EnLink Midstream LLC (ENLC) 2009 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth-quarter 2009 Crosstex Energy earnings conference call.

My name is Janeda and I will be your operator for today.

At this time all participants are in listen-only mode.

Later we will conduct a question-and-answer session.

(Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today, Ms.

Jill McMillan of Crosstex Energy.

Please proceed.

Thank you, Janeda; and good morning, everyone.

Thank you for joining us today to discuss Crosstex' fourth-quarter and full-year 2009 results.

On the call today are Barry Davis, President and Chief Executive Officer, and Bill Davis, Executive Vice President and Chief Financial Officer.

Our fourth-quarter and full-year 2009 earnings release was issued early this morning.

For those of you who did not receive a copy, it is available on our website at CrosstexEnergy.com.

If you want to listen to a recording of today's call, you have 90 days to access the replay by phone or webcast on our website.

I will remind you that any statements that might include our expectations or predictions should be considered forward-looking statements within the meaning of the federal securities laws.

Forward-looking statements are subject to a number of assumptions and uncertainties that may cause our actual results to differ materially from those expressed in these statements, and we undertake no obligation to update or revise any forward-looking statements.

We encourage you to review the cautionary statements and other disclosures made in our SEC filings, specifically those listed under the heading Risk Factors.

I will now turn the call over to Barry Davis.

Thank you, Jill.

Good morning and thank you all for joining us on the call today to discuss our fourth-quarter and full-year 2009 results.

I am extremely pleased with our results (technical difficulty) we made in 2009.

This was truly a transformational year for Crosstex, as we successfully executed our plan to increase liquidity, improve profitability, and reduce debt, which has repositioned us for long-term success as we begin 2010.

Over the past year, we sold non-core assets, which improved our overall business focus and strengthened our balance sheet by reducing leverage.

In January, we sold our East Texas assets, our remaining non-core properties, for $40 million.

This brings the proceeds from our asset sales to over $600 million, which were achieved at an average EBITDA multiple of over 8 times in an extremely difficult market.

We improved our risk profile through the sale of assets with high commodity exposure, increasing fee-based contracts, and continuing to hedge our remaining commodity risk.

We strengthened our cash flows by cutting costs and maximizing operating efficiencies.

We invested in high-return, low-risk projects around our strategically located assets in North Texas and Louisiana, where we see continued continuing opportunities for incremental growth.

We completed a $125 million convertible preferred unit offering with Blackstone GSO, and believe Blackstone GSO's investment is a strong vote of confidence in us and our future.

We are pleased to have them as a partner and look forward to a long-term working relationship with them.

Finally, just a few weeks ago we completed the private placement of $725 million of senior unsecured notes and closed a new $420 million senior secured revolving credit facility with a four-year term.

This successful recapitalization allowed us to repay all of our previously outstanding borrowings and create a long-term financial structure with greater financial flexibility.

Today Crosstex is a leaner, more efficient, and focused Company as we look to 2010.

We will continue to capitalize on high-return, low-cost opportunities around our Barnett and Haynesville Shale assets, which are located in the heart of these plays.

We recently executed contracts for the first 30 million cubic feet a day of our phase four Red River expansion.

I will talk more about this opportunity in the operational update.

We will also continue to reduce leverage and manage our business according to conservative financial guidelines.

We will continue to take advantage of near-term processing and NGL opportunities in south Louisiana.

We will continue to efficiently manage our risk profile while enhancing our operational efficiencies and optimizing results.

Lastly, we will continue to evaluate emerging shale plays to capitalize on our core competencies learned in the Barnett and Haynesville Shales, to analyze which would be the best fit for Crosstex beyond 2010.

As markets recover and natural gas drilling rebounds in 2010, we will look to capitalize on strategic growth projects.

In North Texas, major and large independent producers are increasing their focus on the Barnett Shale as a proven, long-lived, and viable shale play.

We believe this is a strong vote of confidence in the future of the Barnett.

