EnLink Midstream LLC (ENLC) 2003 Q3 法說會逐字稿

Good day, ladies and gentlemen, welcome to the Crosstex Energy LP third quarter 2003 earnings conference call.

My name is Alicia and I will be your operator.

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.

If at any time during the call you require assistance, please press star followed by 0 and an operator will assist you.

As a reminder, this conference is being recorded for replay purposes.

I would now like to introduce your host for today's call, the President and Chief Executive Officer of Crosstex, Mr. Barry Davis.

Please go ahead, sir.

Thank you, Alicia.

Good morning, everyone.

Thank you for joining us today in this conference call to discuss our third quarter 2003 results.

With me today on the call is Bill Davis, our Chief Financial Officer.

After my opening remarks Bill will discuss our financial results for the third quarter in detail.

When Bill is finished I will give an update on important recent developments and finally Bill and I will answer any and all questions you may have.

As always I remind you we are open to any suggestions regarding a format of the call so please let us know if you have any thoughts in that regard.

Our third quarter earnings release, we distributed last evening, for those of that you did not receive a copy of the release, you can call us or download it from our web site at Crosstex Energy.com.

Also for those that wish to listen to a recording of our prepared comments today, we will have a replay available by phone or via webcast on our web site for the next 30 days.

For legal purposes I must remind that you some of the statements made in this call are forward-looking statements, and as such are of course subject to many factors that could cause actual results to differ materially from our expectations reflected in the forward-looking statements.

These factors are described in our SEC documents and we undertake no obligation to publicly update or revise any forward-looking statements.

Now for the highlights of our operations let me begin by saying that we continue to have an outstanding first year as a public company.

As a reminder, we became a public company in December of 2002, just 11 months ago.

Since then we have completed four acquisition transactions in several internal growth projects totaling approximately $110 million.

In addition, we have continued to experience significant growth in our treating division by completing agreements for approximately 25 new treating plants in the last 12 months.

Netting out for the plants removed from service, removed for use in these new agreements we have increased our plants in operation by approximately 50% in the last 12 months.

Further enhancing our position as the largest operator of treating plants in the industry.

Our financial results through the first three-quarters of 2003 have also been excellent.

Through the first nine months we have generated distributable cash flow of $20.9 million dollars, 171% increase over the 2002 period.

This has allowed us to increase distribution by 40% from $2 to $2.80 with three consecutive quarterly increases and still maintain a healthy coverage of 1.3 times for the third quarter on all units.

We successfully completed our follow-on offering in early September using the proceeds of this offering we have reduced our debt to cap percentage to 22%, which gives us financial capacity to continue our growth.

Finally, as a result of these events and a very favorable environment for mlps, our unit price performed very well.

As you know, today we are trading at approximately $40, which is a 100% increase from our IPO price last December.

With that overview, which is intended to communicate to you that things are well here at Crosstex, I would like to turn the call over to Bill Davis to discuss the financial results for the quarter.

Again, once he is finished I will update you on recent activities in more detail.

Bill?

Thanks, Barry.

Welcome to all of you participating in the call.

We continue to be appreciative of your interest in Crosstex.

Before I begin to review the operating results, I will just comment a little more on recently completed equity offering Barry made reference to.

After completing the Duke Energy field services asset acquisitions this summer, our debt to total capital racial had show stood at about 50%, a level about as high as we wanted to see it go.

As you know, we then proceeded to sell 1.725 million newly issued units in September, which brought our total debt level down to 43.2 million as of the end of September, and as Barry said, our debt to total capital ratio at the end of the month or at the end of the quarter is about 22%.

Which leaves us with significant balance sheet room for new growth steps.

The offering priced at 35.97 per unit and since the offer we have been pleased to see the units continue to trade up from that level.

Now I will turn to the quarter's operating results.

As usual, in reviewing the operating results, we will focus first on distribution coverage.

In the third quarter we covered our 70 cent distribution 1.3 times, and in the first nine months we have covered our distribution of 1.75 per unit by 1.4 times.

