Targa Resources Corp (TRGP) 2011 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Targa Resources third-quarter 2011 earnings conference call. (Operator Instructions). As a reminder, today's conference is being recorded. I would now like to turn the conference over you to your host for today, Mr. Joe Brass, Director of Finance. Sir, you may begin.

Thank you, operator. I'm Joe Brass and I'd like to welcome everyone to our third-quarter 2011 investor call for both Targa Resources Corp. and Targa Resources Partners LP.

Before we get started, I'd like to mention that Targa Resources Corp., TRC, or the Company, and Targa Resources Partners LP, Targa Resources Partners, or the Partnership, have published their joint earnings release, which is available on our website, www.TargaResources.com. We will also be posting an updated investor presentation to the website after the call.

Speaking on the call today will be Rene Joyce, Chief Executive Officer, and Matt Meloy, Chief Financial Officer and Treasurer. Rene and Matt are going to be comparing the third-quarter 2011 results to prior period results, as well as providing additional color on our results, business performance, and other matters of interest.

Before we begin, I would like to remind you that any statements made during this call that might include the Company's or the Partnership's expectations or predictions should be considered forward-looking statements and are covered by the Safe Harbor provision of the securities act of 1933 and 1934.

Please note that actual results could differ materially from those projected in any forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings, including the Partnership's annual report on Form 10-K for the year ended December 31, 2010, and other quarterly reports on Form 10-Q, as well as the Company's registration statement on Form S-1, as amended.

A quick reminder before we get started into the results. With the closing of multiple acquisitions from TRC over the previous years and in accordance with accounting treatment for entities under common control, the results of operations of the Partnership include the historical results of these businesses for all periods reported.

With that, I will turn it over to Rene Joyce.

Thanks, Joe. Welcome, and thanks to everyone for participating in our third-quarter conference call. Besides Matt and myself, there are several other members of the management team who will be available to assist in the Q&A session.

For today's agenda, I will start off with a high-level review of performance, key accomplishments, and business highlights for the quarter. We'll then turn it over to Matt to review the Partnership's consolidated financial results, segment results, and other financial matters for the Partnership. Matt will also review key financial matters related to Targa Resources Corp. Following Matt's comments, I will provide additional updates on some of our ongoing activities, and we will then take your questions at the end.

You may recall that Targa had a press release on October 19 which provided an update on selected projects and provided some explanation of our financial outlook, given a lot of moving pieces in our businesses. Today's earnings release, the third-quarter 10-Qs, and our current outlook for the business are consistent with the press release.

The Partnership businesses continue to benefit from favorable industry dynamics that are driving growth in natural gas supply and in NGL volumes across our diverse asset base. Year over year, operating margins strengthened in both our natural gas gathering and processing division and our logistics and marketing division.

During the third quarter, the Partnership experienced an unusual set of operational issues, both ours and third parties, impacting financial performance. These issues, many of which were attributed to a much hotter-than-normal summer in our operations areas, have been resolved and are not expected to occur to the extent or to this extent in the future.

The Partnership's fundamentals remain strong, and we expect an EBITDA in the fourth quarter at least as strong as our previously-announced guidance. We reported third-quarter adjusted EBITDA of $107 million, which resulted in distributable cash flow of $65.4 million. Distribution coverage was 1.1 times, based on our third-quarter declared distribution of $0.5825, or $2.33 on an annual basis. The Partnership's distribution represents an 8% increase compared to the third quarter 2010.

Our field gathering and processing segment increased inlet volumes year over year at our San Angelo operating unit in north Texas, driven by very attractive drilling and production activity. Favorable pricing, increased VESCO and Louisiana operating unit inlet volumes, and improved GPM at both business units led to a strong year-over-year performance in our coastal gathering and processing segment.

The resulting increase in NGL production both from our G&P division and from other gas processors who also experienced increased NGLs improved operating activity through our integrated downstream assets and continues to create incremental demand for NGL infrastructure.

For our logistics and marketing division, impressive operating results benefited from increased CBF fractionation volumes, continued strong NGL prices, and LPG export activity. At Galena Park, LPG export activity across our docks continues well above last year's pace. This activity is supported by multiyear deals, as well as spot export opportunities, and these predominantly fee-based arrangements benefit both our logistics assets and our marketing and distribution segments.

Consistent with our strategy of growing our terminals business, we announced purchase of two petroleum logistics terminals, the Targa Sound terminal and the Targa Baltimore terminal. We are currently pursuing incremental growth capital investment at all three of our recently-acquired petroleum logistics terminals.

