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Targa Resources Partners LP (NYSE:NGLS)

Q1 2010 Earnings Call Transcript

May 5, 2010 10:00 am ET

Executives

Anthony Riley – Senior Manager, Finance/IR

Rene Joyce – CEO

Jeff McParland – EVP and CFO

Matt Meloy – VP of Finance and Treasurer

Analysts

Emily Wang – Raymond James

Lenny Brecken – Brecken Capital

Michael Blum – Wells Fargo

John Tysseland – Citi

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the Targa Resources Partners first quarter 2010 conference call on the 5th of May, 2010. Throughout, today's recorded presentation all participants will be in a listen-only mode. After the presentation there will be an opportunity to ask questions. (Operator Instructions)

I will now hand the conference over to Anthony Riley. Thank you, sir. Please go ahead.

Anthony Riley

Thank you, operator. Good morning, everyone. I'm Anthony Riley and I would like to welcome you to Targa Resources Partners LP's first quarter 2010 investor call. Before we get started I would like to mention that the Partnership has published an earnings release, which is available on our website, TargaResources.com.

Speaking on the call today will be Rene Joyce, Chief Executive Officer; and Jeff McParland, Executive Vice President and Chief Financial Officer. Rene and Jeff are going to be comparing the first quarter of 2010 results to prior-period results, as well as providing additional color on our results, current performance and other matters of interest.

Before we begin, I would like to remind you that this call contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 as amended and Section 21E of the Exchange Act of 1934 as amended. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions.

The future results of Targa Resources Partners LP may differ materially from those expressed from the forward-looking statements contained within this call. Many of the factors that will determine these results and values are beyond our ability to control or predict. These statements are necessarily based upon various assumptions involving judgments with respect to the future, including, among other things, weather, political, economic and market conditions, timing and success of business development efforts and other uncertainties. You are cautioned not to put undue reliance on any forward-looking statements.

One quick reminder before starting into the results, since the Downstream Business and the Partnership are entities under common control, the accounting treatment provides that the Partnership's reported results of operations now include the historical results of the Downstream Business for all periods presented. Please note that the first quarter 2010 and prior-period results discussed today do not include the results of the recently closed dropdown transaction.

With that, I will turn it over to Rene Joyce, our Chief Executive Officer.

Rene Joyce

Thanks, Anthony. Good morning and thanks to everyone for participating in Targa Resources Partner's first quarter 2010 conference call. Besides Jeff and myself, there are several members of management who will be able to assist in the Q&A session.

By way of agenda, I will start off with a review of our key accomplishments and business highlights followed by segment performance overview for the quarter. I will then turn it over to Jeff to review our consolidated financial results, detailed segment performance and other financial matters. Following Jeff's comments I'll provide updates on some ongoing activities at the partnership and finally we will take your questions.

First quarter 2010 adjusted EBITDA fully met our expectations and it was flat compared to the first quarter of last year. For a number of reasons, many of which we have discussed on previous calls and in press releases, first quarter 2010 was lower than the fourth quarter of '09.

We reported a distributable cash flow of $44 million, which corresponds to distribution coverage of a little over $1.1 for the quarter. First quarter performance was affected by several items, including weather and plant turnarounds.

In the marketing segments of the Downstream Business, early winter weather accelerated certain sales volumes and margin into the fourth quarter of '09 at the expense of the first quarter.

In the logistics asset segment we had plant turnarounds in several facilities and experienced lower nominative volumes under certain contracts that have commitments, which we expect to be satisfied over the remainder of 2010.

We are pleased to have recently closed the accretive acquisition of the West Texas assets and Coastal Straddle plants, which continues our stated strategy of seeking attractive and strategic acquisitions for the partnership, including businesses and assets from Targa.

The most recently transaction has enhanced our presence in the Permian Basin, increased the partnership scale and geographic diversity and should continue to position a partnership for future growth.

