple of years are likely to be anemic on average and volatile, as ethane rejection and cracker outages swing supply/demand balances. But margins are good for other parts of the NGL barrel, and producers remain incentivised to drill rich gas.

Propane is enjoying a better winter than last year. Its relative weakness, I believe, is a reflection, at least in part, in the delay in our export expansion. We believe that once our export expansion is online, propane prices will strengthen. Finally, the heavy end of the NGL barrel is strong, and we have exceptionally strong demand for the C4-plus components driving those spreads beyond our expectations.

As with other storms we've weathered, this tsunami will result in Enterprise capitalizing on new opportunities. For example, this storm enhances the value of our export expansion. The 40 million barrels we exported last year will grow to over 60 million barrels this year. What we have targeted to sell over our export dock, we have sold. But we have purposely left open a slot a month for spot opportunities or operational issues, and have been enjoying even greater margins on our spot cargoes. That expansion will be online in mid-February.

Our crude oil business will have a full year of our Eagle Ford crude oil system from Lyssy, and over six months of benefits from our joint venture system with Plains out of Gardendale. We'll have a full year of the Seaway reversal at a capacity on a WTI basis of 400,000 barrels a day. The demand for this capacity is strong. And in addition to the tariffs, the capacity we took out as Enterprise is paying additional benefits.

We're in the process of commissioning our third train at our Yoakum processing complex. That complex, which was designed to process 900 million cubic foot a day, is testing during this commission at over a Bcf a day. And we've touched north of 125,000 barrels a day during our commissioning. Yoakum could easily be the single largest producer of NGLs in North America.

And our Texas and Louisiana intrastate natural gas systems, that not that many years ago transported 4 Bcf a day, are now approaching 7 Bcf a day. With the third train of Yoakum up and running, all of our fractionation trains will be running at capacity, even in an ethane rejection environment. And we still expect to need to move product to Louisiana for fractionation. As Mike said, our seventh and eighth fractionation trains are due to be online in the fourth quarter. What he didn't say is they will be full at startup.

Further out, we're making progress on our Seaway loop, our lateral to ECHO, and our pipeline to Beaumont/Port Arthur. That system will be completed by the first quarter, with our ECHO lateral online the fourth quarter this year. We have two tanks up and running at ECHO, with another expected to be available in February. We are constructing three more tanks that will have an additional 900,000 barrels of capacity, and be up and running in early 2014. And we are permitting additional tankage, and know exactly what we want to build.

Our Texas Express NGL Pipeline comes online in the third quarter of this year; Front Range, the fourth quarter of this year; our Rocky Mountain expansion, the first quarter of next year. These projects add over 450,000 barrels a day of capacity. ATEX is under construction, and will be online the second quarter of '14. The neat thing is all of these projects feed our Mont Belvieu fractionation and storage systems, and they are all backed by firm demand fees and volume guarantees.

So 2013 will be the year of all the Eagle Ford systems, the Seaway systems, our export dock expansion, and a partial year for our Texas Express and Front Range projects. 2014 will be the year of the pipelines -- the Rocky Mountain expansion, the Seaway loop, the pipe to Beaumont, and ATEX. And 2015 will be the year of the PDH plant. This 1.65 billion pound a year plant is sold out to four customers, and we have folks talking to us, seeing if we're interested in building a second PDH.

At Enterprise, our role has always been to provide services on both the supply and demand side of the equation. We focus on giving our producer customers flow assurance and market choices. We focus on giving our end-user customers supply reliability and supply flexibility. That's fueled the growth we've experienced; it will fuel the growth that we expect.

Finally, having what I believe are the most driven and dedicated employees in the industry ensures, as you saw in the beginning of my comments, we always find opportunity in challenging markets.

And with that, I'll turn it over to Randy.

Thank you, Jim. I'll take a few minutes to go over and discuss additional income statement and balance sheet items. General administrative costs decreased to $40 million in the fourth quarter of 2012 from $44 million recorded in the fourth quarter of 2011, primarily due to expenses related to the sale of our Mississippi natural gas storage facilities in December 2011, and the merger with Duncan Energy Partners.

In terms of interest expense, it increased to $199 million for the fourth quarter of 2012 from $183 million recorded in the fourth quarter of the prior year. The $16 million increase is primarily due to $1 billion increase in our average debt principal balance.