That is a brief summary of TRP highlights.

At the TRC level, TRC declared a third-quarter cash annualized dividend of $1.23 per share, which was a 19% increase over the annualized rate paid with respect to the pro rated fourth quarter of 2010.

As we will review with you later in today's call, with the level of producer activity across our field gathering and processing operations and with the growth in NGL supplies to Mont Belvieu, we have approved and launched a slate of over $860 million in organic growth projects across our businesses. These projects will come online over the next two years and support high visibility for incremental contributions to operating margin through 2014.

That wraps up my initial review, and I'll hand it over to Matt.

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

As Joe mentioned, under common control accounting treatment, the Partnership's reported results of operations now include all Targa assets for all periods presented.

Let's start with a review of the consolidated results. For the third quarter of 2011, the Partnership reported net income of $35.9 million, compared to $13.8 million for the third quarter of 2010. The income per diluted limited partner unit was $0.31 and $0.14, respectively. These quarterly results reflect non-cash hedge charges of $2 million in 2011 and $6.1 million in 2010.

Under common control accounting, net income reported for the third quarter of 2010 includes $3.9 million of non-cash affiliate interest expense related to dropdown businesses for periods prior to the acquisition of those businesses by the Partnership.

As Rene mentioned, adjusted EBITDA for the quarter was $107 million, compared to $90.5 million for the same period last year. The increase was primarily the result of higher operating margins in both the gathering and processing and the logistics and marketing divisions, partially offset by lower cash hedge settlements, higher general and administrative expenses, and by temporary operational issues previously mentioned.

Gross margin increased 23% for the third quarter, compared to last year. Again, strong performance across both divisions drove the gross margin improvement, and I will review the drivers of this performance in our segment review.

Operating expenses increased 16% compared with last year, primarily due to the increased compensation and benefits, maintenance, fuel, and utilities. The increase in depreciation and amortization expense for the fourth quarter, compared to last year, is primarily attributable to new assets which have been acquired or placed in service since the third quarter of 2010, partially offset by the impacts of assets that have become fully depreciated.

While total interest expense dropped as compared to last year, due to affiliate interest expense, third-party interest expense increased $1.7 million compared to last year, due to the additional debt component of the Partnership funding for multiple dropdown transactions from TRC, several new acquisitions, and other growth capital expenditures. Equity was also raised for these funding requirements and our debt coverage remains at the low end of the targeted range.

Gross maintenance capital expenditures were $24.7 million in the third quarter of 2011, compared to $12.7 million in 2010. Adjusting for the non-controlling interest portion of the maintenance capital expenditures and certain reimbursements from TRC to the Partnership, net maintenance capital expenditures were $16 million in the third quarter of 2011, compared to $10.7 million in 2010.

Turning to the segment level, I'll summarize the third quarter's performance on a year-over-year basis for all segments, and then I'll summarize the performance on a sequential basis.

We'll start in our gathering and processing segments. Overall, third-quarter 2011 plant natural gas inlet for the field gathering and processing segment was 628 million cubic feet per day, an 8% increase compared to the same period in 2010.

North Texas and SAOU natural gas inlet increased by approximately 15% and 11% compared to last year. Activity in the oilier portions of the Barnett shale in Wise and southern Montague counties drove the increase at north Texas. The increase at SAOU was driven by increased well connects, primarily from the prolific Wolfberry play. SAOU remains on track to set another record for single-year well connects.

Partially offsetting these substantial inlet gains was a decrease in Versado natural gas inlet volumes caused by traditional wellhead production declines, as producers are focused more on developing new resource plays in the Wolfberry and Avalon Shale/Bone Springs than workover in older fields. Over time, Versado may benefit from Avalon Shale/Bone Springs to the west and Wolfberry to the east.

Field gathering and processing operating margin increased by approximately 45% compared to last year, driven by increased volumes and higher commodity prices. Natural gas prices were essentially flat, while NGL and condensate prices were 52% and 19% higher, respectively.

Turning now to the coastal gathering and processing segment, plant inlet volumes were approximately 1.5 billion cubic feet per day, an 11% decrease compared to the same period in 2010.

While the coastal segment volumes declined in total, inlet volumes at VESCO increased 8% when compared to the third quarter of 2010. Relative to other coastal G&P volumes, VESCO volumes are significantly richer in NGL content. The performance of VESCO was driven by new gas packages tied into the facility. These new volumes at VESCO and more favorable processing economics across the segment drove a 69% increase in segment third-quarter 2011 operating margin compared to last year.