As we indicated when we announced the transaction, based on the recent performance of the dropdown and of the existing businesses of the partnership, management expects to recommend to the Board, following the second quarter, a $0.04 increase in the annual distribution rate to $2.11 per common unit from the current rate of $2.07.

The second quarter distribution declaration, including this increase if approved by the Board, is expected to be made in July 2010 and paid in August, so that the increase will take effect for the quarter. That includes the acquisition closing.

Turning to the segment level, I will first summarize the quarter's performance in our gathering and processing segment. First quarter 2010 plant inlet – natural gas inlet for the combined North Texas, San Angelo and Louisiana systems was 479 million cubic feet per day, an increase of approximately 17% compared to the same period in '09. The 17% increase year-over-year was driven primarily by a 52% increase and inlet at the Louisiana system somewhat offset by a 1% decrease at North Texas.

The increase at the LOU system was driven primarily by the addition of discretionary volumes somewhat offset by lower wellhead volumes. The slight decrease at North Texas is due to cold weather and the settlement of a contract dispute with a counterparty that provides for their ability to substitute the amount of physical volumes available to us for plant processing with a payment of the economic equivalent, both somewhat offset by new well connects.

Overall, our margin, after adjusting for hedge charges was just a little lower in the first quarter compared to last year due to lower hedge prices and volumes somewhat offset by higher unhedged market prices.

On a sequential basis, first quarter plant natural gas inlet for the combined systems increased 5% compared to the fourth quarter of '09 driven by increases at all three systems. The 5% North Texas increase over the fourth quarter is the net result of new well connects and milder temperatures in the first quarter offset by well declines.

The 2% San Angelo increase is primarily the result of more well connect activity, partially offset by colder ambient temperatures. The 6% LOU increase is primarily the result of higher discretionary volumes, somewhat offset by lower wellhead volumes. Despite the volume increases, first quarter operating margin was a little lower than the fourth quarter, again, primarily a function of hedges rolling off.

Next, I'll provide an overview for the three segments in the downstream business. Starting with a logistics asset segment, fractionation volumes for the first quarter of this year increased by 20,000 barrels per day or 10% to 210,000 barrels a day compared to 190,000 barrels a day a year ago.

The increase was driven primarily by higher volumes at Lake Charles fractionator resulting from NGL supply recovery from the impacts of the '08 hurricane season that affected '09 volumes, somewhat offset by lower CBF volumes.

CBF volumes at Bellevue decreased due to the negative effects of cold winter conditions on producing area NGL production during the quarter. First quarter operating margin in the logistics asset segment was more than 60% higher than last year, primarily due to the higher fixed portion of fractionation fees.

In the NGL distribution and marketing segment, NGL sales volumes for the quarter decreased by 32,000 barrels a day or 13% compared to '09. This decrease was driven primarily by the renegotiation of the contract with a major customer, which resulted in lower sales volumes while contract profitability was largely unchanged.

First quarter profitability in the NGL distribution and marketing segment was lower relative to '09, but this comparison is distorted by the impacts of unique lower of cost-to-market inventory adjustments in '08 that benefited the first quarter of '09.

In the wholesale marketing segment, NGL sales volumes for the quarter decreased by 1,000 barrels a day or 1% compared to '09 with the decrease driven primarily by lower refinery service volumes somewhat offset by higher wholesale propane volumes.

With slightly lower volumes and improved margins, first quarter wholesale operating margin was better than last year, although the first quarter of '09 was impacted by lower of cost or market inventory adjustments.

That wraps up my review, so I'll turn it over to Jeff to give you more details on our consolidated and segment financial performance.

Jeff McParland

Thanks, Rene. I'd like to add my welcome and thank you for joining our call today.

One reminder, as Anthony mentioned, under the common control accounting treatment, the Partnership's reported results of operation now include the historical results of the Downstream Business for all periods presented.