As I am sure you are aware, these include Exxon's proposed acquisition of XTO; Total's purchase of an interest in Chesapeake's assets; Quicksilver's alliance with Eni; and Devon's planned sale of international and offshore properties and increased focus on the Barnett.

In Louisiana we continue to see drilling increase at a steady rate in the Haynesville Shale, where producers large and small are rapidly increasing their activity.

The current increase in activity and the continued optimism about the future of the Haynesville are good news for Crosstex, and we believe the entire play is an outstanding growth opportunity for us.

Finally, due to increased liquids production and higher processing margins, we are seeing strong growth opportunities in our processing and natural gas liquids business.

2009 was a good year for us financially.

Adjusted cash flow for the full year of 2009 was $203.8 million, including both continuing and discontinued operations.

We are forecasting adjusted cash flow in a range of $160 million to $190 million in 2010.

We have established financial guidelines that we will follow when making decisions regarding the restoration of our distribution and dividend.

Based on our current assumptions, distributions could be paid from the results of operations of the fourth quarter of 2010.

Bill will discuss this as well as our financial results and guidance in greater detail later.

Moving on to operations, I will update you on fourth-quarter activities and our accomplishments in 2009.

I will also provide insight into what we see for 2010.

In North Texas, our assets are situated primarily in the core of the Barnett Shale, one of the most significant shale plays in the US.

Recently we commissioned a third-party engineering study to evaluate our assets.

The study confirmed that the Barnett Shale continues to have tremendous potential, and our North Texas assets are positioned in the most prolific part of the play.

The engineering firm estimates that over 50% of the total production will occur within 3 miles of our existing infrastructure.

Our assets are positioned to benefit from the development of the Barnett for many years to come.

Along with the recent merger and acquisition activity in the Barnett, some producers, several of which are Crosstex customers, have recently announced plans to add rigs in the coming months.

We believe this is another sign that the Barnett remains a strong, stable, and desirable resource play.

In 2009 North Texas pipeline average throughput was approximately 318,010 mmBTU per day during the year.

Our fourth-quarter 2009 throughput for our North Texas pipeline was about 331 million BTU per day, up 5% from the third quarter of 2009.

Throughput in 2009 on our North Texas gathering systems for the year was 793,000 mmBTU per day compared with 670,000 mmBTU in 2008.

Fourth-quarter throughput was approximately 764,000 mmBTU per day or about 3% lower than the third quarter of 2009.

The overall reduction in gathering volume was largely due to the renegotiation of a key producer contract, which reduced gathering volumes and increased transmission volumes, and the impact of reduced drilling in 2009 due to low natural gas prices.

We expect volume growth in 2010 based on our conversations with producers; but we will see a slight decline in the first quarter of 2010 due to a compressor outage.

Our North Texas processing plants processed an average of 203,000 mmBTU per day during the fourth-quarter 2009, and we are operating at full product recovery levels.

The NGL pipeline interconnect with ONEOK's Arbuckle line, which was completed and placed in service earlier in the year, has increased our liquids takeaway capacity and gives us access to improved product netbacks.

To summarize, our assets are ideally situated to benefit as the Barnett Shale resource is developed over its life.

We will continue to focus on optimizing our North Texas systems and providing top-quality cost-effective services to all of our customers.

In Louisiana, we own and operate LIG, one of the largest intrastate pipelines in the state of Louisiana, which is strategically located to provide much-needed takeaway capacity for Haynesville Shale gas and access to premiere interstate pipeline outlets and industrial markets in Southern Louisiana.

As we did in North Texas, we hired a third-party engineering firm to independently evaluate the Haynesville Shale in relation to our assets.

Their study concluded that production in the Haynesville Shale will increase at the rate of 1 Bcf per day per year during the next 10 years from its current level of approximately 1.5 Bcf per day.

The study also showed that our pipelines are located in the Haynesville Shale's core producing area.

We should be in a great position to continue to take advantage of opportunities from the development activity around our assets.

For the year 2009, LIG throughput averaged over 900,000 mmBtu per day versus 960,000 mmBTU per day in 2008.