In terms of capital spending, we had capital spending of $1.2 billion this quarter, including $1.1 billion spent on growth capital. The majority of this was for our Eagle Ford development projects. For the year, we spent approximately $3.9 billion on growth capital projects. And we expect to invest approximately $4 billion in 2013 on growth capital projects, that will begin generating additional fee-based cash flows in the second quarter of this year.

Sustaining capital expenditures were $366 million in 2012, and we expect to spend approximately $350 million for sustaining capital expenditures in 2013. Adjusted EBITDA for the 12 months ended December 31, 2012 was $4.3 billion. Our consolidated leverage ratio of debt principal to adjusted EBITDA was 3.56 times at December 31, 2012. And that's after adjusting debt for 50% equity content in the hybrid securities. The average life of our debt was 12.4 years, using the first call date of the hybrids.

We had consolidated liquidity of approximately $3.2 billion at December 31, 2012. That includes the availability under EPD's credit facility as well as unrestricted cash. Affiliates of privately held Enterprise Products Company, which own our General Partner and 38% of our outstanding Limited Partner units, have expressed their willingness to invest at least $100 million to purchase additional EPD common units in 2013. The first purchase of which will be through the DRIP dividend reinvestment plan in connection with the distribution that we will pay on February 7.

Before I open up the call for questions, I'd like to mention that we expect to complete the mailing of our 2012 Schedule K-1s by Thursday, March 28, 2013. They also will be available online by noon Central Time on Friday, March 22. This should be the last year our K-1s are mailed out this late in the cycle, given that we sold our remaining interest in Energy Transfer Equity in 2012. So when 2013 -- with respect to those K-1s, that will be mailed in 2014, we think we'll be back to our traditional slot of mailing those out in late February of 2014.

With that, Randy, we can open it up for questions.

Okay, thanks, Randy. Regina, we're ready for questions.

(Operator Instructions). Darren Horowitz, Raymond James.

Jim, I want to go back to your comments on ethane extraction economics being anemic. And I know you've seen cycles like this before, but as it sits today, we've got somewhere around 35 million barrels of ethane in storage. The market is running close to 175,000 barrels a day of ethane rejection. And ethane pricing is pinned to the mat, trading just below fuel value, around $0.20.

So how long do you think ethane pricing can remain at that level? And do you see anything on the horizon that can help balance the market? Or do we have to wait until those new crackers come online in 2016 and 2017?

I also said in the comments that I think it's going to be quite volatile. I think what you're going to have are periods of time, when it looks like it's a good deal to extract more ethane, because right now, for example -- and I'm not going to give you exact number -- but we're seeing some fairly strong draws of ethane out of our storage. That's a function of, like you said, a lot of ethane rejection. And crackers are running fairly strong right now.

So, you're going to go through a period of time that you say, wow, this is getting better. You're going to turn it back on and it's going to get worse. That's what I mean by anemic and volatile.

Okay.

You're going to have to see new demand. But demand is, in fact, being created.

The other thing that I think ultimately helps ethane to some extent is you've had propane competing with ethane in the crackers, because of its -- because of the warm winter we had last year, primarily. You're having a little stronger winter this year. But when that export terminal comes up, we're going to be exporting quite a lot more propane. So I think it will have the tendency to pull propane out of that competition with ethane in the crackers.

So that leads me to my follow-up question. And you touched on this earlier. When you think about propane supply/demand over the next couple of years, do you think that the capacity of your LPG export dock expansion and one of your competitors is going to be enough to balance the market when those expansions are fully online?

Well, if it's not, then we'll add to ours.

Okay, okay. I appreciate the color, Jim. Thank you.

Brian Zarahn, Barclays.

The question on a business you don't talk about too much usually during the call. The Refined Products Pipeline business had significantly higher results with lower volumes. Can you talk a little more about this? Is it more of a one-time event with marketing and some one-time lower expenses? Are you seeing some improvement within the business?

Let me take that and then kick it to Tom Zulim. I think this is a good example of how Enterprise will take pipeline systems and say what can we do, what more with them. And, Tom, you might want to explain that.

Yes, what Jim is referring to there is where we see opportunities to put the pipelines in what haven't been the traditional service south to north. We may see opportunities along the Gulf Coast to move them East-West, West-East, and then capturing opportunities where we can of going where the markets demand from north to south. Combining that with good focus on operational costs, and what we spend on those pipes has improved our results. And I expect our opportunistic focus to continue to take advantage of it. So I think we'll continue to see the similar results.

But specifically what we did is, one of the pipelines on the Gulf Coast that normally flowed west to east, we made it bi-directional --

Correct.

-- between Beaumont and the ship channel, and it's been quite busy.