Next, I'll provide an overview of the two segments in the downstream business, starting with the logistics asset segment. Fractionation volumes for the third quarter of 2011 were approximately 29% higher compared to 2010, due primarily to the 78,000-barrel a day fractionation expansion at CBF, which operated for much of the quarter. Third-quarter operating margin increased 28% compared to the third-quarter 2010, driven by sustained LPG export activity at Galena Park and increased fractionation volumes.

In the marketing and distribution segment, NGL sales volumes for the quarter increased by approximately 9% compared to 2010 and operating margin for the segment increased 31% over the third-quarter 2010, driven primarily by an increase in NGL prices and by increased LPG export sales.

With that review of our year-over-year results, let's now discuss a few sequential comparisons for the third quarter of 2011. Starting with the field gathering and processing segment, third-quarter plant natural gas inlet increased 3% over the second quarter of 2011. Drilling and production activity remained strong.

Operating margin for the field G&P segment decreased 11% compared to the second quarter of 2011. The decline was primarily the result of an unusual set of operational issues, both ours and third parties. As Rene said, these issues, many of which were attributed to a much hotter-than-normal summer in our operations areas, have now been resolved and are not expected to occur to this extent in the future.

Moving to the coastal gathering and processing segment, plant natural gas inlet declined 8%, while operating margin for the segment decreased 13% compared to the previous quarter. The operating margin decline was driven primarily by lower VESCO volumes caused by maintenance work on the plant, by maintenance work on two third-party pipelines feeding the plant, by maintenance on major offshore production platform, and also by overall production disruptions caused by Tropical Storm Lee.

Turning now to the downstream business, in the logistics asset segment, fractionation volumes for the third quarter of 2011 increased approximately 4% due to the ramp-up of the CBF 70,000-barrel a day expansion. The logistics asset segment operating margin decreased 10% sequentially, resulting from lower LSNG treating volumes, increased maintenance activities, and increased operating expense.

The marketing and distribution segment operating margin decreased 35% compared to the previous quarter. The second quarter benefited from a contract settlement related to a multiyear propane exchange agreement.

With that, let's now move briefly to capital structure and liquidity. As of -- at September 30, we had approximately $477 million in capacity available under the Partnership's senior secured revolving credit facility, after giving effect to outstanding borrowings of approximately $535 million and $88 million in letters of credit. This capacity and $69 million of cash on hand resulted in approximately $545 million of total liquidity, leaving us with ample flexibility to pursue organic growth and acquisition opportunities.

Total funded debt on September 30 was approximately $1.5 billion, or about 53% of total capitalization, and the Partnership's consolidated leverage ratio at quarter-end was approximately 3.3 times, still at the low end of our target range of 3 to 4 times.

Next, I'd like to make a few comments about our hedging and capital spending programs for the year. As of September 30, we estimate the Partnership has hedged approximately 75% of its 2011 expected natural gas and 80% of its 2011 expected combined NGL and condensate equity volumes. At this point in 2011, our hedged percentages for next year are similar to how we've hedged in years past. For 2012, gas is hedged 60% to 70% of expected 2011 volume and NGLs and condensate are hedged 75% to 85% of 2011 volumes. Of course, we believe field G&P volumes in 2012 will be higher than in 2011.

Moving on to capital spending, including acquisitions we estimate on a net basis approximately $480 million of capital expenditures in 2011, with approximately 15% of the total comprising maintenance capital spending. This amount includes approximately $164 million related to our previously-announced acquisitions of petroleum logistics terminals. The estimate does not include our share of investment related to our minority 38.8% interest in the expansion of Gulf Coast Fractionators. We expect to spend at least $500 million in 2012 on approved growth capital expenditures and approximately $80 million in net CapEx for 2012.

Before handing the call back to Rene, I'd like to make some brief remarks about the results of Targa Resources Corp. At September 30, the balance of the TRC HoldCo loan due 2015 was $89.3 million. Also at September 30, there were no borrowings under the $75 million senior secured revolving credit facility. At September 30, TRC had a cash balance of approximately $85 million, which gives total liquidity of approximately $160 million.

TRC's standalone general and administrative expenses in the third quarter were $1.7 million, and we expect a similar amount of G&A in the fourth quarter.

On October 11, TRC declared a third-quarter cash dividend of $0.3075 per common share, or $1.23 per common share on an annualized basis, representing an approximate 6% increase over the rate paid with respect to the second quarter of 2011.

TRC standalone distributable cash flow for the third quarter came in at $20.2 million. This reported number reflects a one-time benefit for current taxes that relate primarily to an overpayment of prior-year income taxes. On a pro forma basis without this one-time effect, TRC's standalone distributable cash flow was about $14 million, which represents a coverage ratio of 1.1 times.

