EnLink Midstream LLC (ENLC) 2003 Q2 法說會逐字稿

Welcome to the Crosstex Energy second-quarter 2003 earnings call.

During this presentation, all participants will be in a listen-only mode, and we will conduct a question-and-answer session at the end of the conference.

As a reminder, this conference is being recorded today, Friday, August 8 of 2003.

I would now like to turn the call over to Barry Davis, President and Chief Executive Officer of Crosstex.

Thank you, Carlo, and good morning, everyone.

Thank you again for joining us today in this conference call to discuss our second-quarter 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 second quarter in detail.

When Bill is finished, I will give you an update on important recent developments, and then we will conclude the meeting as usual with a question-and-answer period to answer any questions you may have.

Our second-quarter earnings release was distributed last evening.

For those of you who did not receive a copy of the release, you can call us or download it from our Website at CrosstexEnergy.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 Website for the next 30 days.

For legal purposes, I must remind you that 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.

In addition, during this call, we will discuss certain non-GAAP financial measures.

You can find reconciliations to the most directly comparable GAAP financial measures in our earnings release, which is available on the investor relations page of our Website.

With that, I would like to turn the call over to Bill Davis, who will begin today by discussing the second-quarter results in detail.

Thanks, Barry, and welcome to all of you participating in the call.

We appreciate your interest in Crosstex.

For purposes of today's discussion, I wanted to start with a number that I think most of you will focus on first, and then go back and fill in with how we got there.

We think the number most of you will focus on the most is the distribution coverage.

In the second quarter, we covered the 55 cent cent distribution 1.6 times, and in the first half, we covered the $1.05 distribution by 1.55 times.

Distributable cash flow in the second quarter was $6.8 million, and in the first half, it was $12.2 million, compared to 2.4 million and 4.4 million in the comparable prior-year periods.

Gross margin in the second quarter increased to $13.1 million from $8.1 million, an increase of $5 million, more than 60 percent.

And for the first half, gross margin increased to $23.9 million from 15.2 million, again by more than 60 percent.

Net income for the quarter was just under $5 million, or 65 cents per unit, compared to $224,000 last year, and for the year to date, net income was $5.8 million or 77 cents per unit, compared to a small loss last year.

Of course, the units were not outstanding last year, so per-unit earnings are not applicable to the prior-year numbers.

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

Midstream margin growth was primarily a function of new volumes at Vanderbilt and Hallmark, and an increase in average unit volumes on almost all systems.

Margins were helped somewhat by higher gas prices than in the 2002 period, but mostly by improved commercial operations.

It is worth noting that, despite a negative frac spread in the quarter, Gregory processing margins were actually better than in the 2002 quarter, due to continue movement to fee-based processing arrangements rather than frac-spread-based arrangements.

During the quarter, only about 22 percent of the gas we brought into the Gregory system was purchased under a contract in which we took the frac-spread risk, compared to approximately 50 percent in 2002.

In the schedule of operating data provided with the press release, you will note that the Gulf Coast system volumes actually declined from the prior year.

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

We used a lateral that we cut from the Gulf Coast system to make the connection from the Vanderbilt system to these customers.

Service to these customers was discontinued off the Gulf Coast system the first of May, in order to allow the construction time necessary to make the connection with Vanderbilt.

The Vanderbilt rich gas service was then initiated in June.

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

Current volumes on the Vanderbilt system are approximately 55 million per day, compared to 44 million in the second quarter and 32 million of lost Gulf Coast volume.

You will also note that the Gregory gathering system volumes increased by approximately 52 million per day compared to last year, or more than 50 percent, while Gregory processing volumes increased by only about 8 million per day or about 10 percent.

We expect to start up the expanded Gregory processing facility, which we discussed in the last call, by the end of August.

Startup of the expansion has been delayed by rain in the Corpus Christi area, particularly from from Hurricane Claudette, which you will recall came ashore in Corpus in July.

After the startup, then we will begin processing substantially all of the gas going into the Gregory system.

