Energy Transfer LP (ET) 2009 Q4 法說會逐字稿

Good day ladies and gentlemen, and welcome to the fourth quarter and fiscal 2009 Southern Union Company earnings unit conference call. At this time, all participants are in a listen-only mode. We will be facilitating a question and answer session towards the end of the conference. (Operator Instructions). As a reminder, today's conference is being recorded. I would now like to turn the presentation over to Mr. Jack Walsh, Vice President of Investor Relations.

Thank you Marisol and welcome to Southern Union's fourth-quarter and fiscal 2009 earnings call webcast. Presenting on today's call will be George Lindemann, Chairman and CEO, Eric Herschmann, Vice Chairman, President and COO, Rick Marshall, Senior Vice President and Chief Financial Officer, Rob Bond, Senior Vice President of Pipeline Operations and Roger Farrell, Senior Vice President of Midstream Operations.

A replay of this call will be available for one week by dialing 888-286-8010 and entering passcode 87563407. A replay of the webcast will be assessable for our website at www.SUG.com.

Today we will be discussing our fourth-quarter and fiscal 2009 results, our 2010 guidance, significant events and outlook. This morning we issued a press release announcing our results and our 2010 financial outlook, both of which are available on our website. Following our prepared remarks today we will be happy to address your questions. If you have any further questions after the call, please contact me directly at 212-659-3208.

Before beginning, I would like to remind everyone that the information discussed on today's call pertains to the financial results of Southern Union Company. Certain amounts and variance explanations for the transportation and storage segment may differ compared to Panhandle Eastern Pipe Line Company's stand-alone financial statements due to consolidating adjustments.

I would also like to caution you that many of the statements contained in our call may be based on management's current expectations, estimates and projections about the industry in which the company operates. These statements are not guarantees of future performance and involve risks. The company undertakes no obligation to update publicly any forward-looking statements as a result of new information, future events or otherwise. Such statements are intended to be covered by the Safe Harbor provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. I would also refer you to the cautionary statement regarding forward-looking information in our earnings release.

I would now like to turn the call over to George Lindemann. George?

Good morning. I'm pleased to report adjusted fiscal 2009 earnings of $226 million or $1.82 per share. These amounts include certain adjustments as were identified in our press release. This past year was a difficult one for our national economy and for business in general. I'm quite pleased with the performance of our company during such a turbulent time.

The stable nature of our underlying business segments has allowed us to produce strong and consistent results. We're pleased to announce our 2010 adjusted earnings guidance in the range of $1.75 to $1.95 per share and adjusted EBITDA guidance in the range of $870 million to $930 million.

I would now like to turn the call over to Eric Herschmann to comment on some of the key initiatives for the upcoming year. Eric?

Thank you George. First, I would like to take a minute to update you on the status of our Trunkline LNG infrastructure enhancement projects, IEP.

As you may know, IEP is an approximately $430 million project that is expected to generate approximately $67 million to $72 million in EBITDA. The project has two main components -- the installation of eight ambient air vaporization units, or AVUs, and the construction of a natural gas liquid extraction facility.

We're pleased to say that the construction and commissioning of natural gas liquid extraction facility (inaudible) (technical difficulty) demonstrated the operating capability of (technical difficulty). We're completing the final modifications to the air vaporization units. The AVUs allow the facility to regasify LNG by using the ambient air temperature in Lake Charles. The AVUs are designed to maximize fuel savings at temperatures over 70 degrees.

In consultation with our customer, BG LNG Services, we've taken advantage of the recent cold weather to make further modifications to the AVU's heat exchangers. Crews have been working diligently to complete these modifications.

Concurrent with this work, we've been performing code-required pressure [tests] and related work on the completed units as well as modifying the release valve system. We expect to complete commissioning within the next few weeks and place the IEP facilities in service so that we will be positioned to receive cargoes by the end of this month.