Distributable cash flow in the third quarter was 8.6 million, and for the first nine months of 2003 it was $20.9 million dollars compared to 3.3 million and 7.7 million in the prior year periods.

Gross margin in the third quarter increased to $17.3 million dollars in 2003 from $8.9 million dollars in the 2002 quarter, an increase of $8.4 million dollars or more than 95%.

For the first nine months gross margin increased to $41.2 million dollars from 24.1 million, an increase of 71%.

Net income for the quarter was $3.9 million dollars or 43 cents per diluted unit compared to $1.5 million dollars last year and for the year-to-date, net income was $9.7 million dollars or $1.20 per diluted unit compared to net income of a million and a half dollars last year.

The units were not outstanding last year so per unit earnings are not applicable to prior year numbers.

The growth in gross margin, distributable cash flow and net income was driven by growth in both the Midstream and treating divisions.

Midstream margin growth of $7.3 million dollars was primarily a function of the June 2003 acquisition of the Duke assets, together with new volumes on the Vanderbilt and Hallmark systems.

Which all together combined, provided a combined margin growth of over $6.4 million dollars.

Same store margins, if I can use that term to refer to assets owned in both 2002 and 2003, increased by about 900,000 for the quarter, through a combination of higher volumes and improved unit margins.

Our margins were not significantly impacted by the negative frac spread environment that we have been experiencing all year and as we pointed out in the past, that's due to the low volume of gas we now have in the processing plants for which we take the processing risk.

During the quarter, about 10% of the gas we bought in to the Gregory system was purchased under a contract in which we took frac spread risk, compared to approximately 44% in 2002.

As a follow up to our comment in the second quarter, you'll note Gulf Coast system volumes declined from the prior year.

This decline is the result of the Vanderbilt system which is now serving two previous customers of the Gulf Coast system.

We used a lateral from the Gulf Coast system as you'll recall to make the connection from the Vanderbilt system to these customers.

Service to these customers was discontinued from the Gulf Coast system in May to allow construction time to make the connection with the Vanderbilt system and then the Vanderbilt rich gas service was initiated in June.

The Vanderbilt system will provide higher volumes of gas to these customers than was provided by the Gulf Coast system.

Third quarter volumes on Vanderbilt were approximately 55 million per day compared to 45 million in the second quarter and 33 million of lost Gulf Coast volume.

You'll also note Gregory gathering system volumes increased by about 46 million per day compared to the prior year, which is about 39% and Gregory processing volumes increased about 23 million per day, or about 28%.

The expansion of the Gregory processing facility, which we discussed in the last call, was only completed [inaudible] [in late August, and we then began] processing substantially all the gas going in to Gregory.

We anticipate that having the benefit of the expansion for the full quarter in the fourth quarter will provide a meaningful lift in margins from the third quarter to the fourth quarter.

In our last call we estimated that our third quarter results would be negatively impacted by less than 150,000 dollars of margin due to hurricane Claude de.

The actual loss in gross margin we realized in the third quarter was about 100,000 dollars as operating personnel did an outstanding job of quickly restoring service on the system.

Turning to our treating divisions, margins expanded as a result of the increase in plants in service from 30 at the end of the third quarter in 2002 to 45 at the end of the 2003 third quarter.

The increase in the margins from non-volume sensitive plants more than offset the decline in volume served by our five volume sensitive plants, whose volumes are reflected in the operating data.

Operating expenses increased about 2.8 million dollars in the quarter, about 104%, and 4.3 million dollars for the nine months or approximately 55%, primarily due to the expenses of the Duke assets acquired in June '03 and expenses at Hallmark and Vanderbilt as well as expenses at new treating plants in service.

General and administrative expenses charged to the partnership are capped at 1 1/2 million dollars per quarter not including expenses in connection with acquisition or business development opportunities.

These expenses amounted to $612,000 dollars in the first nine months of 2003, bringing total G&A to $5.1 million dollars for the nine-month period.

Had our G&A expenses not been capped, the total would have been approximately $7.2 million dollars in the first nine months, an increase of about a million dollars from the prior year, primarily due to staff additions associated with our recent property acquisitions.