In the fourth quarter, throughput averaged approximately 881,000 mmBTU per day, compared with 898,000 mmBTU per day in the third quarter of 2009.

The decreases in volumes were primarily related to less gas being transported to to reduce arbitrage opportunities between various pipelines as a result of tightening price spreads.

Importantly, this arbitrage margin was replaced by our Haynesville projects that came online in 2009.

Drilling in the Haynesville Shale remains strong in and around our LIG system.

We are continuing to work on growth projects to leverage our Haynesville assets by expanding our capacity.

These projects include a new interconnect for deliveries into Tennessee Gas Pipeline that was placed in service in December.

We have also completed the [Leget] compressor station in Duson, Louisiana, which we put into service in November.

This project will allow us to move additional volumes from the Haynesville to serve our industrial markets in Southern Louisiana, displacing higher priced gas bought off of interstate pipelines in the area.

As communicated earlier, we have executed contracts covering the first 30 million cubic feet a day of the phase four Red River expansion of our North LIG system.

This project will be done as a separate project to maximize value, and we expect this gas to be flowing by the year summer of 2010.

In the aggregate, these projects have increased the total firm contracted capacity on the Red River system to approximately 440 million cubic feet a day from a fully contracted, diversified customer base.

As demand develops, we have the ability to add more incremental capacity from the Haynesville Shale and will continue to work on contracting the remaining 115 million cubic feet a day of the 145 million phase four expansion.

In Southern Louisiana we have made great strides to expand and improve our natural gas liquids business, primarily due to operational improvements, increasing liquids prices, and higher processing margins compared with early 2009.

Our fourth-quarter 2009 processing volumes increased 16% from 769,000 mmBTU per day in the third quarter to 892,000 mmBTU per day in the fourth quarter, reflecting restored production.

The largest package was at our Pelican plant, where the plant volumes increased substantially with the completion of repairs in August of 2009 on the Anaconda system.

As part of our plan to expand our liquids business we recently completed two transactions that support our strategy to enhance our assets.

Last October we acquired the Eunice natural gas liquids processing plant and fractionation facility from Phillip Morris for approximately $42 million.

We previously operated the Eunice plant under an operating lease with Phillip Morris.

This transaction allowed us to improve operating efficiencies and increases the profitability of our NGL business immediately.

We increased adjusted cash flow by approximately $12 million per year by eliminating the lease operating expense.

In late December, we acquired the 60-mile intracoastal NGL pipeline from Chevron for approximately $10 million.

The pipeline, which extends from Patterson to Henry in Southern Louisiana, connects the cross-Texas Pelican processing plant and accesses other third-party processing plants in the region.

The intracoastal pipeline is an important link between our Pelican plant and our NGL pipeline system connecting to our Eunice plant and fractionator, as well as our Riverside fractionators.

Owning this type eliminate lease operating expense.

And at the same time we received a long-term dedication of another operator's liquids into our system for fractionation and marketing beginning in 2011.

While these two acquisitions are great financial transactions, they also support our strategy to enhance our natural gas liquids business.

We are encouraged by the prospects for our NGL business in the region as we pursue additional projects that will give our Southern Louisiana assets a greater strategic position and increase our earnings power.

We have several possibilities on the horizon to increase the utilization of these assets.

We see a growing need for fractionation and NGL handling as a result of the lack of fractionation facilities for natural gas liquids produced in the Marcellus and other developing shale plays.

As you can see, the strategic positions of our LIG system in the Haynesville and throughout Louisiana, and our midstream assets on the Gulf Coast provide us with exciting growth prospects.

Our aim is to cultivate and optimize our efforts in the region, capitalizing on our integrated operational advantages in Louisiana so we can make the most of our investment throughout the state.

Before I turn the call over to Bill I want to reiterate that I am extremely pleased with our 2009 successes.

We own some of the most efficiently and effectively operated assets in the domestic midstream business, that are ideally located in the heart of the Barnett and Haynesville Shale plays, two of the most promising gas-producing regions in the United States.