For the first quarter of 2010 the Partnership reported net income of $12.6 million or $0.14 per diluted limited partner unit, compared to a net loss of $5.3 million or a $0.09 loss per unit for the first quarter of '09. These quarterly results include non-cash hedge charges of $7.6 million in 2010 and $18.4 million in 2009.

Please also note that the net loss reported for the first quarter of 2009 included $14.8 million and interest expense from affiliates that was related to the downstream business for periods prior to its acquisition for the partnership.

Adjusted EBITDA for the quarter declined slightly to $62.4 million compared to $62.6 million. The decrease was primarily a result of lower operating margin in our natural gas gathering and processing segment before non-cash hedge amounts and of increases in other charges somewhat offset by an increase in operating margin for the downstream business compared to 2009.

Operating expenses increased by $3.7 million or 8% to $56 – $52.6 million for 2010 compared to $48.9 million for 2009, driven primarily by higher fuel and power costs due to higher natural gas prices and usage in the logistics asset segment. General and administrative expense increased slightly by $400,000 or 2% to $16.5 million for 2010.

Net interest expense for the quarter, excluding interest on affiliate indebtedness was approximately $15 million or about $6 million higher than 2009, primarily due to the issuance of our 11.25% notes. Maintenance capital expenditures were $3.7 million for the first quarter of 2010.

Let's take a look at segment operating margin results for the first quarter of this year compared to both the first and the fourth quarters of last year. Starting with the gathering and processing segment, first quarter 2010 operating margin was $40.8 million, compared to $31.6 million a year ago with the volume improvement, as Rene mentioned, entirely due to the LOU system discretionary volumes.

The $9.2 million operating margin increase was driven primarily by lower non-cash hedge charges of $7.6 million in 2010 compared to $18.4 million in 2009. After adjusting for the impacts of these non-cash hedge charges, first quarter 2010 operating margin would be $48.4 million compared to $50 million a year ago. The increase is primarily due to lower hedge volumes and prices, somewhat offset by higher average commodity prices.

First quarter average realized prices for natural gas, NGLs and condensate increased 15%, 79% and 83% respectively compared to last year. Compared to the fourth quarter of last year, first quarter operating margin declined $6.6 million or 14%. After adjusting for the impacts of non-cash hedge charges, first quarter 2010 operating margin was $48.4 million compared to $51.2 million for the fourth quarter.

This decrease was driven primarily by lower hedged volumes and prices, somewhat offset by higher average commodity prices and some volume improvement in the first quarter of 2010. Realized prices for natural gas NGLs and condensate increased 21%, 8% and 24% respectively, compared to the fourth quarter.

In the logistics asset segment, first quarter 2010 operating margin was $14.7 million compared to $9.1 million a year ago. The $5.6 million or 62% increase was driven primarily by the higher fixed portion of fractionation fees at Cedar Bayou fractionators or CBF and by higher fractionation volumes and associated fees at Lake Charles, Louisiana.

The volume improvement is due, in part to NGL supply recovery from the impacts of the 2008 hurricane season on 2009 production. These positive effects were somewhat offset by higher operating expenses this year.

Compared to the fourth quarter of 2009, first quarter operating margin declined by $14 million or 49% to $15 million. Fourth quarter results benefited from year-end reservation payments from customers on certain contracts, as well as higher fractionation and LSNG utilization.

Creating volumes at the LSNG unit for the first quarter was significantly lower compared to the fourth quarter due primarily to a customer turnaround. Planned maintenance and turnaround activity and higher fuel costs during 2010 also contributed to this sequential decrease.

In the NGL distribution and marketing segment, first quarter 2010 operating margin decreased by $5 million or 34% to $9.6 million compared to last year. First quarter 2009 results benefited from lower cost or market inventory adjustment taken in 2008.

Average realized prices increased 89% to $1.15 per gallon in 2010 compared to $0.61 per gallon in 2009. Compared to the fourth quarter of 2009, first quarter operating margin declined $4 million or 41%, driven primarily by lower LPG export sales and third-party marketing margins.