I mentioned Hurricane Claudette as a factor in the Gregory delay.

I know many of you have had a question as to the amount of impact we sustained from the hurricane in our third-quarter results.

Our current estimate is that our third-quarter results will be negatively impacted by less than $150,000 of margin from the hurricane.

Treating division margins expanded as a result of the increase in plants and service from 32 at the end of the second quarter in 2002 to 43 at the end of the 2003 period.

This increase more than offset the decline in volumes served by the volume-sensitive plants which you see in the operating data.

Operating expenses increased approximately $770,000 in the quarter, and about 1.5 million for the six months, each approximately 30 percent over the prior year, primarily due to operating expenses at Hallmark, Vanderbilt and the new treating plants and service.

Importantly, the percentage increase in operating expenses is much less than the percentage increase in margins we experienced.

General and administrative expenses charged to the partnership are capped at 1.5 million per quarter, not including expenses incurred in connection with acquisition or business development opportunities.

These expenses amounted to 391,000 in the first half, bringing total G&A to $3.4 million for the period.

Had the expenses not been capped, they would've been approximately 4.6 million in the first six months, approximately $400,000 more than the prior year.

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

This charge is due primarily to the fact that Crosstex Energy Holdings modified its stock option plan to provide a certain amount of liquidity to our employees.

The value of the employees' options in Crosstex Energy Holdings is largely based on the value of the partnership units owned by the general partner.

Therefore, as the trading price of the units increases, the value of the employees' options in Crosstex Energy Holdings increases.

This is the primary component of a non-cash charge of 568,000 in the second quarter and $3.1 million for the first half.

It's important, once again, to stress, as we have on the last couple of calls, that the partnership pays out nothing for this program and issues no units in conjunction with his 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 $600,000 in the quarter, and $1.2 million in the six months, due to higher levels of property, plant and equipment in service by the partnership.

Cash flow for the second quarter was $8.2 million, compared to 2002 cash flow of 2.7 million, an increase of 300 percent.

For the first six months, cash flow was $13.9 million, compared to $5 million, an increase of 270 percent.

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

And these figures are all appended to the press release.

BCF (ph) has been favorably impacted this year by a delay in certain planned maintenance capital expenditures till later in the year.

However, the second-quarter rate of about $1.4 million in maintenance capital was close to a level we expect to see in the next two quarters.

Therefore, we still anticipate maintenance capital expenditures for the year of between $4 and $5 million.

The guidance that we previously furnished was that we would achieve net income this year of between 11.3 million and 13.2 million in 2003, and distributable cash flow for the year of between 21.4 million and 24.3 million.

As we have said, one of the variable in that range, the Gregory plant expansion, will start up in a few weeks; and volumes in front of the plant now appear to be consistent with our expectations when we began the expansion.

The Duke Energy Field Services asset acquisition has now closed, and those assets appear to be performing in line with our expectations, which were incorporated into our last forecast.

Therefore, given the first-half results, the Gregory startup and the Duke Energy Field Services asset closing, we now forecast between 12.5 million and 13.6 million for net income, and between 23.7 million and 25.8 million in distributable cash flow for 2003.

Our 2003 distribution, with our increase in the distribution to 70 cents per quarter, will be a total of $18.9 million.

Given this, if we are able to maintain our guidance targets, and no further increases in the distribution, we will achieve distribution coverage of between 1.25 and 1.36 this year.

Now, I'll turn the call back over to Barry.

Thank you, Bill.

In the remainder of the time before we get into the Q&A, what I would like to do is provide an update on transactions that we have previously discussed, and summarize our recent activities.

Since our last call, we have been able to complete, or are very near completion of, many of the key transactions and projects.

Starting with the Duke transaction, as expected, we closed the transaction on June 30 and took over operations July 1st.

After almost a month and a half of operating the new assets, we remain confident that we have accurately projected their performance.

Additionally, as I have communicated before, for Crosstex, the work just begins with the closing.