That concludes my review, so now I'll turn the call back over to Rene.

Thanks, Matt. To wrap up the final portion of our prepared remarks, I would like to review the impressive set of organic-growth projects that we have underway.

In direct response to increased production, producer activity, and expected volumes from significant new acreage dedications in the recent -- we recently announced a 200 million cubic feet a day cryogenic gas processing plant for north Texas. The project cost is estimated at approximately $150 million, and is expected to be online and operational in mid-2013.

Also due to increased producer activity and new acreage dedications, we are exploring gathering and processing expansions in the Permian Basin and our San Angelo operating unit and for the Sandhill system.

Our $360 million fee-based 100,000-barrel per day Train 4 expansion at Cedar Bayou fractionation is progressing on time and on budget for a Q1 2013 startup. We previously mentioned that this capacity is essentially fully booked for a term with high levels of frack-or-pay commitments.

Further, due to additional demand for fractionation capacity in response to high level of customer inquiries, the Partnership is exploring a potential 100,000-barrel per day Train bayou -- Train 5 at Cedar Bayou.

At approximately $250 million, the expansion of our Galena Park marine export/import terminal and our Mont Belvieu complex to provide for exports of international-grade propane will add to our fee-based profile and is expected to be operational Q3 2013.

The $35 million benzene-treating project, also fee based, is scheduled for commercial operation in January 2012.

The 25 million -- $29 million fee-based expansion of Gulf Coast Fractionators, where we have a 38.8% interest, is underway and is scheduled for completion in Q2 of 2012.

In conclusion, we are pleased to report operating margin increases for each of our segments compared to last year on both a year-to-date and a third-quarter basis. These results clearly illustrate the growth we are seeing across all areas of our operations.

We have over $300 million of growth investments that are coming online this year. We have also announced over $860 million of approved projects targeted for start-up during 2013.

As we continue to expand our diverse operations in response to strong industry fundamentals, we are becoming increasingly optimistic about the Partnership's longer-term growth. At EBITDA multiples of 5 to 7 times or better, these projects provide the Partnership with good visibility on incremental contributions to EBITDA through the 2014 timeframe. And we are continuing development of additional projects to serve our customers' needs.

And with that, we'll turn it over for questions.

(Operator Instructions). Bradley Olsen, Tudor, Pickering.

Could you guys discuss some of the one-time items? It appears as though they were largely felt in the field G&P, as well as the logistics segment. And I was wondering if you guys might be able to quantify those one-time impacts on both those segments.

This is Mike Heim. I'll go over some of these very briefly.

Looking at the field, we had both operational problems with some of our own equipment, primarily some of the turbines in the hot weather. We also had to shut back part of our production during the timeframe when Chevron's west Texas pipeline was partially shut down due to a fire that they had.

There were a number of wildfires across both north Texas, eastern New Mexico, and west Texas that caused us to shut parts of our gathering systems in as the firefighters moved in and fought those fires. We've got a number of places where we have aboveground pipes, and we had to actually remove the gas and make them safe while the firefighters were in the area. That's very, very unusual for us.

We also had to put up with a problem in the Gulf of Mexico. We had a tropical storm come in where we curtailed production in most of the Gulf. The middle part of the Gulf was shut in. Producers removed their people from the platforms. So we had gas down for several days.

At the end of that period, we were doing scheduled maintenance on one of our plants that has two trains, and we had a turbine problem with the other one, so basically we were producing and processing very little gas for four or five days in there.

So, it's a number of different problems, primarily temperature, drought related, and in a normal year we wouldn't have seen any of these. They're very unusual, and we've fixed all these problems and don't expect to see them again.

And we had significant one-time operational issues with the pipeline supplying our coastal straddle plants, both on the western and eastern areas of the Gulf of Mexico.

Okay, great. That's really helpful color.

I guess kind of a related question, as far as -- given the fact that right now we're probably at a historical record, if not pretty close, in terms of the utilization factor on a lot of NGL infrastructure, and given the fact that you guys are somewhat unique in that you touch both the upstream portion of the midstream industry as well as the downstream portion, do you feel as though in this high-utilization environment that we're more likely to see small hiccups or just various issues have maybe larger impacts than they have historically, just given the fact that everything is running at 95% or higher?

Primarily with the Y-grade pipelines feeding Belvieu. Anything -- I mean, those lines are running all out, and any kind of hiccups with those operations are going to lend itself to quite a number of curtailments in deliveries to Belvieu, as well as from our processing assets and others.