In the wholesale marketing segment, first quarter 2010 operating margin showed an increase of $2.5 million or 58% compared to last year driven primarily by lower cost of market inventory adjustments in last year's first quarter. Average realized prices increased by 50% to $1.41 per gallon for 2009 from $0.94 per gallon last year.

Compared to the fourth quarter of 2009, first quarter operating margin declined $6 million or 47% driven primarily by the acceleration of some sales volumes and margin into the fourth quarter of 2009 at the expense of the first quarter of 2010 in response to earlier than normal winter weather in the West. These negative effects were somewhat offset by higher wholesale propane volumes resulting from strong demand in some regions.

Now let's move briefly to capital structure, liquidity and hedging. At March 31st, we had approximately $564 million in capacity available under our senior secured revolving credit facility after giving effect to outstanding borrowings of $318 million, $77 million in letters of credit and a reduction in borrowing capacity as a result of the Lehman default.

We also had $66 million of cash on hand, bringing total liquidity at quarter end to approximately $630 million. Total funded debt at March 31 was approximately $747 million or about 43% of total capitalization. Our consolidated leverage ratio at quarter-end was approximately 2.6 times.

On January 19, 2010, we completed the public offering of 6.3 million common units at a price of $23.14 per common unit. Net proceeds of $140 million were applied to repay a portion of the outstanding borrowings under our revolving credit facility.

Last week on April 27 we closed the acquisition from Targa of the West Texas assets and Coastal Straddle plants. Total consideration paid to Targa was $420 million in cash, funded entirely through borrowings under the Partnership's revolver.

Pro forma for the closing of the transaction, the Partnership's liquidity as of March 31, 2010 was approximately $170 million. A wrap-up with CapEx and hedging and then turn the call back to Rene.

Including the businesses we acquired last week, our estimated 2010 capital expenditures are approximately $145 million, with maintenance capital expenditures accounting for approximately 25% of that amount.

With respect to hedging our equity volumes within the natural gas gathered in the processing segment, we estimate that as we stand today we have hedged approximately 80% of our equity volumes of natural gas and have combined NGLs and condensate for 2010. These estimates include equity volumes and hedges associated with West Texas assets that we've just acquired.

That wraps up the financial overview, so now back to Rene.

Rene Joyce

Thanks, Jeff. I'd like to quickly provide an update on the 78,000 barrel a day fractionation expansion at Cedar Bayou fractionators. We're still on track to commence operations no later than the second quarter of next year. We have started mobilizing construction equipment onsite and have ordered all long-lead time equipment.

Regarding our volume outlook for the gathering and processing segment based on information available to date, we believe 2010 North Texas volumes will remain close to those of '09. San Angelo volume should exceed those of '09. And total 2010 Louisiana inlet volume should exceed those of '09 based on the current frac spread projections for this year.

For the recently acquired assets, this year's volume outlook has not changed since our press release update. We believe inlet volumes at both the West Texas assets and Coastal Straddle plants will exceed those above '09.

We are very pleased with the addition of both of these new gathering and processing systems into the Partnership. Our Permian presence is greatly enhanced. This is important given all the crude based drilling and work over activity we see in the Permian Basin. And of course this crude-based activity provides us with high GPM associated gas.

The Coastal Straddle plants provide a scaled position in the Gulf of Mexico where we represent one of the largest processors of offshore Gulf of Mexico production. Given the outlook for NGLs and natural gas, we believe these assets are well positioned to benefit given their contract mix consistent primarily of hybrid contracts, which have been settling as a percent of liquids and remaining Keppel [ph] percent of liquids and fee-based contracts.

As previously discussed, Targa has indicated to the partnership that it plans to engage the partnership in discussions and due diligence regarding a potential purchase by the partnership of the remaining businesses at Targa sometime during the second quarter of this year.

These businesses include Targa's joint venture interest in the Versado assets in the Permian Basin and the VESCO gathering and processing systems at the mouth of the Mississippi River. If terms can be reached, a closing of this final dropdown could occur before year-end.