We are now very focused on enhancement of the assets, and are encouraged by the potential we see for enhancements.

As a reminder, the Duke transaction is the largest transaction to date for us, at $66.35 million.

It adds approximately 800 miles of pipeline to our existing 1,700-mile asset base, for a 47 percent increase.

It increases the throughput on our systems from 500 million cubic feet a day to over 650 million cubic feet a day, a 31 percent increase.

It brings our total volume handling (ph) to over 1 BCF a day.

Finally, it increases our employees from 130 to 175, or about a 35 percent increase in employees of the Company.

We continue to believe that this acquisition is an excellent fit for us, because of the growth or accretion that it represents.

The timing has been outstanding.

Following the IPO just six months ago, the size of the deal was perfect, and the characteristics of the assets to be acquired could not be better.

In previous discussions regarding the acquired assets, we have emphasized her enthusiasm for the Mississippi pipeline.

This pipeline gives us a new geographic core in an area of strategic gas producing region in Southern Mississippi.

It is a system that gathers gas at the wellhead, and delivers it ultimately to the burner tip, very much like our Gulf Coast and CC&G systems in South Texas.

It has a franchise-type position in its area of service.

As expected initially, this is the asset where we're seeing the most opportunities.

The opportunities that we're seeing are primarily to increase throughput by connecting to new gases being developed as a result of several very active exploration and development programs in the vicinity of our pipeline.

Additionally, we're seeing opportunities to expand the market share of industrial and utility markets that we serve in Mississippi.

Finally, related to this significant growth step for Crosstex, I think it is important to note that we have very successfully recruited and hired the people that will join our existing staff to run these new assets.

We have increased our staff by approximately 35 percent, as I mentioned, as a result of this transaction.

As I have said many times, our people are the key to turning steel in the ground into cash flow.

And what we have seen is that this is a great time to be hiring professionals in the natural gas industry, and we have hired some of the best in the business to add to our team.

Next, I would like to focus on the Gregory expansion and the development of additional supply into the gathering system.

We continue to see an increase of volumes available into the plant from our system, as Bill communicated earlier.

Our volume averaged 154 million cubic feet a day in the second quarter, up from 133 in the first quarter and less than 100 in the second quarter of 2002.

As a result of the increase, we're nearing completion of an expansion of the processing plant in the system.

The expansion will increase the plant capacity from approximately 90 million cubic feet a day to over 150 million cubic feet a day.

Given the timing of the startup, as communicated in our first-quarter conference call, we expect to see up to an additional 1.3 to 1.5 million in cash flow for this year.

Annualized, the initial cash flow from the project is projected to be approximately $4 million.

The cost of this expansion is on budget, and is expected to be approximately $8 million.

Combining the two, the $4 million estimated cash flow and the 8 million capital expenditure, you can see the quality of this project is being an add to an existing asset base.

Now, let me focus on the Vanderbilt system.

As Bill mentioned, part of the good results that we have communicated for the second quarter was the result of the Hallmark and the Vanderbilt system results.

As a reminder, the Vanderbilt system was acquired recently from Devon back in December, and consists of over 200 miles of gathering and transmission pipelines.

It gathers rich gas from several prolific producing South Texas counties, including primarily Wharton and Fort Bend Counties, just Southwest of Houston.

We closed the acquisition of the asset in December and began preparing to change dramatically the operation of the system by June 1st.

We were able to complete the transformation on time, and began flowing gas to a new processing plant owned by Formosa Plastics, and start to sell gas into the Formosa market on June 1st.

Volumes are now at 55 million cubic feet per day, compared to approximately 30 million cubic feet a day at the time of our acquisition.

This represents an 80 percent increase in throughput in just six months.

Now, let me move to our Denton County Barnett Shale project.

We've completed the initial phase of the system, which consists of 14 miles of 4-inch to 12-inch pipeline that is connected to 18 wells that have been drilled and are awaiting final completion.

Final completion operations are being performed on the first of the connected wells as we speak, and we expect gas will be flowing into our system within the next few days.