Although the in-service date is later than originally expected, this delay allowed us to assert vendor warranty claims and effect the modifications without an interruption in service. We believe the modifications will result in a more reliable facility for our customer for decades to come. Our guidance for 2010 has already factored in this delay.

Next, I would like to discuss the recent ruling in our Missouri Gas Energy rate case. The Missouri Public Service Commission recently issued an order approving a $16.2 million increase in annual base rates with a return on equity of 10%.

Also of importance is the Commission's approval of a distribution rate structure for residential and small general service customer classes which eliminates the impact of weather and conservation on revenue. The residential and small general service customers comprise 99% of MGE's customers and 96% of its operating revenue. This improved rate structure will further enhance the stability of our earnings cash flows. The new rates became effective on February 28.

With that, I would now like to turn the call over to Rick Marshall, our CFO, to give an overview of our results and 2010 guidance. Rick?

Thank you Eric and good morning. Before I begin I would like to point out that our discussions today will focus on adjusted net earnings, adjusted EBIT and adjusted EBITDA -- all non-GAAP measures. In accordance with Regulation G, our press release and 2010 financial outlook issued this morning contained reconciliations of those non-GAAP measures.

For fiscal 2009, adjusted net earnings were $226 million or $1.82 per share. This compares to adjusted net earnings of $223 million or $1.81 per share in 2008.

For the fiscal year ended December 31, 2009 Southern Union had adjusted EBIT of $536 million compared with adjusted EBIT of $548 million in the prior year. The decrease was primarily due to decreases in the gathering and processing and distribution segments, offset partially by increases in the company's transportation and storage and corporate and other segments.

Adjusted net earnings, EPS and EBIT include adjustments for several items including the mark-to-market accounting treatment on our hedging portfolio, changes to the provision for hurricane related repair and abandonment cost, environmental insurance settlements and the reversal of a provision for a past take or pay settlement obligation. As mentioned earlier, the adjustments are identified in our earnings release and financial outlook issued this morning.

In terms of segment results for fiscal 2009, transportation and storage including our investment in Citrus had adjusted EBITDA of $414 million for the year compared with EBIT of $405 million in the prior year. The increase of $9 million was largely attributable to higher operating revenue at Panhandle Energy in 2009 compared to 2008, offset partially by higher operating expense and depreciation.

Our gathering and processing segment generated $64 million in adjusted EBIT for the year compared with $86 million in the prior year. The decrease was largely driven by lower realized natural gas and natural gas liquids prices, and lower process volumes as a result of the fire at our Keystone processing plant in July 2009, offset partially by reduction in operating expenses as a result of ongoing cost cutting measures being applied throughout the company.

Our distribution business generated EBIT of $59 million for the year compared with EBIT of $61 million in the prior year. The decrease was primarily due to higher operating expenses.

Our corporate and other operations generated a loss before interest and taxes of $1 million in 2009 compared with a loss of $4 million in the prior year. The year-over-year improvement was primarily due to higher litigation related legal expenses in the prior year.

During the year we invested approximately $394 million into our operations. Growth capital accounted for $179 million, while maintenance capital was $214 million.

From a segment standpoint, our transportation and storage segment invested $247 million; $108 million for growth and $139 million for maintenance. Our gathering and processing segment invested $70 million; $36 million for growth and $34 million and maintenance. Our distribution segment invested $46 million; $6 million for growth and $40 million for maintenance. Finally, our corporate and other segment invested $30 million; $29 million for growth and $1 million for maintenance.

This past Friday, we successfully closed on the renewal of our revolving credit facility which was scheduled to mature in May. Given a high level of demand in the market, we were able to increase the size of the facility to $550 million from its previous $400 million. The new facility has a term of three years and provides us with ample liquidity to cover operating and capital requirements for the next few years.