And our integrated midstream assets on the Gulf Coast of Louisiana are situated in the middle of the Southern petrochemical and refinery complex that interconnects with major pipelines and East Coast markets.

Now Bill will discuss our fourth-quarter and full-year 2009 financial results.

Thanks, Barry.

Good morning, everyone.

Thanks for joining us.

As always, in our earnings release we have reconciled certain non-GAAP items to their GAAP equivalents, which we will discuss on the call today.

Please refer to the earnings release for the reconciliation.

As Barry has said, we're very pleased with our results for 2009 and continue to be pleased with the overall progress we have made in executing our business strategy.

As Barry touched on earlier, we have worked hard this past year to reposition our balance sheet for long-term success.

This includes paying down debt with the gross proceeds from over $600 million in asset sales; further paying down debt and delevering with the proceeds from the issuance of $125 million in preferred equity from Blackstone GSO.

This investment not only provides valuable equity capital to us, but gives us a partner with a valuable perspective on the industry and markets and a great potential source of future capital.

Thirdly, we've completed our long-term refinancing with the placement of $725ml in 8-year unsecured notes and a new revolving bank credit facility for $420 million with a four-year maturity.

Giving pro forma effect to our East Texas sale and the issuance of preferred equity that we have just completed, we ended 2009 with a debt-to-EBITDA well below 5X, and we expect to keep delevering further during 2010.

Our refinancing elimintated the restrictions on distributions and capital expendtitures that resulted from our amendment in 2009, and pushes our nearest debt maturity out to 2013.

We now have more than $200 million of liquidity available.

I want to clarify that when we talk about debt-to-EBITDA, we talk about debt-to-EBITDA from continuing operations only, not including the assets that we have sold in our EBITDA.

We realized adjusted cash flow during the year of $203.8 million compared with $245 million in 2008.

The majority of the difference between the years was related to discontinued operations from the sale of assets during 2009.

On a same-store basis, adjusted cash flow from continuing operations is $163.6 million in 2008 compared to $158.7 million in 2009.

The fourth quarter of 2009 and the four-year results are impacted by the $3.7 million charge associated with the final arbitration ruling, which was received last week.

We are proud that our continuing operations achieved 2009 cash flows consistent with 2008, particularly given the flattening of basis, which has eliminated our arbitrage margins, and the tighter processing and percentage of liquids margins that we had, given the much lower average NGL prices during 2009 compared to 2008.

The loss of arbitrage also accounts for the fact that, despite our growth in the Haynesville, the LIG volumes look relatively flat over the periods.

The proportion of adjusted cash flow that is sensitive to commodity prices also continues to decline due to the asset sales and due to contract renegotiations.

For the year ended 2009, approximately 80% of the Partnership's continuing operations gross margin came from either gathering and transmission business or fixed fee processing, which is not since sensitive to commodity prices, compared to about 70% in 2008.

So a much higher percentage of our margins now are not directly commodity exposed.

Adjusted cash flow for the fourth quarter of 2009 was $42.3 million compared with $61.3 million in the fourth quarter of 2008.

$18.3 million of the difference is related to assets sold that were in the fourth-quarter 2008 adjusted cash flow figures.

In addition, fourth-quarter 2008 adjusted cash flow was positively impacted by other income of $20 million associated with the assignment of certain contract rights to a nonaffiliated third-party area.

To offset these in 2009 we have seen higher firm transport volumes and margins in the Haynesville and better processing quarter-over-quarter, although for the year in total processing was not as strong.

Gross margin from continuing operations for the fourth quarter of 2009 increased to $80.6 million compared with $65.2 million in the fourth quarter of 2008.

As I just mentioned, processing has been relatively good recently, with a strong weighted average natural gas liquids price of $1.03 per gallon and a natural gas liquids to gas ratio of 280% during the fourth quarter of 2009.

As you probably know, processing margins during the first couple of months of 2010 have also remained good.

Finally, the Partnership has benefited from the new fee-based volumes and margin expansions from our Haynesville projects in the Northlake system.