As we have discussed in detail in the last couple of calls, this year we're incurring a charge for stock-based compensation, each quarter, related to the adjustment in our stock option program of the owner of our general partner.

Name it Crosstex Energy Inc., formerly Crosstex Energy Holdings.

The charges due primarily to the fact Crosstex Energy Inc. modified stock option plan to provide a certain amount of liquidity to employees.

The value of the employees options in Crosstex Energy Inc. under this program is largely based on the value of the Crosstex Energy LP partnership units held by Crosstex Energy Inc.

Inc.

Therefore, as the trading prices of the units increases, the value of the employees' options in Crosstex Energy Inc. increases, this is the primary component of this non-cash charge of $1.6 million dollars in the third quarter and $4.6 million dollars for the first nine months.

It's important to note again for you that the partnership pays out nothing in this program and issues no units in conjunction with this program.

From the partnership's perspective, it is an accounting charge only and this program will expire at the end of 2003.

Depreciation and amortization expense increased by approximately $1.9 million dollars in the recent quarter, and $3 million in the nine-month period due to higher levels of property, plant equipment on the balance sheet due primarily to the Duke acquisition.

Cash flow for the third quarter was 9 1/2 million, compared to 2002 cash flow of $4 million, an increase of 138%.

For the first nine months cash flow was $23.4 million dollars, compared to 9 million, an increase of 160%.

Distributable cash flow, which we have already highlighted and discussed, is calculated by deducting maintenance capital expenditures from our cash flow.

Distributable cash flow has continued to be favorably impacted this year by delay in certain planned maintenance capital expenditures to later in the year, or in calendar year '04.

Third quarter maintenance capital expenditures were about $900,000, and the year-to-date total is about $2.6 million dollars.

We continue to expect maintenance capital expenditures this year to be between $4 and $5 million million.

Turning to our guidance, we previously stated that we would achieve net income of between 12 1/2 million dollars and $13.6 million in 2003, and distributable cash flow for the year between 23.7 million and 25.8 million.

Given results for the first nine months, the start-up of the Gregory expansion in August and the performance of the Duke Energy field services assets that we acquired in the second quarter, we now forecast between $14 million and $15 million dollars for net income and between 26.9 million and 28.9 million in distributable cash flow for 2003.

Our 2003 distribution total with our current distribution of 70 cents per quarter applied to the fourth quarter distribution would be a total of $21.5 million dollars.

Given this, if we're able to attain our guidance targets and to not increase the fourth quarter distribution, we will achieve distribution coverage of between 1.25 and 1.34 times for the year.

No decision has been made at this time on the fourth quarter distribution.

Now I will turn the call back to Barry.

Thank you, Bill.

During the remaining time prior to our question and answering section, I want to provide an update on transactions.

We have previously discussed and summarized recent activities.

I would like to begin by talking about if integration of assets acquired in the Duke transaction which closed on June 30th.

As a reminder this, was a very significant growth step for us as it represented a 47% increase in pipelines owned and 35% increase in employees.

Given the magnitude of the growth by those two key measures, at least from an integration standpoint, I'm very pleased to say that we have not experienced any significant problems with the integration.

Importantly, and I think supporting that statement, our operating income on the assets slightly exceeded our expectations for the first quarter of our ownership in the third quarter.

Looking at the largest two individual assets acquired from Duke, first of all on the Mississippi system, we have begun a very aggressive commercial focus to pursue newly developed production as well as gas that is currently flowing to other pipelines in the area of our Mississippi system.

To date we have contracted for four new gas supply sources with a total initial production of approximately 12 million cubic feet a day.

Unfortunately this new gas has been offset by the loss of approximately 13 million cubic feet a day that we lost due to a call by a third party industrial buyer of a package of gas that has previously been coming to the Mississippi system.

This gas is split connected with an industrial buyer that came back online, so as a result of them coming online and pulling the gas under a preferential call, it has come off of the Mississippi system.