The completion operations will move to successive wells until all are completed and flowing into the system.

This is expected to take approximately 90 days for all of the connected wells to be flowing.

In addition to the 18 connected well, there are four wells currently drilled that will be connected, and an additional 19 wells that are identified and planned for drilling by the producers in the area.

Now, let me move to the Treating division, where we have continue to experience significant growth in the plants owned and operated.

During the second quarter, we completed construction and startup on six plants, and we are currently in construction on an additional four plants that will be completed in the third quarter.

The Treating division continues to see better-than-expected, better-than-projected results, and we expect that to continue moving forward as the South Texas area has provided a very active drilling and a very active opportunity for our Treating business.

With that, I would like to wrap up our prepared comments and turn the call back to our operator, Carlo, to facilitate the answering of any questions.

And Bill and I will be handling your questions.

John Tysseland, Raymond James.

I just had a quick question on -- when you are looking at Gregory, you have been showing some excellent volume growth in that area.

And I was kind of curious on what's the production profile, I guess, of the gas wells behind that pipe and the processing plant?

And then, do you continue to see activity back there like you had previously?

Yes, John.

First of all, let me tell you that we've got a mix of gas that comes from onshore, in the Corpus Christi area there, and offshore.

With that mix or blend, if you will, of maturity on the producing property, then we have kind of got a blended production profile.

Certainly, the more mature wells have a very minimal decline rate and then, on the opposite end of the spectrum, the newer wells coming from offshore will have a steeper decline early on.

Fortunately, I think the blend is going to make the decline something that we can work with.

Secondly, we are seeing a continuation of the drilling and development plans of the producers.

In fact, we're projecting that volumes will continue to increase throughout this year, and we have specific drilling plans by the producer that would support that.

Now, let me say, though, that we do acknowledge that if you were to see those drilling plans change, then the decline would start to affect the property.

And that's why we felt like the short return of payout on the capital project is important, with the two-year payout on the initial capital.

The Arkoma region showed a bit of a sequential increase.

What are you seeing in that area?

I am actually surprised.

When you look at it on a quarter-over-quarter or year-over-year basis, that system has remained about flat, but the good news is we are seeing even more substantial growth here in the third quarter.

We're actually flowing about 17 million a day into the system at the beginning of this month, and that's the result of a couple of higher-deliverability wells that have been tied into the system.

So we are seeing good development there, good results.

And I think in the next quarter, you are going to see even more dramatic increase.

It's hard to predict at this point what the third-quarter average will be, but it will be up and will continue to be up.

From the demand side, have you seen any customers -- I guess, more industrialized customers -- backing away due to higher gas prices, or taking in less gas, that you have seen?

We have not, John.

And it's a question that we have focused on here very closely.

We certainly believe intuitively that there is a point in time where that would become an issue, but we have seen no evidence of cutbacks at this point.

I would say we became more concerned when we saw gas prices above $6, and we weren't sure if they were going to stay at that level.

I can tell you, though, that we are focused on a study right now that would tell us what our sensitivities are, and what our response would be in the event we saw any cutbacks from our industrial markets, either in the Gulf Coast system or now, in our Mississippi pipeline system.

Just to remind you, we do have a very diversified market base there, with electric utilities, with power generation distribution companies, industrial load, and the industrial load itself is very diversified as far as the type of market we're serving.

We have no indication that there is going to be cutbacks, but we want to be on top of it and know where our alternative markets are going to be, if that were to happen.

And one last question would be, can you just update us on the contract that you have with Calpine, and the amount of gas that they are taking and how that is working out for you guys?

Yes.

We originally entered into a long-term contract with Calpine, and it is a firm transport agreement.

It basically has a demand charge, which means basically an annual fee for access to capacity on our pipeline.

That is paid at the beginning of each year, before flow is actually -- or before service is actually delivered.

They are taking about 60 million cubic feet a day -- I think, actually 57 to 58 million cubic feet a day on average.