Yes, most of the facilities at Mont Belvieu are at or very, very close to capacity, when you're talking about the fractionators, the connecting pipelines.

We have had a few hiccups, as you say, with power in the Mont Belvieu area. It's expanded very quickly. There are ongoing discussions with the transmission companies in the area. And I think everybody is on the same page with the growth. And I don't think that, on a go-forward basis, there's really going to be any major problems out there. But it's something that does need to be coordinated and is being coordinated.

I think you might have just answered my next question. But as far as looking at your 2012 guidance, when you think about the volumes that you're going to be running on your fractionation units, you're not expecting any kind of curtailment throughout 2012 to affect the amount of Y grade that you receive in Mont Belvieu and Lake Charles?

We have scheduled maintenance to be done during 2012, but no major outages. And as we temporarily take production -- fractionation facilities down in Mont Belvieu, we shift barrels over to our Lake Charles fractionator.

And if your question was aimed at whether pipelines were going to cause constraints to our fractionation volumes, we don't currently expect that, absent a problem like West Texas Pipeline, and absent that force majeure, you know that we have high reservation fees, or so-called frack-or-pay.

Okay, and those would remain in place, even if there was a shortfall from a pipeline outage?

Absent a force majeure event.

Darren Horowitz, Raymond James.

Just a few questions, Rene. Thinking about the amount of capital for infrastructure enhancements that's associated with CBF Train 4, if we were -- if you guys were to move forward with CBF Train 5, am I right in assuming that the cost could be closer to $275 million relative to the $360 million that you're spending on 4?

You know, at this point in time, we are looking at the utilization of all of our assets, storage, brine, interconnects, and the fractionation, and I don't think I could give you a plus or minus 25% number today, but it's an exercise that we're doing right now so that we can put in a very detailed air permit application.

We are expanding a lot of our facilities that were filled up and utilized when we put the 78,000-barrel a day fractionator in, and that's why the Train 4 is $360 million. And we're just trying to find out, give ourselves comfort, and make sure that we give all of the reliability to our customers that they deserve as to what we need to add for Train 5.

Okay. So Mike, when you're thinking about that and you're thinking about all the NGL pipe expansions into Belvieu that should be coming on by 2013, how do you guys think about leveraging that footprint to get more of the purity products down to the petchems? Is it a situation where you'll come back in and look at that propane export facility and possibly enhance it again, or is it a situation where you think, simply put, as you pointed out, you'll need more storage and, more importantly, downstream connectivity to the petchems in order to handle all that offtake?

When we decided to do the debottlenecking and add the 78,000 Train 3, we started working on interconnects with the different petrochemical companies. By early next year, we will have five new connections that weren't in in 2007 and 2008. So we're definitely working with the petchems.

As far as storage is concerned, with the flexibility that the petchems want, we definitely are putting in additional storage for their utilization. We also want to make sure that we don't disrupt the fields. We're going to put in new Y-grade storage so that we have more areas to -- more capacity. We're going to have five new pipeline connections into Mont Belvieu by the middle of 2013, which is great for the utilization of our fractionation capacity.

Input connectivity and outgoing connectivity will be in place by the time Train 4 starts. That will be infrastructure that could be leveraged to Train 5.

As we're designing Train 5, Mike has already been making decisions and his engineering group has been sizing and going forward with dollars being spent that are upsizing, that will benefit a Train 5 should we go forward with (multiple speakers)

We definitely saw that Train 5 potential was right on the heels of Train 4. We've upsized the piping all the way through the new pipe racks and we have upsized some of the new brine ponds that we're putting in, and they were very cheap increases rather than doing it over again. So, we're going to get some synergies from Train 5 if we build it.

The other thing you brought up was the export capacity. We are working very hard to utilize all of the assets we've got. With the announced export increase, we're putting in the new deethanizer. We're putting in the refrigeration. But with that goes the management of the pipes connecting Mont Belvieu and Galena Park, and all of that is going very well at this point in time.

Yes, and Darren, if we had to, we could expand that facility further. For another dock, I think it's about $80 million --

$30 million for the dock and about $50 million for our new large-diameter (multiple speakers)

Yes, for a total number of $80 million, we could increase the number of ships we can handle per month at that facility.

Rene, last question for me. Could you just give us a little bit more color on the scale and scope of how you're thinking about expanding that G&P asset footprint in and around the Permian and SAOU? Because I know you've got $30 million on the board right now for an SAOU expansion, and I'm assuming what you're talking about right now is going to be a bit more.