So with the 12 million cubic feet a day of new supply and 13 million lost, net-net the volumes will remain about the same.

We do hope going forward that we're able to attract back the 13 million which would represent a significant increase on the system, which is flowing currently about 83 million cubic feet a day.

In addition to the new well head gas contracted, we have begun also aggressively marketing our treating services in Mississippi.

We have reached agreement with a producer to set first treating plant for gas coming in to the system and expect that we will have that plant operational in the first quarter of 2004.

Again, this was an upside opportunity that we identified in the acquisition as much of the gas that's produced in Mississippi has to be treated.

Historically that's been done by third parties other than the pipeline operator.

So we'll be very focused on that and think it could lead to some upside in the future.

The second plant or facility that was part of the Duke transaction I want to focus on is the Seminole plant.

To date we have been very pleased with the increased margin we have seen there resulting from higher ngo prices than what we used in our acquisition models

We're also excited about a planned expansion that has been completed, currently in the start-up phase.

We expect the plant expansion to be fully operational by December 1 and it will increase our total plant capacity by about 60 million cubic feet a day, which represents a 35% increase.

Assuming ngo prices remain flat with the third quarter, the incremental volumes we can move through the plant would mean additional $1.5 million dollars to operating income on an annual basis.

As we have said previously, this plant gave us our entry in to the CO2 business and we remain excited about the opportunities to expand that position and we're currently evaluating various ways to expand in to the CO2 business particularly in the geographic area of west Texas.

Next I would like to update you on the Gregory expansion and the development of additional supply in to the Gregory gathering system.

By way of background, the Gregory processing plant and gathering system were acquired by Crosstex from Shalel/Tejas in May of 2001.

Gathering system comprises of approximately 300 miles of pipeline with a total through-put capacity in excess of 200 million cubic feet a day.

The system is connected to well heads in San Patricio, New Aces, [Oranges County] the Corpus Christi bay area, Mustang Island and adjacent coastal areas around the city of Corpus Christi in South Texas.

When acquired, through put capacity of 75 million cubic feet a day, and was expanded to 90 million cubic feet a day by us in late 2002.

As Bill communicated earlier, 60 million cubic feet a day plant expansion we spoke of often in the past, which now gets us to a total of 150 million cubic feet a day, has been completed and is fully operational since late August.

The project was completed on budget at about 7 million dollars.

Our current through put is approximately 150 million cubic feet a day, meaning the plant is essentially at capacity day one after the expansion.

Our average throughput has risen from 85 million cubic feet a day to the 150 as a result of this capacity expansion.

The incremental operating income expected to be generated by the increased plant throughput and additional gathering system throughput is about 3 million dollars on an annual basis.

With the expansion we have, we now have the capacity to hand in excess of 200 million cubic feet a day, including our blending capacity.

Again, let me just describe the plant can move 150 million through it.

However we have the ability to blend gas at the tailgate and still meet pipeline specifications which would allow to us move again about 200 million cubic feet a day, including the blending.

Based on producer drilling plans, our current forecast is that we will continue to see volumes increase, in fact we expect to see it exceed 160 million cubic feet a day here in the fourth quarter of '03 or early in to the first quarter of '04.

In conjunction with the Gregory plant expansion, obviously we have, we had to address the residue outlets.

In doing so, we have completed a project to expand our residue outlets with the acquisition of a 18-mile pipeline building of an additional two miles of pipe that would allow us access in to some new industrial markets.

As a result, we have entered in to long-term contracts that provide for about 40,000 mmbtu per day of sales to industrial markets in the Corpus Christi area.

Again, these are new markets we did not serve prior to the expansion-this pipeline.

Now I would like to move to our new Denton shale gathering system, we initiated gas flow on the system in late August, in fact it was shortly after our last conference call.

The system is initially 14 miles of well head gathering and will be connected to approximately 20 wells.

It is currently receiving gas from seven wells and throughput is approximately 3 1/2 million cubic feet a day.

Our initial production rates, consistent with our expectation.

However, the rate of completion of the wells has been much slower than anticipated.