With that, I'll conclude by saying that we continue to actively pursue new fee-based investment opportunities, potential opportunities for fee-based gathering assets in one of the shale plays as well as additional expansion opportunities within our Downstream Business.

That concludes the formal part of the call. We will now open it up for your questions.

Question-and-Answer Session

Operator

Thank you, sir. (Operator Instructions) And the first question today comes from Emily Wang from Raymond James. Please go ahead with your question.

Emily Wang – Raymond James

Hi. Good morning, guys.

Jeff McParland

Hi, Emily.

Rene Joyce

Good morning.

Emily Wang – Raymond James

Can you guys just comment on your EBITDA guidance? I know in early April you guys came out with $310 million to $330 million of guidance and that was based on an April 1 acquisition close. Given that it closed almost a month later, can you guys kind of provide updated guidance on that.

Matt Meloy

Sure, Emily. This is Matt. In terms of timing of the close, it did close on April 27, but the effective date is still going to be April 1. So the dropdown asset will be included in the results starting with April 1. So it'll be in the results for the full second quarter when we report that after the quarter end.

You know, as far as, you know, continuing guidance, you know, we gave that guidance as kind of a one-time deal and we had closed the dropdown acquisition and we're talking about closing, you know, the newly acquired assets, the Straddle and the Permian business.

You know, there were a lot of moving parts, so we wanted to provide some clarity out there for investors. So it's not something that we expect to update continually.

Emily Wang – Raymond James

Great. Okay. Thanks for the clarification on that. And could you guys kind of comment, you know, with these new assets in your system, what would be the average NGL content, say, on a GPM basis with, you know, West Texas and your legacy assets?

Rene Joyce

Yes. The GPM content and the Sand Hills is not much different than what you see at the San Angelo system, somewhere, I would say, close to 6 GPM or recoverable GPM. The Straddle plant business is typical of the kind of quality of gas you see from the Gulf of Mexico with that GPM being under 2G – recoverable GPM being under two.

Emily Wang – Raymond James

Okay. So, I guess, on an average basis could you kind of assume something between, you know, 2.5 to 3?

Rene Joyce

Well, with the Sand Hill system you're dealing with a volume that's around 120 million cubic feet a day and with the offshore systems well over 1 billion cubic feet a day. So, I mean, you could take those numbers and come up with your blend.

Emily Wang – Raymond James

Well, all right. I guess including everything else with LOU and Angelo and everything else?

Rene Joyce

I don't think we have a system-wide GPM number readily available.

Jeff McParland

You have to look at it by system. I think if you look at what we've said about LOU, given the discretionary volumes, the GPM mix there isn't entirely different than what you're going to see from there.

Rene Joyce

Yes.

Jeff McParland

North Texas GPM recoverable is a little bit less.

Rene Joyce

Yes, North Texas GPM recoverable is somewhere around 4.8. You're dealing with closer to 6 at San Angelo and Sand Hills. And you're dealing with under 2 for both the LOU system because that's primarily processing discretionary gas off offshore pipelines. And so that's just the rough mix.

Emily Wang – Raymond James

Okay. Great. And then final question is bigger picture. You know, after, say the final dropdown and you guys start looking at more organic opportunities or perhaps more acquisitive third-party opportunities, what sort of shale regions would you guys kind of focus on or, you know, business lines? Would it be more gathering and processing or maybe more kind of a frac expansion?

Rene Joyce

Well, I don't think we'd be going in a frac expansion. With 78,000 barrels is probably all we'll be doing in Mount Bellevue. Although there are a number of fee-based projects around the liquids business, such as an upgrade to the LSNG unit, potential, you know, major connections to provide outlets for our projects at Bellevue plus import and export opportunities around LPGs at our Galena Park facility. All those that are projects we're working on.