Correct.

Okay. Do you see any additional opportunities, larger scale opportunities to reverse flow in certain lines in that business?

Yes, I think we're constantly looking at those opportunities. Nothing that we've announced yet, certainly, but we certainly see developing opportunities for redeploying existing assets to get better use out of them.

Okay. And a quick question for me on offshore. Seems like we bottomed in 2012. What order of magnitude do you expect improvement going forward in offshore crude? And then I guess, to a lesser degree, gas?

This is Bill Ordemann. I guess we see incremental improvement over the next year or two. We've got some other projects coming on that we see from third parties that will bring additional volumes into our systems. And then we have a major project that will come on in 2015, I believe, the Lucius project, that we're actually laying the pipe on right now, that will be a little more than incremental to our bottom line. And then we're working with producers on several other projects that will come on in that 2016/2017 timeframe.

This is Jim again. I think in about three or four years, we're going to be delighted we got that offshore system.

Okay, thanks for the color.

Brad Olsen, Tudor, Pickering, Holt.

First question is about ATEX. You discussed on the call how you've done a lot in the way of repurposing old assets. When you look at the amount of fractionation capacity getting built in the Marcellus, and the fact that we're seeing new fractionators announced, it seems like every week, in the Utica, is there an opportunity to repurpose another portion of the TE Products line for heavier NGL service going forward?

Tom, you want me to just start?

Yes, go ahead.

We're taking a hard look at all of those pipelines that go up to the northeast. I'm not going to say exactly what we're looking at doing, but we do have a 50/50 pipeline with a company called Marathon, and a pipeline called -- what the hell is the name --?

Centennial.

Centennial, that -- it's not doing a heck of a lot, and it doesn't take a long lateral to lay over to it. So anything is possible. We're going to play that just like we did the ethane out of the Marcellus. Close to the best and deal with producers.

Great, thanks. And my follow-up is related to Seaway. There was an operational issue a couple of weeks ago that I guess led to some operational limitations on the line. And I was -- as you think about developing the ECHO system, is ECHO going to be something that effectively alleviates those limitations?

And I think as a kind of -- another tangent, as you think about your business and how it might benefit from a situation like that, if refiners are having trouble taking away all the throughput from Seaway, is there a role where your barge fleet could actually help move some of that crude to other destinations along the Gulf Coast?

This is Bill Ordemann again. I think when we get the lateral from Jones Creek to ECHO finished for Seaway -- which I believe will be sometime in the third, early fourth quarter this year -- I think we will have the ability to alleviate most of the bottlenecks we're seeing right now. Seaway, as we look at it today, is operating as per design on injections out of Cushing, and the ability of the pipeline to move crude oil down to Jones Creek.

We are seeing some day-to-day fluctuations that we will intend on seeing that will affect the monthly averages that some people are quoting, based on the nominations by the shippers of crude out of Cushing, and based on the availability of third parties to take that crude out of Jones Creak. Again, when we finish the lateral over to ECHO, we expect a lot of that to -- or all of it, essentially, to be alleviated. Then we'll finish the lateral over to Port Arthur in early 2014. So, all that being said, we think it's heading in the right direction.

As far as the barge fleet, we are looking at a project right now that would give Seaway access to the water and give access to potentially barges or potentially even ships. But that's probably something that is going to be later this year before we shake out.

Great. Thank you.

And, in fact, we're already using our barge fleet to some extent. And we're loading crude oil barges at our Morgan's Point terminal.

Great. Thanks, guys.

Curt Launer, Deutsche Bank.

Just a couple of unrelated questions relative to, first, ATEX. There's been some discussion of it becoming a Y-grade line as opposed to an ethane-only line. And would love to hear your perspective on that, given the magnitude of ethane rejection going on and all the other things that are happening within the Marcellus. And then I'll just have a quick follow-up after that.

ATEX is an ethane line, but we're open to talking to producers to meet their needs.

And would you see it as any major change in economics if it would be Y-grade or ethane? I mean, I'm certainly remembering the discussion relative to the rates for moving the ethane as being a factor there.

Curt, I don't think we'd change the service to Y-grade for a lower return.

That's kind of what I was thinking. Anyway, okay, let's switch gears and talk about -- I just want to make sure I heard you right, Mike. I think in your opening comments, you talked about $2.4 billion of organic capital expenditures in 2013 as being completed. And then Randy mentioned $4 billion of organic capital expenditures this year. Can you talk about the reconciliation of that in terms of just what goes into service this year? What's hanging out for next year and things like that? There's lots of different names on my pad right now.