We originally expected that all of the 20 wells that were in existence when we completed the system would be fraced and flowing in the system within 90 days.

Today as we look at the progress that's been made we would say it will take about twice that long to get all 20 wells flowing, unless the pace picks up dramatically from what we have seen in the past and it's just simply a matter of logistics of getting wells fraced in a fairly congested area and is taking a little longer than we had originally expected based on the producer's guidance there.

As currently configured, our Barnett Shale system has estimated capacity up to about 35 million cubic feet a day, we will continue to aggressively market the system and expand the system well beyond the 20 wells, assuming the project remains successful from a producer's standpoint .

While this project is relatively small at the present time we are optimistic with the wells connected to the system and high level of drilling activity that over time this will become a significant asset for Crosstex.

Probably most important, though, this is, this system gives us a presence in the prolific Barnett Shale play and we are looking to expand this position through acquisition in other grassroots growth.

Now I will move to our CC&Gs we initiated flow from a new field via nine-mile extension of the system to a new field is that operated by Camden resources here in Dallas.

This is into their [Hostetta] Wilcox field.

This has been a great project for Crosstex as we now have built four gas treating plants in addition to the nine-mile pipeline.

Ultimately we expect to receive as much as 50 million cubic feet a day from the field for sale off of the CC&G system.

Moving to our treating division, we just continued to see outstanding growth in the plants owned and operated.

As I said in the introduction, we have completed construction and start-up on 18 plants as of the end of October 2003, and we anticipate an additional six or seven plants to be completed by the end of the year.

In total we will have increased our plants in operation from 33 at the end of 2002 to approximately 50 plants at the end of 2003.

The pace of new plant installations has continued to increase.

We believe this is due to our enhanced ability to leverage off of our pipelines just as we're now doing in Mississippi.

We also believe it's because of the excellent quality of service that our team provides and competitiveness of our rates due to the critical mass that we have been able to accomplish.

To conclude my prepared comments, I would like to remind you of something that we have communicated in each of our first three earnings calls as a public company,

That is, we're simply executing a strategic plan that has been the same here at Crosstex since our inception.

That plan in summary is to buy the right assets, that means those that are strategically located and have the potential for enhanced utilization, that plan is totals buy them at the right price, then to enhance them after acquisition and to over time seek to consolidation of assets in certain core areas.

If we do this, we can achieve superior economic returns.

As evidence of the fact that we are executing the plan, we look to a measure that we focus on here at Crosstex in our every day operation.

In fact, the only measure that we use to calculate the bonus of all 185 employees of the company, and that is return on invested capital.

I'm happy to say for both your benefit as investors and the benefit of all employees of Crosstex that we have achieved a return on invested capital of over 18% for 2003 year to date.

Again, let me emphasize that the 18% is return on invested capital, not return on equity, which would be much higher assuming normal leverage of a balance sheet.

In fact we think it would equate to something in excess of 30%.

So I'm happy to report that we are having a great year at Crosstex.

It is a continuation of things we have seen in prior years, we have had a great year from a standpoint of growth and we --our deal flow and opportunities don't seem to be slowing.

So with that, I would like to wrap up our prepared comments and turn the call back to our operator Alicia to facilitate the answering of any questions and Bill in a will be handing your questions

Ladies and gentlemen, if you would like to ask a question, please key star followed by one our touchtone telephone.

If your question has been answered or wish to withdraw your question, please key star 2 again, star 1 to ask a question.

The first question comes from Ron Lont with A.G. Edwards.

Please go ahead.

You know, I was looking at the percentage of margin for the Midstream area, that is, you know, gross margin divided by the revenues.

And it's come down from 5.9% in 2002 to 5% even on 2003.

Can you give us some insight in to that?

Ron, that's primarily going to be a function of gas price and it's its inordinate impact on the revenue line which is why we tend not to focus very much on revenue.

Does that answer your question?

I think if you look on it on a per mmbtu basis you'll find it's gone up.

Okay.

In fact I have that number here, if you'll give me just a second.