Yes, $30 million at San Angelo with the two cryogenic trains we're currently being -- currently being refurbished. We could probably see another 30 million a day processing expansion at San Angelo, just based on the acreage dedications we're working on, and then at Sandhills we're also looking at 30 million a day of additional expansion of processing there.

And longer term, we've talked about building a line from the Sandhills system out West, which could further, down the road, lead to 200 million a day of additional processing. But for sure, 90 million a day looks like that's almost a guaranteed.

Louis Shamie, Zimmer Lucas Partners.

Just had a question regarding the results in field G&P. If I'm just comparing it to the second quarter, your volumes were up, pricing was better, but the gross margin was about $7 million lower. Just trying to understand how that happened. Was that something related to the one-times or how did that flow through?

Yes, part of it was related to the one-times that Mike had touched on earlier. The other part, we say, commodity prices. Gas and NGLs were approximately flat, but crude was down. So we did have a negative price variance in the field segment and we do bank a decent amount from the condensate sales, and those were down sequentially.

Okay. But otherwise, I guess, when I think of operational issues, I usually think of those, let's say, affecting the volumes. Is there any reason that would affect you other than what showed up in the volumes?

We had lower condensate and crude, primarily in north Texas, which was several million dollars' worth of impact. The recoveries on some -- at some of the plants, as we went up towards higher capacities, decreased. The inlet volume could be up. That's why we brought the Conger plant on in SAOU. That plant brought on an additional 25 million a day of capacity, and we had (multiple speakers)

(Multiple speakers) west Texas pipeline was down, we were having to process inefficiently to try to keep our producers on. But the inlet was still more up than the NGLs were producing.

We basically went into ethane rejection, so that our inlet stayed the same as far as what came to the plant. But we went into ethane rejection because we got throttled back by 40% on west Texas pipeline for about 10 days.

A lot of moving parts.

That makes sense. Okay. So, and most of these issues have already been resolved.

Taken care of, and actually a little bit of extra costs, too, in it.

Makes sense. Okay. Thank you very much.

T.J. Schultz, RBC Capital Markets.

Just on the propane export project, how much of that export capability is contracted with take-or-pay contracts, and where are those new low-ethane volumes going?

On the new project, nothing to date. The current activity is on the multiyear deals, but we have no contracts in place for the expansion. Right now.

Lots of interest.

Lots of interest. We're not too concerned about being able to contract for activity when this facility comes on, but nothing to date.

Yes, we see far enough out that it's very difficult to get somebody to sign a multiyear two years in advance. (Multiple speakers). That's where we've been, and especially before we announced it. I mean, it hasn't been long since that's been announced.

Okay. On the terminal segment, can you expand on some of the growth opportunities around the Sound and Baltimore terminals? I guess, is the $60 million guidance there indicative of the full extent of the expansion available at those terminals, plus Channelview, and then, I guess, kind of what timing and returns do you expect on some of those expansion projects?

Basically when we bought each of those terminals, we thought that there was built-in expansion.

Channelview, we have signed agreements for additional land to build tanks. We are very close to signing a contract with one of the long-term customers down there for another 190,000 barrels of storage. Again, that will be signed before we start construction. It'll be at least a three-year contract.

At Sound, again, it had projects in there. We're working on connections to the Olympic pipeline and we are working with several producers. We've got a signed contract up there to build another 190,000 barrels a day of storage.

There is a lot of upside for Tacoma that we have not announced. It's a great location. We've got great people and we've got a lot of connectivity. We're just in the process of buying additional land next to the northern part of our acreage so that we can expand into that.

So, there's a lot of growth in here. There's a lot of growth potentially in Baltimore. It's just (multiple speakers)

The $60 million is indicative of that very highly probable, not the full growth case.

And I think we've told everybody that these aren't going to be the only three that we own. We're continuing to look at other ones that we're negotiating to buy.

Okay, great, helpful. I guess just one last thing. On your target leverage, you're still obviously comfortable with the low end of your 3 to 4 times target leverage. I guess the question is, as you progress towards more 45% of the business being fee-based for margin, does that make you more comfortable kind of approaching the higher end of that target leverage, or where would you expect things to shake out as you kind of approach that 45% fee-based margin?

Over time, as the fee-based mix changes, you know, you can look at being more comfortable at the high end, but three to four times has been where we've led and we've really been at the low end. We're a pretty conservative group over here that likes a lot of liquidity and we just generally feel more comfortable at the low end of that range.

So, over the next several years as the fee-based increases, we'll evaluate where we're more comfortable, but we like to give ourselves plenty of flexibility. So, really anywhere between three and four times we're comfortable, depending on the growth profile of the business.