As mentioned earlier, we posted our 2010 financial outlook presentation to our website this morning. I would like to take a few moments to walk through some of the highlights. We expect adjusted earnings for 2010 to be in the range of $1.75 to $1.95 per share. We expect reported or GAAP earnings for 2010 to be in a range of $1.92 to $2.12 per share.

Adjusted earnings for 2010 reflect the impact of mark-to-market accounting treatment on our economic hedges. We expect consolidated adjusted EBITDA for 2010 to be in the range of $870 million to $930 million. This amount includes our 50% interest in the EBITDA of Citrus Corp.

From a net capital expenditures standpoint, we expect to spend a total of $275 million to $330 million in 2010. Of this, approximately $205 million to $235 million is for maintenance and $70 million to $95 million is for growth, with approximately $15 million dedicated to the LNG infrastructure enhancement project.

Our gathering and processing segment is forecasting growth capital of $50 million to $65 million. This amount contemplates the restart of the Mi Vida treating facility in the first quarter and the Halley gas processing facility in the fourth quarter. These facilities are being placed in service to accommodate additional volumes expected to come online throughout 2010 and into 2011.

At Citrus Corp. total maintenance capital is expected to be in a range of $200 million to $220 million, while total growth capital is expected to be in the range of approximately $1.4 billion. The majority of the growth capital at Citrus is related to the Phase VIII expansion.

I will now turn the call over to Rob Bond, who will discuss our transportation and storage segment.

Thank you Rick and good morning. Our transportation and storage businesses performed well during 2009, posting strong results due to the hard work and determination of our dedicated employees.

As Eric mentioned earlier, we're in the final stages of construction and commissioning on the infrastructure enhancement project at Trunkline LNG, and are optimistic that we're only weeks away from placing it in service. To remind everyone, the project is fully subscribed by our customer, BG LNG Services, for 20 years. Once in service, the other contracts we have with BG will run concurrently with IEP for 20 years.

Our other major capital initiative is the Florida Gas Transmission Phase VIII project. We have a 50% equity interest in and service the operator of Florida Gas Transmission through our investment in Citrus Corp. The Phase VIII project is designed to add approximately 820 million cubic ft. per day of incremental delivery capacity into Florida through the addition of 500 miles of pipe and over 2000 hp of compression.

In the fourth quarter of 2009 we received our first certificate authorizing us to move forward with the project. We remain on target for an in-service date during the spring of 2011.

We continue to have 74% of the expansion capacity contracted under 25-year agreements. One shipper has an election to increase its capacity to a level which would take us to 83% contracted. We estimate the project will cost approximately $2.4 billion and generate operating income of $240 million to $260 million and EBITDA of $290 million to $310 million when fully contracted.

With that, I would like to turn the call over to Roger.

Thank you Rob and good morning everyone. For 2009 we averaged approximately 47,000 mmbtu per day of total equity volumes. Of that amount, approximately 37,000 mmbtu per day was comprised of high-value NGL volumes and approximately 10,000 a day was natural gas. These averages reflect the impact of the fire we experienced at our Keystone processing plant in July 2009. During the fourth quarter, process volumes increased to pre-fire levels until late November when field production was negatively impacted by production freeze offs in our service area.

For the year, we reduced operating expenses by $2.8 million year-over-year. We remain optimistic that we will be able to grow throughput in equity volumes during 2010. Although cold weather has slowed producer well completion activity and hampered production, we are beginning to see significant horizontal [all-directed] drilling activity occurring in close proximity to our system and have secured dedications from a number of producers.

Gas production for recent well completions contains high levels of both carbon dioxide and natural gas liquids. Although we recently expanded the treating capability at our (inaudible) facility, we have determined that it will be necessary to restart both our Mi Vida treater and Halley processing plant to accommodate these new volumes. As Rick mentioned, the majority of our growth capital expenditures shown in the 2010 financial outlook pertain to restarting Mi Vida and Halley and for reduced supply connections.