Sure. We had $2.9 billion a project that started service last year. We've got about $2.4 billion that will begin service this year. What Randy was talking about was cash out the door on new growth projects being roughly $4 billion. So that is finishing up some of the projects that are going into service this year, and it's going into other projects that will go into service in 2014 and '15.

Okay, thank you.

Noah Lerner, Hartz Capital.

First off, happy and healthy -- belated happy and healthy New Year to everybody. Sorry, I was interrupted, so if it's been asked, I'll just read the transcript. But I was wondering if you could put some color on the gas volumes out from the Gulf have fallen off, and Independence Hub is not getting the demand payments any more. And I'm just curious if you can give some kind of color what kind of activity from the drillers are going on within reach of those assets currently? Or what you might know or think about their future drilling plans around those assets?

Yes. No, let me start and then I'll hand it off to Bill. In my comments, I did give you kind of an indication of what the activity is in the Gulf of Mexico in terms of rigs that are in place, and what's expected to be there by the end of the year. Currently, we've got more rigs in the Gulf of Mexico than there were before the Macondo incident. So, we feel pretty good about that. But, clearly, development of these fields takes time and so there is a lag time.

Yes. And, no, we're really focused on the Gulf as being an oil province at this point in time. There are some gas opportunities out there that we're chasing. But primarily, the exploration of the Gulf of Mexico today is looking at oil, so my expectation is we'll continue to see gas volumes declining in the Gulf for a while, anyway, and then eventually, they'll come back the other way.

But crude oil, I think, is what we see as being the big player in the Gulf of Mexico and all these rigs are targeting today. And certainly, our crude pipeline group or our offshore group is focused on the crude oil aspect of it primarily, and the gas aspect of it secondarily.

Okay. As a quick follow-up, is there any way then to repurpose some of those assets that have been primarily looking at natural gas at some point for crude use? Or is it just basically going to be a decaying asset until the entire gas market comes back some day out in the future?

I think, to be realistic, there's probably limited opportunities to repurpose the floaters, anyway, that we've got for gas, like Independence for crude. But the other assets we're looking at some of our existing platforms and infrastructure we've got in the Gulf of Mexico we're certainly looking at as landing points for new crude oil pipelines.

Great. Thanks a lot.

Michael Blum, Wells Fargo.

Jim, just wanted to go back to ethane for one minute again and apologize for that. So historically, when you had ethane drop below its gas value, you'd have ethane rejection, the market would quickly correct itself. Now that dynamic has changed, obviously. And I just wanted to get your perspective on what's changed and why ethane is trading sustainably below that level? And how much ethane rejection you think actually is in the market right now?

I think our first questioner, when he said something like 175,000 barrels a day, wasn't too far off the mark. I think we're thinking 150,000 to 175,000 barrels a day, Michael.

Okay.

I think we're going to live with this for a couple, three years. And -- but I do think that it's getting a lot of attention from the demand side of the equation. I mean, I said in my comments that -- I mean, you guys can read it. Every cracker out there is focused on using more ethane. That takes time. But that time will come.

The other thing that I didn't say is we even have companies coming in here wanting to underwrite engineering studies on the possibility of exporting ethane. Might be a stretch, but its advantage is not going unnoticed and it will be exploited.

And Michael, I think one other thing to note -- when you dial back to 2003, ethylene produced with US ethane was one of the most expensive sources of ethylene in the world. Where now, ethylene produced from US ethylene is one of the cheapest sources in the world. So, again, I think you may have, like Jim talking about more market reaction to take advantage of that.

Okay. And then (multiple speakers) --

Between '13 and '17, if you look at some of the current announcements, I mean, you're north of 600,000 barrels a day of additional ethane demand, just with those current announcements.

Okay, that's helpful. And then I guess on a related topic, do you have any update on the ethane header project that you've talked about in the past, and how that may or may not play into the current market landscape for ethane?

Tom, you want to take that?

Yes, we're still actively working that project and talking to potential customers for it. I think that's going to enhance the demand side of the ethane, because it will make it that much more available to the users of it.

I can say something nobody else can say, because I'm a retiree of a chemical company, and those guys go slow and they're methodical. I think we have two contracts that are done and we're working two others, that if we get all four, we'll build.

Correct.

Great. Thank you very much, guys.

(Operator Instructions). John Edwards, Credit Suisse.

Just a follow-up on Curt's question. You mentioned you expect $2.4 billion of organic growth projects to be completed in 2013. About what's the number for 2014 and '15?