Yves Siegel, Credit Suisse.

Matt, just on the last point. What's your sense or goal in terms of investment-grade credit rating?

Yes, we get that question a fair amount. Our thought over here is two things are really needed to get to investment grade. We need to increase the amount of EBITDA and increase the amount of fees -- you know, fee-based percentage.

We don't have a target or a goal that says we want to be investment grade by this time, this date, or this exact metric. But what we're doing is we're just executing on our strategy of growing the EBITDA and growing the fee-based. And so, as we do both of those things, we're going to approach the land of the possibility of investment grade.

So it's not a set goal, but the goal that we are delivering on does kind of get us closer to that position.

Okay, got it, thanks. And then, could someone describe how much capacity do you have on the -- how much takeaway capacity or pipeline capacity do you have right now going into Mont Belvieu and how are you thinking about it going forward?

Are you asking how much we have under contract or how much is there on line in service from the multiple pipeline owners that come into our facility?

No. I'm asking about you specifically.

Well, we're the biggest shipper on the West Texas Pipeline by far. And we have contracted with DCP for their Sandhills Pipeline future. We also ship on Louis Dreyfus or Lone Star Energy Transfers company.

So we ship on them, and then we've got some that comes through Chaparral, which is an Enterprise pipeline. So we've got it spread out on four pipes today -- or three pipes today with a fourth one coming. And we are -- we have connectivity with ONEOK'S Arbuckle line. We anticipate to be connected to DCP's new line out of Oklahoma and we expect to be connected into Enterprise's new line coming out of the Rockies in north Texas.

So, we anticipate being connected to everybody. It's going to give the producers and midstream companies more flexibility, but by the end of 2013, we anticipate being connected, I think, to either nine or 10 pipeline companies bringing in raw make into Belvieu.

Adding to Mike's description, it may be as you look at other companies they're reporting that they are constrained in their gathering and processing areas because of lack of NGL takeaway capacity.

In our rapidly-growing north Texas and SAOU areas, we have not been constrained. I give credit to our commercial folks being ahead of the game and getting capacity in front of that growth.

Large projects in the far Western Permian, ourselves and others, are somewhat constrained waiting for those pipelines to be developed. But that's not inhibiting our current capacity and current producer customers at this time. Then you look at it from a fractionation standpoint. All of that new capacity that Mike's talking about can come to our fractionation and terminaling facilities in Mont Belvieu.

Certainly, the new 200 million a day plant we have announced in north Texas has to have a home, and we're dealing with that with several interconnects. SAOU, the San Angelo system, has capacity under contract to install the two Garden City trains at the Sterling plant. That's not a problem.

We do bump up into some MAOP problems with some of the takeaway pipelines out in the Permian. And we anticipate one of those being fully fixed by the first quarter of next year. That was not our problem. It was one of the pipeline companies who had reduced their MAOP on the line, so that's supposed to be looped and replaced by the end of the first quarter.

So, there's going to be constraints on the whole system, not just Targa, all the midstreams and all the producers, until we get to 2013 with new pipelines coming on and new fractionation coming on.

Was there or is there an opportunity for you to take an equity interest in any of the new builds or the expansion projects?

Some of that's under negotiation right now. I can't go into it because of CAs that we've got.

Okay. And then, on the [quarro], with the 200 million of inlet capacity, how much NGLs do you think you'll be producing there?

That plant will -- based upon the drilling to date around it, it looks to me like that plant will probably be able to recover about 21,000 to 22,000 barrels a day.

Ramping up slowly over time.

Yes, it peaks in -- several years out after it comes on.

Okay. And then, in terms of thinking about further fractionation new builds, and I might be way off on this, but what kind of contract length are you thinking about? Did you disclose, like on frack four, what the contract length was?

Yes, I think that we've told people that they are long term, 10-year contracts with high percentages of either frack or pay.

And would you be thinking that you'd be able to get a similar type of contract to go ahead with another project?

Absolutely. That's the only way we're going to do it.

And then, my last question is as you look at your geographic footprint, is there opportunities for you to expand into different regions?

There are opportunities, and we've been working on those additional areas for quite a while. But we keep -- we've got efforts going forward. We'll see how they turn out.

It was also fairly attractive as an investor, you all have seen, for the resource plays to come to Targa instead of Targa going to the resource plays.

And that's particularly true in Louisiana where there is the potential of the Tuscaloosa marine shale or Louisiana, Eagle Ford, Wilcox, and Austin chalk plays. We've got some additional wellhead. We've doubled probably the wellhead coming in the loop and we're trying to figure out a way to tie all of our facilities.