The Mi Vida and Halley facilities will allow us to treat and process at least 60 million cubic ft. per day of this new NGL rich high carbon dioxide production. We expect Mi Vida to start this month with Halley in the fourth quarter.

As of today, we've locked in a substantial proportion of our 2010 and 2011 equity value through our hedged portfolio. For 2010 we're hedged on 40,000 mmbtu per day of equity NGL through a combination of processing spread and natural gas swaps at an average realized price of $10.44 per million BTU. We're also hedged on additional 5000 mmbtu per day of natural gas at $5.33.

We expect NGL equity volumes for 2010 to range from 40,000 to 45,000 mmbtu per day. We also expect natural gas equity volumes for 2010 to range from 7000 to 15,000 mmbtu per day. Actual equity volumes will obviously be influenced by the drilling activities of our producers. We'll continue to update you quarterly as better information becomes available.

For 2011 we have 25,000 mmbtu per day of NGL hedged at $11.63. We continue to actively monitor the forward markets and we'll look to add additional hedges to our portfolio as opportunities arise. I would now like to turn the call back over to George.

Thank you Roger. At this point, I would like to open the meeting up to any questions that anyone might have.

(Operator Instructions) Craig Shere, Tuohy Brothers Investment Research.

Thanks for the call. Couple of quick questions, distribution guidance, looks like the rate case is proportional for the time of the year and might be another (technical difficulty) [what, 13] million or so, but guidance is flat to up $10 million. Can you talk about maybe some of the headwinds there?

In gathering and processing, it looks like versus the guidance for equity volumes from last year's guidance call that the NGL volumes are flat but net gas equity volumes are up. Can you talk about production trends in the basin and the impact on NGL and gas equity volumes? And then one quick follow-up on midstream.

This is Rick Marshall. I'll take the distribution guidance. Even though we do have the rate increase that is factored in for this year and you have to remember the rates became effective in February 28, last year's guidance included a level of capacity release sales that did not materialize in the year and were not factored into this year's guidance. And that level was in the range of $7 million or so. So, outside of the capacity release issue, guidance is up.

But as you're probably aware, part of this rate case is necessary to recover and increasing costs in the business. Those costs are pension, labor benefits type of expenses that did materialize or will materialize in 2010. Those are factored in guidance as well. As far as the gathering and processing, I'm going to let Roger speak to that.

Sure. The gathering and processing in terms of the NGL equity volumes, we were -- we are shown flat year-to-year. We are certainly hoping we'll do better, but one of the things -- the new production hasn't come online as rapidly as we had expected late in the year. So, just with all of the contract renewals and normal decline rates that we see staying flat is kind of what we're seeing now. Although if drilling does pick up a little bit more quickly we can see some growth in that as well.

The increase in the natural gas equity, what we've seen is we've done a very good job at managing our fuel usage and our system losses. And that relates -- comes back directly to us in the form of natural gas equity volumes.

Any prospects there in your mind for improvement going into next year?

Prospects for either one of them?

Yes, for production in the basin.

Yes. One of the things I alluded to in my prepared comments was the fact that we have made a decision to restart our Mi Vida treater. And actually that -- it did come up over the weekend. It is a facility that will be able to handle up to over 100 million cubic ft. a day of this high carbon dioxide laden gas. And by the end of the year we expect to have our Halley processing facility restarted at initial capacity of 60 million a day, expandable to over 100 million a day as well.

Based upon what we are seeing in producer drilling activity in our area, we do expect to see drilling volumes throughout 2010. And if the plays prove up the way that we believe they might, that volume growth will continue on into 2011 and possibly beyond. We're certainly not giving any guidance for 2011. But our expectation is to see volume and equity volume growth as well.

Great. Do you all feel that midstream is a strategic fit for the company or [worth] increasing interest in the market place for midstream assets could there be an opportunity to de-risk the overall portfolio by monetizing that?