Yes, if you look at it on a -- well, I'm sorry.

I'll get that back to you, Ron, in just a moment, if we can have the next question.

Sure.

On the P&L line of profit and loss from trading activities, it looks like you made about 646,000 in profit there, which is about 8 cents a share.

How sustainable do you think that is?

And do you really need an attractive natural gas price environment to sustain that?

In the producer services segment?

Well --

I'm sorry, Ron, that 646,000 is substantially all just our producer services business.

That is, according to the new accounting rules we have to reflect those as net, on a net margin basis.

There's no trading activity going on there, other than a small amount of P&L effect when we enter in to a hedge on behalf of one of our customers or producers.

So 98% of that 646,000 is just the margin that we earn in our producer services activity, buying gas off our systems.

Has that margin been enhanced by, you know, the kind of favorable natural gas price environment that we have been in?

Ron, this is Barry.

Let me address that that.

Again, I want to make sure you understand that basically this is a buy resale margin on the business that's done off of our assets.

If you take, if you annualize the amount shown here at 650,000, approximately $2 million a year, that is -- we have made $2 million a year, approximately, in gross margin on our producer services business for as long as we go back.

Meaning it hasn't grown, it hasn't declined.

It is sustainable.

You know, has very little to do with gas prices.

It is basically a service fee-type margin and, you know, to me it's characterized, it can be taken the wrong way by the way the line item is identified.

That's, I thought that was kind of fuzzy the way it was identified there.

Energy trading contracts means a physical buying and selling of gas on, -- off of our systems, not on our assets.

You answered a lot of my questions in the very fine detail of what's going on with the company, so the only question I had, other question I had, at least for now, is you expected to be able to increase volumes for the Formosa plant.

How is that going?

Are you going to be able to get any more volume volumes in the future?

We're very encouraged by, it all begins with a relationship and we're very encouraged by our relationship with Formosa.

You know, over the last ten years they have been sitting there with a 300 million cubic feet a day processing plant on the front end of their plastics facilities and many have tried to become the gas supply aggregator for them and have not been successful.

It's just been a difficult, difficult code to crack.

We have done so with currently about 55 million cubic feet a day that we're moving there through our Vanderbilt pipeline.

We are very actively working with them to expand this both off of our Vanderbilt system and in other ways, through other pipelines pipelines.

I am encouraged that we will do that.

We're actually looking at trying to get some rich gas off of our Gulf Coast system in to the Vanderbilt system and down to Formosa.

Currently with the hydraulics that we have, pressures on the pipelines, we believe we can move about 90 million cubic feet a day in there.

Beyond that we would have to start looking at some compression and so I think we have got that near term upside in front of us and then we will look for further upside with the Formosa relationship in other ways.

Ron, let me just further answer your first question and you can compute these numbers off the data in the press release.

But our average per mmbtu gross margin in 2002 was about 13 cents.

Year-to-date in 2003 it's been about 15 cents.

Okay.

Also curious, the Gregory processing plant operating at capacity now, what's the anticipated time line and can you expand that plant again?

Yeah, if I were you, I would kind of wonder why we don't build capacity in excess of what we're flowing and kind of get out in front of it where we have a growing supply.

The answer is that this is one of the only facilities that we aren't able to kind of, to get underwritten throughput.

Most of the time when we're building facilities, for example the nine-mile extension off of the Corpus Christi system, we have volume commitments and volume guarantees, if you will, that support the capital investment with a minimum return.

It's been difficult to do that in the processing plant so what we try to do is build just enough capacity.

We use the excess of the blending capacity, the 50 million cubic feet a day, another 33%.

We use that for kind of that excess volume that we may have over a period of time.

In a perfect world we see the volume go up to 200 million a day.

We hand it through blending and after we get comfortable that it's there and sustainable, then we look at an expansion.

Expansion like what we just did, 50 to 60 million a day expansion, all in will take about 8 to 9 months to accomplish and so that would be our lead time.

Okay, thank you.

The next question we have comes from John Tysseland with Raymond James.