We've got 13 plants across south Louisiana, and we're trying to figure ways, if this Tuscaloosa play turns out to be a major resource play, how do we leverage our existing asset base to take advantage of that. So, we're fortunate to be in the areas where we've got a huge amount of drilling activity and we're working hard to see if we can get into some of the other areas.

Yes, I apologize. You've announced close to $1 billion worth of projects and I just want more, right? So, I apologize.

So do we.

So do we.

Michael Blum, Wells Fargo.

I think Yves asked all my questions. Just one, I guess, big picture everyone has been kind of circling around, this frack five. The big-picture question is, up until now it seems like you've just seen -- I guess I'd describe it as insatiable demand for frack capacity by the industry, and do you see that slowing down at all? Or do you --

No. We announced that we've preliminary work on that Train 5, but I wouldn't be surprised if others operating in Belvieu want to add an additional fractionator. We could see a couple more additional fractionation projects above our Train 5. So, maybe three more, Mike?

Yes, I think there's a strong possibility of that.

Basically, we had a list of 20 potential suppliers for Train 4. We filled it with three, and those other 17 are still out there asking for space. We made it very clear to everybody we were going to build it and we were going to take the first people who came to the negotiating table to take the terms that we were offering.

And that's why we have already started working on the air permit. We have bought the property to build a Train 5 on. And we have started working on all the engineering. The only thing we have not tied down is how many ancillary utilities we need to increase, if any.

I would put my money on two more fractionators above our Train 5.

And it may be three.

And it could be three.

James Jampel, HITE.

Yes, in the spirit of wanting more, you haven't discussed the acquisition market much. Is there anything out there that perhaps the combination of having the C-Corp structure public would help you do at a more reasonable price?

Yes, terminal, acquisitions -- we are. We are acquiring terminals, and like Mike said, we are not stopping at three. We think there's additional opportunities out there that we're going to be closing on.

But with regard to other areas and other assets, we see them all. We look at them. Sometimes we make an aggressive bid. Like you've seen, we haven't been very successful doing that, but we think there's going to be quite a few assets available for us to take a look at.

But spending all the money that we've spent, $500 million this year and another $860 million and growing above that, I'll keep focusing in on these organic growth opportunities before stepping out with a high multiple acquisition.

I mean, our business development group hasn't shrunk any, and they played a key role in Train 4 being fully contracted this quickly after we announced it.

But we aren't currently looking at acquisitions at the C-Corp level.

Wait, you said you are looking at the C-Corp level?

We are not.

Helen Ryoo, Barclays Capital.

So just one follow-up on the frack discussion. On frack five, are you -- given the strong -- still strong demand environment there, are you seeing a better pricing environment as you put frac five into your firm, I guess, projects?

I would put it in the same environment as the current expansions that are underway.

Okay. So pricing-wise, you would get a similar type of contract rate?

People who were unable to get space in Train 4 are still very interested and now might want to be first in line instead of too late in line.

Okay. Great. And then, just one follow-up. Rene, you mentioned five to seven times return on these projects coming online in 2013. Do you think by 2014 you would be able to achieve that return multiple? Or is that too early, as some projects need some ramp-up time?

Most of these projects come on throughout 2013. So we mentioned the five to seven times EBITDA multiple as kind of going to provide growth through 2014 as they will continue to kind of ramp and get more full-year credit in 2014. So, it's kind of a staged amount of EBITDA going on throughout 2013, and then we'll see the benefit of that in 2014.

All of these projects will be at probably full capacity in 2014, with the exception of north Texas (Multiple Speakers)

North Texas is going to be (multiple speakers)

-- which will have to be drilled into.

Yes, which would be another year or two outside of 2014 before they see peak volumes.

And I guess other than north Texas, everything else is fee-based projects? North Texas, you would (multiple speakers)

No, the processing additions out in the Permian would be under the similar contractual structures that we have out there. But anything involving the liquids business would be fee-based. Terminals would be fee-based. Galena Park, Belvieu.

Although a great percentage of our field gathering and processing there are a combination of POP and fee. Primarily the fees are for treating and compression and the POP is for the processing.

Thank you. I show no further questions in the queue and would like to turn the conference back to Mr. Rene Joyce for closing remarks.

Thank you, operator. And to the extent that anyone has any follow-up questions, please feel free to contact Matt or any of us. Thank you again for your time today, and we look forward to speaking with you again.

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program, and you may all disconnect at this time.