I think it is something we're carefully monitoring and obviously we would need to be a strategic play for us. It's very close to our current footprint. That's about as far as we can go currently.

I got you. Last question is around Citrus and [MGT]. Was there a rate case we should be thinking about there? And does the FP&L rate case disappointment affect your expectation of natural gas fired demand, bringing that expansion up to 100% contracted eventually?

There was a rate -- let's take both of those questions. First question about the rate case, yes, there was a rate case that was filed October 1, 2009 which was -- as a result of the previous rate case settlement, we were obligated to file by October 1, 2009. Of course we did. We did file for a significant increase but it will take a while before that whole rate case is adjudicated and goes through the process. Rates have been suspended until April 1 at which point in time they'll become effective subject to refund.

But that is not in guidance?

That is -- I think there are some dollars that are baked in based on our expectations and in our guidance.

Yes, there are dollars that are in guidance.

Okay. (multiple speakers) rate case fully contracting the expansion there?

I'm sorry. Say that last comment again.

The growth CapEx at Citrus, the expectation that gas fired generation will still be able to soak up all the supply there?

Yes, we still do believe that will be the case. In fact what we've seen is, as you mentioned, in light of the difficulties that some of the utilities have had in the state what you have seen is the announcements that a delay in future nuclear facilities and certainly any coal plants that were originally planned, so we do believe natural gas is going to be the fuel of choice for the next round of generation in the state of Florida.

Carl Kirst, BMO Capital Markets.

Actually if I could just follow up on that last question, Rob, just to -- when you say natural gas, for the long-term certainly how would you characterize any discussions, if there are any discussions right now as far as the incremental capacity for Phase VIII? Is there anything currently ongoing or is that something we should be more expecting to see perhaps heat up once the expansion comes into service?

I think there is obviously continued dialogue with all of our customers us to what their future expectations are for generation, whether they're new facilities or whether they're incremental generation facilities added to existing plants, etc. So, I think we are on top of what the expectations are for our customer.

Clearly timing is still something that our customers are assessing, trying to figure out exactly what their power growth looks like in the state. And I don't think it's -- I think it's probably premature to speculate. But we are certainly on top of it and expect all of our major customers to eventually need some incremental power generation, and of course we believe that will be served by natural gas.

Another question if I could, and Eric I'm sorry if I have to ask you to repeat yourself a little bit. There was some crazy music going on while you were talking. But, can you go over again on the IEP? Whoever wants to take it, the -- what happened between sort of late November with the first expectation and today? And almost perhaps more important, there maybe were some concerns that whatever challenges were in that infrastructure project could perhaps be read over to execution on Phase VIII. And I just want to get your thoughts on that.

I'm not certain about the connection to Phase VIII. I did hear the music so let me read a portion of that again.

We have the systems broken down between the AVUs and the natural gas liquids extraction facility. The natural gas liquids extraction facility we have completed. We're completing the final modifications to the AVUs.

The AVUs are what allows us to regasify the LNG by using the ambient air temperature and we have that in Lake Charles. They perform best when the temperatures exceed 70 degrees. We've been working with BG LNG Services to take advantage of what has been amazingly cold weather recently to make further modifications to the AVU's heat exchangers.

While we are doing this, we're also performing our code required pressure tests and related work on completing the units. Our expectation is that we will finish everything and put the IEP facilities in service by the end of this month and be prepared to receive (inaudible) at the end of the month. So, I don't think there are any hurdles we see in the technology or the facilities going into service and do expect to have (inaudible) shortly.

As far as Phase VIII I don't think there's any correlation whatsoever. Phase VIII is a completely different project for us in the expansion of our current FGT system. Rob, is there anything else that you think needs to be addressed?

No, I think there were just some issues that we wanted to address with the warranty claims, that being able to delay in the year while it is cold as Eric mentioned, worked out best for both the company and for BG. And that's the reason we went that route.

Just to make sure, so you guys now have warranty claims where you didn't perhaps or you wouldn't have had that recourse back at the end of last year?