Please go ahead.

Good morning.

I just wanted to ask you a couple quick questions on really the state of your competition and I guess in south Texas and Mississippi.

Do you feel like, you know, you're obviously have a lot of internal growth projects and some good volume growth.

What's your competition look like down there?

And is it that a factor or a benefit?

Yeah, one thing, John, every time I slow down long enough to look at all the things we have going on, you know, every day, I know what's going on, but I don't necessarily stop to reflect on it.

But here as we do that at the end of a quarter, it's clear that Crosstex is just very aggressive when it comes to commercial development of new projects and I'm proud of that.

And I think it's what really allows us to, you know, be a good acquirer.

I mean we have a great ability to enhance after acquisition.

South Texas has been a great fertile ground for us.

I mean we continue to see opportunities through to expand there from a comp competition standpoint it feels at the moment like everybody identified their core focus and, you know, in the case of Kinder Morgan, for example, I mean they're very much focused on the transmission part of their business, they're doing very large gas supply deals to move long haul transmission.

They haven't been focused on the upstream, which is where we really continue to focus with the treating business and the expansion in to new fields of production.

You know, the others we obviously are seeing the Gulf Tara/ El Paso assets again have a little different focus.

Maybe that's why we accentuate the upstream and full range of services, is that we're able to differentiate ourselves.

You know, the treating business has been a leading service for us.

We get in front of a producer providing the treating facility and it kind of gives us a foot in the door to do more than that and to see all the competition, if you will, for the pipeline connection.

You know, we know competition is there, so far I think we feel pretty good about our ability to compete there.

Mississippi, it appears at the moment that we're the ones wanting to grow systems over there.

Our main competition is the Gulf South System and, you know, I think they have a little different mode as far as aggressively pursuing the well head gas, but we operate as if, if they're as aggressive as we are.

But I will say we have got essentially the same markets at the well head as Gulf South does, so we're all kind of going to be working with what margin are we willing to accept, knowing our resale price is about the same.

We also have interstate markets and we are developing more markets off the Transco system, primary internet market off the Mississippi go, I feel good about our ability to compete and we aren't seeing anything that's dramatically changing over there.

With your treating plants, how many of those do you have left in inventory?

Or I guess that you could refurbish and put out?

Yeah, John, boy, what a neat business that's been for us.

We haven't had to expand our inventory.

We have approximately 12 to 14 plants in inventory at all times and what we do is plants are distinguished by their capacity and we basically inventory plants with a capacity from about a million cubic feet a day in the typical application up to about 30 million cubic feet a day.

And that, in a plant size, that's basically a ten gpm, 10 gallon per minute plant up to 3 million gallon per minute plant, we essentially always have ready and available a plant in each size from 10 to 60 to 100 up to a 300 gpm plant.

Anything bigger we know we would have the lead time that was necessary to basically refurbish and acquire and refurbish the plant so.

The answer is, we had about 12 to 14 plants in inventory when we had 25 plants in operation, that's the same size that we have today with 50 plants in operation.

Just on, you mentioned the Seminole expansion.

Is there going to be any downtime associated with that expansion in the fourth quarter?

Or is that going to be -- you can get through it without that?

No, it is done in basically in a separate train where we will not have downtime on the existing capacity.

And then the Gregory expansion, you said you were running at 150 today.

Didn't you say you had capacity with your ability to blend at the back end to 200?

So you still have 50 left?

Or did I read that incorrectly.

Keep in mind if for volumes moved over the 150 million, we would be, our margin gets reduced because we're not able to, our margin there is basically comprised of a gathering fee, a processing fee and a frac in to the various ngo products.

So on that last 50 million if we run 200 we wouldn't have the frac fees, we still have the processing fee and the gathering fee.

But yes, we can move up to the 200.

On Gregory, how are your liquids?

You know, your liquid being taken over from the plant, have you had any trouble finding markets for that?

Has that not been a problem?

It has not been a problem.

The market there has been, you know, we're so strategically located to the markets there that we haven't had any problem and I'm not familiar that we expect any that's upcoming.