A key element of our strategic business plan has been to focus on reducing operating expenses.

Fourth-quarter 2009 operating expenses from continuing operations decreased $6.4 million from the expenses in the fourth quarter of 2008.

Our operations teams have done a great year -- have had a great year focusing on efficiency gains.

Depreciation and amortization expense increased slightly in the fourth quarter compared with the fourth quarter of 2008 due to the Partnership's investments in North Texas and Louisiana assets.

Interest expense declined to $28 million in the fourth quarter of 2009 from $41 million in the fourth quarter of 2008, the result of debt reduction associated with our asset sales.

We have also continued to add to our commodity hedge position for 2010, hedging our percentage of liquids contracts and our processing margin contracts, the two types of contracts which give us commodity exposure.

For 2010 we have currently hedged about 70% of our hedgeable volumes for our percentage of liquids contracts, and approximately 60% of our hedgeable volumes for our processing margin contracts.

We are continuing to evaluate hedging opportunities for 2010 and 2011, but feel we're fairly fully hedged now in 2010.

We currently do not have any 2011 volumes hedged, as liquids pricing in the forward curve seems low relative to crude prices.

We've never used a proxy hedge, only specific product hedges.

As an aside, while we are focused on liquids I will just note a name change in one of our income statement captions.

The line item that was previously labeled Energy Trading Activities, which made many people think we were engaged in trading, has been changed.

The label flowed from the fact that most of the margin in that line item historically was derived ide from our off-system marketing on behalf of producers.

Now the line item is mostly made up of margins derived from our NGL marketing business, so we now call it NGL and Gas Marketing to better reflect what it is.

Turning briefly to Crosstex Energy, Inc., the Corporation had a year-end cash balance of approximately $10 million which was reduced to approximately $7 million from the GP, General Partner, match on the GSO/Blackstone investment.

For 2010, we've provided preliminary high and low guidance based on a range of commodity pricing assumptions.

We are forecasting 2010 adjusted cash flow in a range from $160 million to $190 million, and associated distributable cash flow in a range of $62 million to $96 million.

This guidance brings the potential for distributions into sight.

The Partnership has established financial guidelines that will govern its considerations of any future distribution payments, including reducing debt to EBITDA from continuing operations to a ratio of less than 4.5-to-1, pro forma for the payment of a distribution, maintaining strong coverage of the distribution from cash flow to allow us to continue to delever, as well as maintaining a positive outlook on the business prospects for the future.

Assuming actual results are within the range of guidance, the Partnership expects it could generate sufficient distributable cash flow to pay up to $0.30 per unit in distributions relating to the fourth quarter of 2010 with strong coverage; and the Corporation expects it could pay up $0.10 per share in dividends, assuming the receipt of the $0.30 per unit distribution from the Partnership.

There are a number of variables, particularly around our financial guidelines, that could affect the timing of a restart of the distribution and the dividend.

And of course, the payment and amount of any distribution and dividend will be subject to approval by the respective Board of Directors and to economic conditions and other factors existing at the time of determination.

But we're pleased to be able to see it coming.

In our guidance we are assuming our weighted average liquids price will be between $0.80 and $1.09 per gallon, implying a crude price of between $69 and $94 per barrel.

We are also assuming average Henry Hub prices of between $5 and $6 per mmBTU, which implies a natural gas to liquids ratio of between 150% and 245% for the period.

The guidance also assumes growth capital between $25 million and $30 million, and maintenance capital between $12 million and $15 million.

The growth capital estimate currently includes only projects that have been approved by the Partnership.

However, we believe there will be additional bolt-on project opportunities that we are currently studying that could increase the growth capital up to $100 million, a level consistent with our 2009 capital spending.

We are evaluating several additional high-return capacity additions in the Haynesville and in North Texas, as well as several great projects associated with our NGL and processing business.

As previously mentioned, our decisions regarding financing capital investment, as well as those on distributions, will be guided by our financial guidelines.