And that has been pretty consistent, month-in, month-out, over the last six months or so.

So it has worked very well.

I think the project seems to be working well for them, and deliveries have been very stable for us.

Paul Ferguson (ph), Swank.

Could you talk a little bit more about the increase in the gross margin and your Midstream segment?

It looks like it went from about 14 to 15 cents up to about 18 cents.

Is that something you expect going forward?

We feel good about the margin impact that we saw in the second quarter, and really, there were a lot of good things that happened in the quarter that contributed to that.

A lot of it was just smart operations by our operations and commercial people.

And we are somewhat hesitant to predict that we will have that much good fortune going forward, and in fact, in our guidance, we haven't used that kind of margin on a go-forward basis.

But we certainly hope to see it continue.

You mentioned prices and commercial.

Is it basically just some purchasing agreements that you have that you have been able to negotiate a better price, because of the high prices?

Or what was the impact of prices on that?

Paul, I think that's right.

Let me answer that in a couple of ways.

Forever, we have said that at $5 gas prices, you see better margins than you see at $2.

Producers are just a little more easy to deal with, I guess you would say, at $5 than at $2.

So that's been part of it.

We have been able to expand some margin on our short-term contracts.

Secondly, we have had the opportunity to take advantage of some of the market volatility.

And what I mean by that is that if we started a month and saw a dramatic move in one way or another, we have been able to move gas to access the higher-priced market or change our supply position to take advantage of the lower-cost gas supply.

Generally, I would like to say that we would be on the positive side of taking advantage of volatility 9 times out of 10, and the one time out of 10, you are not going to be able to take advantage of it.

It seems like in the first half and in the second quarter, as we have said here, what can go right has gone right, and we have been able to take advantage of those.

While we would challenge ourselves to make that happen in the next quarter and the next six months, we won't count on it and we won't show it to you in the projections.

Malcolm Day (ph), Eagle Global Advisors.

I wanted to ask you, on your processing business, you mentioned that you had renegotiated or reduced your number of contracts that were subject to frac-spread risk, and I was interested in knowing if you were attempting to renegotiate the remainder, and if the contracts that you had changed -- if they had gone to pure fee-based, or if they were more -- I mean, if they were cash-fee-based or if they were a percent of proceeds or what the process had been there.

The answer is we have moved most of that frac-spread risk into fixed-fee, basically a treating fee or throughput fee type structure.

In some cases, we expanded gathering margin, for example, and basically left the producer with the processing opportunity, and then charged a treating fee or a processing fee.

So it would be fixed-fee.

I don't know believe we have done any percent of proceeds, so we haven't just moved it into a commodity price risk from a frac-spread risk; it has truly become a fixed-fee.

The second part is we have gotten the volumes down to the minimum level that we can, given the contracts that we have.

The contracts remaining have some term on them.

And, Bill, I am not familiar -- I can get the timeframes, but off the top of my head, I think we still have significant time left -- a couple of years left, on those contracts.

I was wondering if maybe you could give us an update on -- I guess, with margins where they were, there were a lot of other people who were not running their processing plants, and they were running them at, I guess, low volumes, undercapacity.

And I was wondering if your volumes were down in processing, or if you were not having that effect because you were, again, not -- most of your volumes were not affected by frac spreads, and therefore you were processing.

Most importantly, we have to process the gas to make it pipeline quality.

It's not discretionary processing, so no; we ran at full capacity throughout the last six months.

And as I said, we actually saw margins increase at the plant year over year, just because of the increase in the volume that we had from fee-based arrangements.

Currently, we have no questions in queue.

Thank you, and everyone on the call, thank you for your interest in Crosstex.

Thank you for your support.

We are happy to have a good report today, and look forward to a good third quarter and talking to you guys at that time.

With that, we will end the call.

Thank you, guys.

Thank you.

Ladies and gentlemen, that does conclude our conference call for today.

We do thank you for your participation, and ask that you please disconnect your line at this time.