Certainly warranty claims have a limited timeframe in which they need to be made and we wanted to make them in the first year of operation, quite frankly. Now is the time of year again while the year is the weather is below 70 degrees to make those modifications.

Faisel Khan, Citigroup.

On the gathering side, you guys talked about bringing back some [late] capacity. Are those treating plants and processing facilities, is that going to be new equipment you're installing there or are you just bringing back mothballed facilities?

This is Roger. These facilities were idle facilities and we're in the process of, on Halley, refurbishing existing equipment and installing new control systems. There is some new equipment particularly compression that will be installed, but generally speaking is a start up of an idle plant.

Mi Vida is essentially the same. It had a run a number of years ago. We went in and refurbished equipment and we had to install some compression in the fuel, to boost the treaters and on to the Halley plant. I guess the short answer is a combination of both.

Of the new volume that you expect to come online, is this under similar contract terms you've had in the past?

Yes, our expectation is that predominately will be a percent of proceeds contract with treating fees, just because of the fact that the CO2 content is frequently over 10%. So it's very heavy with CO2.

Is the gas more liquids-rich than your current volumes coming through your entire system?

I think on average it's very similar. It's roughly 4 gallons per 1000 cubic foot of gas.

And the -- I believe you said that when -- (inaudible) flipping to the pipeline segment for a second. You said that when FGT comes online you expect to generate $248 million to $260 million in EBIT. Is that right?

Correct. When it's fully contracted, correct.

When it's fully contracted, okay. What would it be with the current contracts you have right now?

I don't have that number right in front of me. Clearly we intend to sell all of the capacity beginning in -- early on, as soon as we can, once it is in service. However it may be some of that is done under short-term contracts until it is fully contracted for long-term.

And Rob do you think the FGT rate case, does that kind of impede you from signing a deal right now on the uncontracted part of the expansion?

I don't think so. Again, I think there's going to be incremental generation built in the state of Florida. I think we're going to have the available capacity to sell. My expectation is that we'll meet with our customers and we'll satisfy that need.

How many LNG cargoes did you guys take in, in the fourth quarter?

It was a very low number in the fourth quarter. I don't know if I have that number on my fingertips. We're digging real quick to see if we have it.

While you're digging, last question; do you guys still consider the MLT as a potential way to drop down assets into a structure like that and expand your business using a lower cost to capital?

We continue to monitor. Obviously we've seen Williams restructuring and have been in consultation with our tax and financial advisors, but have not made any final decisions yet.

And I know we did 11 for the year. I don't think we have it broken down by quarter.

Lasan Johong, RBC Capital Markets.

When you get the AVUs in the Trunkline LNG facility and you actually use it, what kind of cost savings do you think you will see on the operating cost side? I'm assuming you'll be able to save some costs on power and gas usage.

Obviously that's the economic benefit that BG sees and that's what they're paying us to do. It varies, so I hate to give you an exact percentage. But at 100% efficient it should use very little, if any, natural gas. So, BG will basically save all the fuel or substantially all of the fuel that they currently pay to vaporize LNG.

And do you not benefit from that savings?

No, that's basically saved them on the commodity side. We earn our return based on a straight, fixed variable rate that we'll put in place once the facility goes into service. (multiple speakers)

It will not be a function of utilization. It will be much like the existing facility in which we earn basically just straight rent for the facility.

I got you, I got you. Do you expect for whatever reason to see an increasing flow after the AVU units are installed?

I think there has been some recent LNG liquefaction facilities that have come online and are expected to come online throughout 2010. So, we'll certainly be ready for them if in fact they do arrive.

Okay, and just quickly, can you give me an overview on what you're seeing in the NGL markets? Is the pricing pressure going up because of global reasons or is there some domestic pull on NGL that is causing some price movement?