We have been actively involved in a number of projects, potential projects in the shale plans – Painesville, Marcellus and Eagle Ford. Unfortunately, we haven't had a project to announce to date. We're still actively engaged in a number of projects. I think one of the benefits we have in a Marcellus is our wholesale propane terminals in the region that could help with liquid solutions in that area, plus our expertise on the gathering and processing side. But we're still actively engaged in a number of projects in the shale plays.

Emily Wang – Raymond James & Associates

Okay. Great. Thank you so much.

Operator

Thank you. And the next question comes from Lenny Brecken from Brecken Capital. Please go ahead with your question. Lenny Brecken, your line is open.

Lenny Brecken – Brecken Capital

I have three questions. Just regarding– if you look at the overall market for NGL and its– you know, and its components to be exported, can you just give us an update given the rise in the dollar, any recent trends on ethane prices or anything to give us comfort that the demand is still holding up?

Rene Joyce

Well, the– on the petrochemical side, even though the first quarter, first full month this year was plagued with a number of planned and not scheduled plant shutdowns from the petrochemical side of the business, utilization or operational rates have remained pretty high in the upper 80% and I think a lot of that is still driven by export opportunity. So, you know, even though ethane has fallen off, you know, somewhat in the first four months of this year, it's now back up to around $0.58, $0.59 a gallon. We're still optimistic that ethane will hold up for the remainder of this year as well as the other products.

We have not seen a lot of LPG imports into the Gulf Coast, none, to be exact. In fact, there's been more export opportunities for LPGs rather than import, given the number of issues in that industry around the world. So we're still optimistic about the petrochemical utilization of the lighter end of the barrel for the remainder of this year.

Lenny Brecken – Brecken Capital

Okay. And then just a follow-up on it, can you just give us an update any activity on the hedging side recently, if you can disclose anything? And where do you think your coverage ratio is going to be sequentially? If you can give me some guidance in terms of that.

Jeff McParland

I don't think you'll see us giving guidance of the coverage ratio sequentially. We just talked about what we do infrequently on our guidance. On hedging, no major new disclosures. Our hedging program remains consistent and the only new difference to that hedging program is we aren't hedging out as far on natural gas liquids because we believe that sort of post-three-year discount on financial products is a little more than we want to sign up for.

Rene Joyce

And we recognize that the coverage for the first quarter, for all the reasons we've talked about, was lower than what we've historically had. I wouldn't draw any conclusions about the first quarter. There was just too much noise between the fourth and first quarter and a number of items in the first quarter that will adjust itself out over the remainder of the year.

Lenny Brecken – Brecken Capital

Okay. That's what I wanted to hear and that you weren't panicked on the…

Rene Joyce

No. No. No, no, no. We knew, like I opened in my opening remarks, that we anticipated what the quarter was going to look like based on what we saw occurring in the fourth quarter of last year and the announced turnarounds. So it's not only our turnarounds but also turnarounds that impacted some of our customers, mainly the turnaround on one of our customers at the LSNG units. So none of that– none of what we saw in the first quarter was unexpected.

Lenny Brecken – Brecken Capital

And one last question. The projects that you're working on in the shale area, is that working at the parent level or at the LP level?

Rene Joyce

No. It's not at the parent level. Everything that we're contemplating would be done at the MLT.

Lenny Brecken – Brecken Capital

Okay. Great. Thank you.

Operator

Thank you, sir. And the next question comes from Michael Blum from Wells Fargo. Please go ahead with your question.

Michael Blum – Wells Fargo

Thanks. Good morning, everyone.

Rene Joyce

Good morning, Michael.

Michael Blum – Wells Fargo

Just a couple of quick ones really. One, just a point of clarification, in terms of the remaining assets at the parent, are you saying that you could have an announcement on a potential deal like a deal signed in the second quarter or are you going to start negotiations in the second quarter?

Rene Joyce

No. We're going to start the process with the independent committee and which requires their due diligence and other stuff in the second quarter. And we anticipate it closing before the end of the year.