In 2010, we expect our focus to remain largely around our existing footprint as we begin to evaluate the next phase of growth.

We will provide additional color on this guidance in our conference for the buy-side and sell-side analyst community on March 31 and April 1.

If you are part of this group, you should have received an e-mail notice of this meeting by now.

If you haven't, please contact us to get the details.

This meeting will be webcast so the general public will also have access to our discussions.

Now I will turn the call back to Barry.

Thank you, Bill.

During 2009 we successfully addressed the challenges head on; and as a result we are in a stronger position today.

We worked diligently, decisively, and prudently to execute our business plan.

We built on our strengths, proved we are resilient, and turned the Company around.

We optimized our asset base, reduced costs, lowered business risks, and focused on the most rewarding growth projects while maintaining strong customer relationships.

I am extremely happy with our achievements and believe 2010 will be a year of opportunities for Crosstex.

Today we are a stronger, revitalized Company.

And with the continued commitment from our dedicated employees we are in an excellent position to capitalize on the operational performance of our assets and create value for our shareholders.

With this sound foundation in place, we are optimistic about our future success in 2010 and beyond.

With that, I would like to turn the call back to our operator, Janeda; and Bill and I will be happy to take your questions.

(Operator Instructions) Darren Horowitz, Raymond James.

Good morning, guys.

Congratulations on the quarter.

Thanks, Darren.

Thank you, Darren.

A couple quick questions for you.

First, Barry, from an operational perspective in North Texas, can you quantify the sequential gathering decline into the first quarter due to that compression outage that you mentioned?

Also, when you talk with producers about volume growth, can you give us a sense for how much is coming from previously drilled wells that are currently being hooked up, and also incremental capital that is spent through the drill-bit?

You bet.

Darren, first of all, let me just broaden the question if you will, a little bit and say that while we have seen the slight decline in the fourth, and we have given an indication of the slight decline into the first quarter as a result of the compressor outage, we still believe that flat to slightly up is our outlook for 2010 in North Texas.

Clearly we've seen slowing, a slowdown in the drilling as the challenges of 2008 led into 2009.

That has certainly heightened your focus and all of our focus on volume fluctuations in this area.

But I want to say that our view is that production around our system is still essentially flat, with increases coming into view in the next couple of quarters as producers do bring us the gas that they have developed, both from wells that have been previously drilled and awaiting completion and wells that are currently drilling as we see drilling ramp up.

What happens, though, when we see a slowdown like this and a heightened sensitivity is that the everyday changes in the dynamics of the system is even magnified, such that when you see a compressor outage you actually see that volume impact more significantly, as we have here in the fourth quarter and the first quarter.

Let me just say that we have seen some volumes gets redirected.

Where you have multiple interconnects on particular volumes, and you see that get ick directed into a different market, totally because of a netback price scenario that may be a temporary change, we've seen some of that.

I would also point out though that typically this is a lower margin gas because of its optionality.

Therefore, the impact on us is muted.

We did point out, I think, in the script, that we completed a renegotiation with a producer that shifted some gas from our gathering system into our North Texas pipeline.

So you essentially saw a reclassification of that.

Then ultimately as we have indicated, we expect that in the first quarter we will have an impact of 20 to 25 million a day from a compressor outage that we have seen in a major breakdown on one of our gathering systems.

So that is the order of magnitude.

I know it's a long way to get to the answer to your question, but basically 20 to 25 million a day in the first quarter.

And then as we have seen already, we are starting to see some impact of the inventory of wells.

We saw a particular pad that brought on nine or 10 miles at one time and increased production at the rate of 25 million a day or so from a particular pad.

So we still believe we will see additional pad drilling turned on.

And I would say bigger-picture we still believe the Barnett is very bright as we continue to hear feedback from producers on their drilling plans in 2010 and 2011.

Sure.

Listening to all the conference calls of the producers operating in that area, one can get very encouraged about 2010 and beyond with the drilling ramp up.

When you talk to the folks at Devon and elsewhere, do you get the sense that the inventory of wells that could be hooked up this year could be north of 100?