One last question would be, you know, on your other Midstream, what has changed in that category?

What is included in that category?

How has that changed quarter to quarter sequentially?

Well, the primary impact there, John, is just some of the other assets that we have acquired that are reflected in the growth in that line, for example, some of the smaller assets on the Duke system are in that category now and we are in fact experiencing higher volumes on some of those than we had anticipated when we did the acquisition.

In addition, Denton county is in that category.

So some of the, most of that growth you see is just reflecting to adding new smaller assets in conjunction with those type transactions.

All right, thanks, guys, great quarter.

Thank you, John.

We have no more questions at this time.

Would you like me to repeat the instructions?

Yes.

Actually, we have a question from Brian Watson with RBC Capital Markets.

Please go ahead, sir.

Yeah , the new guidance for epu and dcs, does epu include the non-cash stock compensation charges?

Well, the footnote there on that page, we didn't give earnings per unit guidance but we did give aggregate net income.

Net income guidance.

Yes, and the footnote there says that we assume that we don't have any further charges due to the modification of the stock options.

Obviously if we do have charges it doesn't impact the distributable cash flow because it would be added back to the cash flow number, but, you know, if we did have charges it would reduce the net income number.

And the guidance that was provided at the second quarter that also did not assume any further charges?

Right.

Okay so it's kind of a bigger pickup than it would initially seem.

Yes.

Okay.

Then also the -- can you give an update on the utilization rates in general given the higher volumes for this quarter?

Yeah, we continue to have, Brian, this is Barry .

Our utilization there is obviously going up.

If you look at our systems, the CC&G system, we have a nice pickup with volume, new volume coming in.

The Gregory system, as we communicate the gathering system has probably a little over 200 million cubic feet a day of capacity, which matches, if you will, the blended capacity of the plant.

So we would be at approximately 75% of that.

On the CC&G system, Gulf Coast system, Vanderbilt, on average it's going up slightly, but it's still at a fairly comfortable 60% or so.

We don't see capacity constraints on any of those systems that would keep us from developing new opportunities.

Okay.

Then you may have had this in front of you, at some point you gave an earnings sensitivity to changes in natural gas, natural gas liquid prices, have you updated that?

We haven’t , and it hasn't changed.

Then I good he is the last question is kind of I was trying to back in to how the gp share of net income is calculated.

Based on actual, but percentage of net income?

The gp share of net income is based on your starting point is it's 2% ownership interest and then the balance, the difference between that number and the reported number is base basically the general partner's share of the idr’s.

Okay.

So that's 2% of net income plus the idr?

Right.

Okay.

I think that's it.

Thanks.

Thank you. .

The next question comes from Mark Easterbrook with RBC[inaudible].

Hi guys, I see Brian got a lot of my questions.

But just one question.

Did you look at the energy transfer assets?

I know you guys know those people, the management team there somewhat.

Did you guys get to look at those assets at all?

You know, actually, Mark, we mow the energy transfer guys and they have done a great job in putting a that deal together and then on the deal that they announced last week.

We really didn't.

We spent some preliminary time on the major asset was the Texas, central Texas facility.

We spent a lot of time on the Oklahoma plant.

The Oklahoma facilities gathering system and plant, but we didn't spend much time on the Texas facility.

We really don't have any thoughts on those assets.

I know it's working great for them, from what we understand.

Just quickly, maybe you already mentioned this, but what was the debt outstanding at the end of the quarter?

After the Duke acquisition and all that?

At the end of the quarter we had 43.2 million dollars of debt outstanding and we should file the 10q with all those numbers in it this afternoon.

All right, thanks, guys.

Thank you, Mark.

Again, ladies and gentlemen, to ask a question, please key star followed by 1.

We have no questions, Mr. Davis.

Alicia, thank you.

And again, to everyone on the call, we appreciate you and we look forward to any communication between now and the fourth quarter or talking to you then.

Thank you again..

Ladies and gentlemen, thank you for joining today's conference.

This conclude it is program.

You may now disconnect.

Good day.