Michael Blum – Wells Fargo

Okay. Thanks for that. Second question, I think I know the answer but just to make sure. Are you at all impacted particularly with the Straddle plants with the spill in the Gulf?

Rene Joyce

No. There– right now it's occurring east of the Mississippi River and kind of the currents from the river is acting as a natural barrier but, no, none of our operations have been impacted to date. There's the potential that some barge activity between Pascagoula, Galena Park and Florida could be impacted but we believe that would be minor. What we have to see play out is what are the future regulations that will come out of this and how does that impact future Gulf of Mexico drilling activity. We're still very optimistic about the Gulf of Mexico, particularly as an oil producing basin. But we'll just see how– what comes out of this event.

Michael Blum – Wells Fargo

Okay. And then last question is just, you know, it sounds like volumes will be up pretty much across all your systems. Wondering if you're willing to put any kind of numbers around that, just in order of magnitude. Are we talking 1% to 2%, 5%, 10%? Just any kind of – just an aggregate, I guess.

Rene Joyce

No. Up is the best I'd describe it, Michael. And part of the issue is we're definitely going to see a nice increase at San Angelo because we are on record, well hookups and, you know, the other systems are holding their own. But in Louisiana, where we can put on these discretionary volumes and that's solely dependent on the frac spread and the fact that we're going to have a new connection with the Kinder Morgan Pipeline, those volumes can move up and down significantly. So I would just say we – overall the volumes will be up for this year. I'm just not prepared to say what.

Michael Blum – Wells Fargo

Okay. Thank you.

Operator

Thank you. And the next question comes from John Tysseland from Citi. Please go ahead with your question.

John Tysseland – Citi

Hi, guys. Good morning. I guess the – just a couple questions on – general industry questions. When you look at your – across your system, you know, are you pretty – are you surprised by how quickly producers have been able to bring up their production in NGLs and then also do you see any kind of bottlenecks? And are you starting to see producers looking into processing expansions and willing to contract something out with – on any of your systems at this point or do you think you have a sufficient capacity?

Rene Joyce

We have sufficient capacity in all of our systems. We've got, at Sand Hills, about another 30 million a day. San Angelo, we've got a 25-million-a-day plant that's on immediate standby. In North Texas, we've got significant capacity. That's true for Central [ph] Louisiana in our Straddle plant business. So, no, we would not be expanding our processing plants at the current locations. Now, there are situations where we may be building a new plant, one of the shale plays or we could be using one of our spare plants at our location.

The ramp-up in drilling activity is somewhat surprising in the Permian Basin. We knew the activity would be solid a year ago, but the – just the number of rigs moving into that oil play, primarily Wolfcamp and Sprayberry had surprised us. And our record well hookup in San Angelo was in '07, and we have every indication to date that we will exceed that by a wide margin. So I would say the only thing is in the Permian that's kind of surprised us the number of rigs that have moved in, particularly on the acreage dedicated to us.

John Tysseland – Citi

And then also where you do have capacity available on the processing side? Do you have available takeaway capacity for the NGLs once they come out of that unit or is that something that you would need to look at further?

Rene Joyce

We have been looking at that issue because we are bumping up some but we have, I think developed what I would call backup plans or additional options that it should not impact the amount of gas we bring into our systems.

John Tysseland – Citi

And then also at this point are you looking at longer-term fractionation contracts on your systems or how much is rolling off this year on a percentage basis that would come up for re-contracting and potentially all margins?

Rene Joyce

Those contracts come up on a continuous basis, and, you know, we're probably – I would say everything we do on the frac side is going to be done on the long-term contracts at current rates. Spot activity is diminishing over time and the amount of rollover on those contracts this year; I don't even think we have a number.

Operator

(Operator Instructions)

Rene Joyce

Thank you, operator, and to the extent anyone has any follow-up questions, please feel free to contact Jeff or any of us. Thank you again for your time this morning and I look forward to speaking with you again.

Operator

Ladies and gentlemen, this concludes the conference call today. Thank you for participating. You may now disconnect.

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