John, we haven't broken the number down between the two, but it struck me was, what, $4.8 billion for the 18 months starting 2014 and through the first six months of 2015.

Okay, that's helpful. And then the natural -- on the switching over to the Natural Gas Pipeline segment, within that, the Pipeline and Services, that was up quite dramatically year-over-year. And I'm just wondering, is that reasonable to think about as a run rate going forward for that piece of that segment? It was around a 220 million or so. I think last year, it was like 170 million.

Yes. This is Jim Cisarik. One of the things that you've seen is the Haynesville extension came on November of '11. Obviously, we had a full year there. And in Texas, especially, we're benefiting from the Eagle Ford and some of the other expansions on the producer side on our assets. So, when you look at that the last couple of years, we've had exponential growth on our intrastates.

And so, with us having so much scale now, I can see that run rate continuing somewhat. Obviously, in Texas, we've doubled the gross operating margin since 2010. In Louisiana, we've probably 11 times the operating margin since 2010. Obviously, it's not going to grow that much, but we have enough scale now to continue that growth to reach certain areas.

And obviously, you've got -- what I haven't seen in probably 12 or 13 years is we've been living on the producer push, per se. Now, like Jim and Mike had mentioned, you have that low natural gas price that's creating significant demand on our assets. So, what's going to happen now, we're having the producer push combine with that new end-user demand, which we're going to be targeting as well.

And John, you've seen a lot of LNG announcements, so depending on what happens in Texas and Louisiana on LNG exports, that might create some additional demand for our pipes.

Okay. And I was thinking specifically on the NGL pipes and storage. I'm just thinking in terms of sort of a margin run rate there. Since it was a pretty significant step-up from the last quarter, is that reasonable to think about this higher run rate?

I'm sorry, John, I thought you said natural gas.

I'm sorry. I was thinking that -- I was talking natural gas liquids. I'm sorry.

Okay. If you're looking at segment performance, remember that there's a whole lot of stuff in the NGL segment, including marketing and storage processing, fractionation.

Right, I mean the pipelines and storage sub-piece that you break out.

Yes, John, on that, I mean, if you think about the first train to Yoakum came on in May of last year; the second train at Yoakum came on in July of last year. So when you start doing your year-over-year comparisons, you'll still pick up NGL growth, both in the pipes and also in the fracs, downstream of that. And then, as Jim mentioned, the third train at Yoakum should go into commercial operations probably beginning of March. So you should continue to see some quarter-over-quarter growth coming from those.

And then, John, remember, we've got the Texas Express and the Front Range projects that will be coming online and adding additional volumes.

Right.

So I think the answer to your question is yes.

Yes (laughter). Okay, great. And then you -- in terms of capital spend, I mean, you've been going about a $4 billion rate here. Are you continuing to see your backlog increase? Or is it holding steady? I mean, is it working off at all with this kind of stepped-up investment?

John, with the creative people we have, I'm not sure we'll ever work it all off. What we try to do is to do those projects that make the most sense for the partnership. As we've said in some places in the past, there's certain of these projects that if we don't do them now, somebody else will or we won't have that opportunity.

So, a lot of what you're seeing now is for us positioning ourselves for the future. We don't need to spend $4 billion a year on growth capital in order to grow our distribution, but it does really position ourselves for some pretty interesting projects going forward.

Okay, great. Thank you very much.

Michael Blum, Wells Fargo.

Yes, just one quick follow-up. Just what is Seaway flowing at right now in terms of volume?

It varies day-to-day, Michael. Again, depending on the noms from the shippers, the availability downstream. We've had it flowing as high as 380,000 barrels a day physically. I don't know what it's flowing at the moment.

Okay, great. Thank you.

Yves Siegel, Neuberger Berman.

Good morning, this is Yves. Quick question for you -- or maybe not so quick. Could you describe the business environment, if it's changed much in terms of what you're seeing on contractual commitments from your customers? And by that, I mean the willingness to -- on the processing side, the willingness to do fee-based or the desire to do fee-based contracts. And then when you think about the pipeline side, how much of that are they willing to do on a demand charge basis or guarantee volumes?

And then, thirdly, Mike, based on your last comments as it relates to doing projects now, that if you didn't do it, others would perhaps come in, does that mean that you're accepting perhaps lower returns today, because strategically, it just positions you very well for the future?

Why don't I take that one first, Yves, and then we'll come back to your first question. We're not going to take returns that don't make sense just to do a deal. But you have projects like moving ethane out of the Marcellus, for example.