NGL prices obviously have increased significantly since this time last year. We have -- we hit some very strong both raw NGL prices plus a strong correlation to crude, probably peaking out in January at -- I think it even went over 70% at times. It has since fallen off quite a bit here in the last couple of weeks.

But we're seeing and expect to see in the forward markets strong NGL prices. Methane has been exceptionally strong and the rest of them have followed. So, if you read and believe the forward-looking view of NGL staying up in the $70 plus per barrel range, that would tend to indicate to us that NGL should stay strong and to stay and retain their preference in the petrochemical and refinery feedstock, so we're quite optimistic on the NGL side.

So you think it's a domestic play more than an international issue that is causing LNG prices to stay healthy.

I think to a large degree, but the world demand for crude I think is certainly highly supportive of strong NGL domestically.

Rebecca Followill, Tudor, Pickering, Holt.

I'm looking for some clarification on the midstream [and extract] these numbers correct. I think you said in 2009 your NGL volumes were 37,000 mmbtus and natural gas was 10,000. How much did the fire negatively impact those volumes?

I actually haven't calculated, but we would have been over 40 on the NGL side had the fire not occurred.

Was it roughly a month, correct, that it was out?

The Keystone fire affected us for four to five months. Certainly when the plant was down, it impacted us a lot. But we had a lot of damaged facilities and compressors and other things that we had to get installed. So, we were -- we struggled for several months. In terms of EBIT, we believe we lost about $5 million because of the impacts of the fire.

And restarting Mi Vida and Halley, Mi Vida is first quarter and Halley is fourth quarter. How big are the two plants on a relative basis to get to the 60 million BTUs per day in incremental volumes? Is there one that is bigger than the other or are they roughly the same size?

Essentially they are operating in sequence. Mi Vida is a treater and it removes the carbon dioxide and you have to do that before you process it at Halley. Today but we will do is we will treat at Mi Vida and send it to our Keystone or (inaudible) plants and use whatever little excess space we have today.

But in terms of volumes, Mi Vida can treat 100 million cubic ft. per day of high CO2 gas. And Halley, the way we're going to initially structure it we'll be able to process 60 million a day, but it is expandable to 110. In terms of relative to what our existing system is, we now can process 400 to 450 million cubic ft. a day. So you can do the math there. It would be at roughly a 15% increase in our -- 15% or better increase in our processing capability.

So you have to expand Mi Vida before you can get Halley back up and running. Is that correct?

Yes.

So Mi Vida is already up. You're just expanding it.

No, we just turned Mi Vida on this last weekend. The gas, we could not take this gas directly to Halley without it being treated at Mi Vida.

So, the bulk of the -- what I'm trying to get at is, with your volumes there's not much of a change despite the fact that you're adding 60 million a day of incremental volumes. But sounds like that's going to be more back-end loaded.

That's correct.

And then on Citrus, how big of a rate increase did you guys file for October 1?

A little over 100 million a day -- $100 million.

But not all of that was incremental. I guess incrementally it would be about $80 million.

$80 million. And you guys can begin booking the new rates subject to refund on April 1. I'm surprised there's only roughly a $5 million increase in your EBITDA guidance for Citrus and relative to your '09 guidance.

You have to remember from our standpoint it's a 50% number. So the 80% is going to be -- we're going to -- obviously don't expect to get 100% of what we ask for. So, using round numbers, if you assume you get 50% of that it turns into 40 from a revenue standpoint. Half of that is 20.

Then it is not in our numbers for a full year since rates go into effect on April 1. That comes down to 15. And then after taxes as it flows to the bottom line to Southern Union's guidance, you can see it's not a huge number.

Okay, thank you.

This concludes our question and answer session for today's conference. I would now like to turn the presentation over to Mr. George Lindemann any for closing remarks.

I just want to thank everyone for attending this meeting and we hope next quarter will be even better and I hope everyone will be here again. Good luck to all and see you next quarter.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect and have a great day.