We really don't have a number at this point, Darren, that we would communicate.

Because it is just so hard for us to see behind our systems.

Where we have central delivery points, it's difficult for us to see just how many wells could come online.

I think you have probably seen the number that has been communicated by the industry, that there could be as many as 600 to 700 wells.

As I said earlier, we believe we are exposed to as many as 50% of the wells in the major core operating area.

So I think that I would say that we are exposed to a lot of those wells that are in inventory.

And at this point that's probably not an unreasonable expectation that you would see something in the 50 to 100 million -- or 100 wells that could be connected to our system throughout the year.

Okay.

Switching gears just quickly over to the LIG system, can you tell us where LIG throughput is today?

And also just to touch on the reduced arbitrage opportunities that impacted volumes, if that continues, can you give us your expectations for what volume targets are reflected in your full-year '10 guidance?

The volume in our 2010 guidance is pretty consistent with what we saw in the fourth quarter.

We will have the 130 million a day project that we are currently constructing come into play early in the third quarter; that will be additive.

We have no arbitrage volumes in the guidance, no arbitrage margin in the guidance.

We have very little in the way of IT margin in the guidance, and very nominal IT volumes in the guidance.

So really most of what we've got in the guidance is around our FT volumes; it's around our key markets in south Louisiana and our key on-system Southern Louisiana producers.

So very little that is optional.

Okay.

The main optionality that you see is just with the range of commodity price assumptions.

Sure.

Then final question, south Louisiana, when you think about upsizing your capital budget to as much as $100 million, as you detailed, Barry, can you give us a little more color on the Gulf Coast potential?

It would appear that fractionation capacity additions would certainly be the most needed, as would storage facilities and associated interconnect.

But you've got the Eunice plant there that I think has some organic optionality to it, and also the intercoastal pipeline benefit.

So can you just give us a little bit more insight?

You bet.

Yes, again, we have in our plans $25 million to $30 million of growth CapEx with an expectation that we would be much closer to $100 million of investment, similar to what we were in 2009.

When you look across the three core operating areas we think we will see investment opportunities across all three areas.

I think the largest of that likely from an investment standpoint would come in the Haynesville.

However, the largest from a returns standpoint could be in our Gulf Coast NGL processing business.

The reason there is that we have got unutilized assets that we expect to increase the utilization without significant capital expenditures.

So I think it will see its share or some amount of the investment in 2010; but I think more importantly we will see significant earnings opportunity as we increase utilization on those asset in significant disproportion, if you will, to the capital investment.

Thanks, guys.

I appreciate it.

Sharon Lui, Wells Fargo.

Hi, good morning.

I guess going back to North Texas, Devon had indicated drilling plans of maybe 370 walls this year.

Just wondering if you have a sense of -- I guess a percentage of these wells being tied to your gathering system.

Yes, we do.

Their base plans call for about 10% of that drilling to be on our acreage.

However as they have indicated, as they complete their disposition of the international and offshore business, that they will redirect capital into the Barnett and Haynesville.

And we don't have a sense of what that will mean on our acreage when they do that.

Okay.

I guess in terms of your volume assumptions, should we assume that for south Louisiana you are assuming relatively flat?

Yes.

Okay, and then looking at the --?

Sharon, let me clarify.

Flat from the fourth quarter.

Flat from the fourth quarter?

Yes, okay.

Right.

I guess looking at the level that you can reinstate the distribution at and the timing, are you still targeting a coverage ratio around 1.3?

Of at least 1.3 times?

Well, It's going to be a function, Sharon, of where those cash flows are coming from, what type of business.

To the extent it is coming from the FT type long-term contracting contracted business It would be relatively tighter.

To the extent it is coming from commodity exposed business, it would be higher.

But given our current mix where we are today, yes, 1.3 is probably not a bad level to be thinking about.

Okay.

Then I guess lastly, can you just give us an update on what your current debt balance and liquidity is?

Yes, we've got liquidity right now of about $215 million on our revolver.