If you look back a couple of years ago, there were probably five different projects trying to do that. We were able to do it with some existing pipeline assets that we have that were underutilized. And so, for us, it was a great project for us, allowed us to improve the returns on existing assets, and to serve the needs of the producers up in the Appalachian Basin, and really provide a low-cost solution for them while providing great returns for us. So it was kind of a win-win.

The things that we're doing in the Eagle Ford really are capitalizing on assets that we already had before the Eagle Ford hit the headlines. And we are building big trunk-line projects through there, a lot of processing capacity. From there, we can easily extend into other areas for less cost. And so, while we have good returns on the assets that we have now, we think that will lead to really good projects going forward as well.

But the answer is, we're not going to pay up, either in the acquisition or in a new project, just for the sake of getting a deal done. Now some of the projects that we do, we will have a return on our economics, based on the contracted volumes, that are going to be lower than what you would normally expect from us -- I mean, the kind of low-double digits. But that's only because we've got additional capacity that we feel confident that we'll be able to contract for and get those ultimate returns up.

So I don't know if that answers any questions?

No, it does. But you're also creating a lot of value just because your cost of capital is so cheap. So, even if you went down to below double-digits, you'd still be creating shareholder value by doing those projects.

Yes, we don't like to give away our cost of capital, Yves. And so you're right, from a purely competitive standpoint, if we wanted to achieve the same rate of return as our competition, we could charge lower rates. But the way we prefer to look at it is that we get these projects on kind of the same terms that the competition would have gotten, and we drive the results to our unitholders and the returns that they get.

A good example, Yves, of what Mike's talking about is our PDH plant. We had -- Jerry, two customers? We had two customers for that PDH plant when we pulled the trigger and announced we were going to build it. It wasn't the kind of a return that we would typically want, but we knew or felt comfortable we could get others. As it's turned out, it sold out and it's a pretty darn good return. It's -- that's pretty much a classic example.

Okay. And then could you also just speak to the earlier part of the question, which is, are you seeing any change in this business environment?

Yes, I forgot the earlier part of the question, Yves.

(laughter) It really relates to -- the way I think about it is the sharing of risk. Are the customers willing to -- or do they have a desire to do fee-based contracts? Or would they prefer to do -- on the processing side, are they more willing or more wanting to do keep-whole? Has that changed at all going forward? And what's the ability of you to get demand charges on the pipeline, as opposed to protect yourself on the volumetric risk, as you look to some of these projects going forward?

Yves, I think -- this is Bill. As far as your first question goes on the processing side, we haven't seen any change in the producers from wanting the fee-based contracts, wanting their liquids. They still want their liquids and they've still got good margins on the heavies. And from what I've seen, really haven't seen anything change in that direction going back toward keep-whole or anything of that sort.

So we're still going down the road of mainly fee-based contracts on our processing. On our pipelines, we still see people willing to step up and pay demand charges. I think they may be a little more cautious about the volumes they'll accept for demands today, and keep an eye on that basis, the ethane margins. But other than that, both the pipelines and the fractionations, all the contracts we're doing right now primarily have those demand charges embedded in them.

Yves, this is Tony. You know we always publish what we think a typical processing upgrade is. And it's in all our material. And what you see is that the heavier part of the barrel is very profitable, and Jim talked about that in his comments. So, producers are very much incented to drill.

Got it. And my very last question, you may or may not be happy to answer it, but when you think about the pipeline projects that you have underway, how much do you think you'd like to keep of the capacity for your own account?

I believe that depends in large part on what we can sell.

Well, and it depends in large part on what is the pipeline. If you look at Texas Express, we don't want any of it other than -- well, I guess we did take a little bit of it, as it relates to our MAPL assets. So we took a little bit of that, but we tied it back to what we had on Mid-America that we needed on Texas Express. If you look at Seaway, we took some capacity out on Seaway and we're extremely grateful for that capacity today. So, it depends on the type.

Okay, thanks a lot, gentlemen.

I will now turn the call back over to Randy for any closing remarks.

Regina, we have no closing remarks. And if you would, go ahead and pass along the replay information for our listeners.

Thank you for joining today's conference call. This call will be available for replay beginning today at one o'clock p.m. Eastern Standard Time, and will run through midnight Eastern Time on Thursday, February 7, 2013. The number to dial to access the replay is 855-859-2056. And for international callers, 404-537-3406. The conference ID number for the replay is 88439459.

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