Our total debt balance we've got the -- I will just have to do it in pieces.

We have got about -- we have got the $725 million of new senior notes.

We've got about $25 million drawn on our revolver right now.

We've got $18 million associated with the Eunice acquisition outstanding.

And we've got about $24 million of capitalized leases on compressors that show up as debt.

So doing that in my head it comes to almost $800 million, I guess.

Okay.

I'm sorry, just one more.

When you look at XTXI, how should we think about the withholding for taxes?

We will continue as we pay the distribution to hold back some cash for taxes, although we don't anticipate that XTXI will have any significant cash taxes in the near term.

We will have about $1.2 million of AMT payment coming due this month, alternative minimum tax.

And we probably will have a similar payment in 2011 to make.

But don't expect any significant income taxes in the near term for XTXI.

Okay.

So I would continue to assume that we will hold back something on the order of 20% for the payment of taxes.

Okay, great.

Thank you.

(Operator Instructions) John Edwards, Morgan Keegan.

Yes, good morning, everybody.

Just on your proposed distribution restart, you are saying up to $0.30 a unit.

I am just trying to get a sense here.

If you're at the high end of your guidance, do you expect to be at that $0.30?

And if you are at the low end, where do you expect to be?

That is going to depend, John -- this is Bill, good morning -- just on factors around where we are on a total leverage basis and so forth.

But certainly it will be variable within that range.

$0.30 just sort of seems to be in the center of the radar of where we think we would be, in that range.

We have not tried to quantify either side of it.

Okay.

All right.

Then what was the total debt at the end of the year, 12/31/09, with all the restructuring and so on?

We need to check our math for our model.

Well, our 10-K is on file now and that is in the filing.

If you give me a minute to check some data here, it was the same order of magnitude as I just recapped for Sharon, with the difference being that in our refinancing we paid about $27 million to buy out the interest rate swaps that we had in place.

And in addition we had the fees associated with the refinancing itself, which were order of magnitude probably all-in $20 million, $25 million as well.

So the refinancing itself created some new debt, but that's probably the difference, if you're looking to try to recalculate where you are.

Okay, all right.

And I will just refer you to the 10-K that is currently on file to get the exact numbers.

All right.

I hadn't seen it yet.

Okay.

Then as far as the interest expense then, so with this $800 million or so, that would roughly calculate at around 10%.

But that seems a bit high.

So what else is in your interest expense guidance?

Well, the main component of the interest expense is the $725 million of 9.25% debt that is outstanding.

In addition, you've got the amortization of the deferred financing cost, which is basically the fees that I mentioned that will be amortized into interest expense over the course of the life of the debt.

Okay.

So it's a cash charge that we've already paid; but it will be a component of interest expense.

Okay.

All right.

Okay, so just to clarify then I guess Darren, then Sharon's question for Louisiana volumes.

You're expecting this year to be relatively flat versus fourth quarter of '09.

Is that correct?

Yes, yes.

Okay.

But that is before the consideration of any of the projects that Barry mentioned that we don't have in the capital budget right now.

Okay.

So you are looking at -- your CapEx guidance of $25 million to $30 million is really more of a minimum number.

You could end up closer to $100 million for the year if things work out well?

We expect to end up closer to $100 million, but we just don't have those projects finally approved and in our cash flow numbers at this point in time.

Okay, great.

All right.

Well, thank you very much.

You bet.

At this time there are no further questions.

I would now like to turn the call back over to Barry Davis for any closing remarks.

Thank you, Janeda.

I just want to thank you guys for being on the call today.

And most importantly I want to thank you for your patience and your support over the last 18 months as we have battled through these challenges and getting to a point where we can deliver good news as we have here in the fourth quarter and for the year 2009.

A defining point for our Company, and we again really appreciate your support and interest and look forward to continuing to provide good results as we pursue opportunities in 2010.

Have a great day and a great week, and we will talk to you soon.

Ladies and gentlemen, that concludes today's conference.

Thank you for your participation.

You may now disconnect.

Have a great day.