Targa Resources Corp (TRGP) 2011 Q4 法說會逐字稿

Good day, ladies and gentlemen, welcome to the Targa Resources Fourth Quarter 2011 Earnings Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. (Operator Instructions) As a reminder, this conference call is being recorded.

I would now like to turn the conference over to Joe Brass. You may begin.

Thank you, Operator. My name is Joe Brass. I'd like to welcome everyone to our Fourth Quarter and Full-year 2011 Investor Call for both Targa Resources Corp. and Targa Resources Partners, LP.

Before we get started, I would 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 Joe Bob Perkins, Chief Executive Officer, and Matt Meloy, Chief Financial Officer and Treasurer. Joe Bob and Matt are going to be comparing the fourth quarter and full-year 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 Acts of 1933 and 1934. Please note that actual results may 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 and the Company's annual reports on Form 10-K, for the year ended December 31, 2010, and other quarterly reports on Form 10-Q.

One quick reminder, before starting into the results. With the closing of multiple acquisitions from TRC over the previous years and in accordance to 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 Joe Bob Perkins.

Thanks, Joe. Welcome and thanks to everyone for participating in our Fourth quarter and Full-year 2011 Conference Call. As is our practice, besides Matt and myself there's several other members of the team who will be available to assist in the Q&A session. That group today includes Rene Joyce, Jim Whalen, Jeff McParland, Paul Chung, and Bob Sparger. So I'm getting a lot of support and you're surrounded.

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

We are pleased to report strong operating and financial results for the fourth quarter and full-year 2011, with solid performance in both our gathering and processing and logistics and marketing divisions.

The Partnership's integrated midstream platform continues to benefit from industry fundamentals, strong ongoing trends which we have discussed before driving growth in liquids-rich natural gas volumes, and increased NGL supplies.

As indicated in our earnings release, we reported record adjusted EBITDA of $146 million for the fourth quarter and $491 million for the year. This resulted in quarterly and annual distributable cash flow of approximately $107 million and $337 million, respectively.

The 2011 adjusted EBITDA of approximately $491 million reflects annual growth of about 25% over 2010.

The Partnership's fourth quarter declared distribution of $0.6025 per quarter, or $2.41 per unit per year, was a healthy coverage of 1.6 times. This distribution represents a 10% increase compared to the fourth quarter 2010; and that 10% increase is just for the quarter comparison.

With this latest distribution increase, the Partnership is well on track to achieve our guidance of 10% to 15% distribution growth for full-year 2012 over full-year 2011. In 2011, the Partnership demonstrated strong distribution growth, while at the same time maintaining an average annual distribution coverage of 1.4 times, slightly higher than the 2010 reported coverage of 1.3 times.

As you will recall, due to increased scale and diversity, our long-term target would be coverage of more like 1.2 times.

Moving to business highlights for our Gathering and Processing division, the field G&P segment recorded a 2011 operating margin increase of approximately 22% compared to full-year 2010. This increase was benefited from active drilling and completion activity resulting in increased volumes at SAOU, North Texas, and Permian. Inlet volumes and gross NGL production for the segment both increased more than 4% over 2010; and this 4% increase is a net of a year-over-year Versado volume decrease, which we expect to reverse in 2012.

These growing field G&P volumes are primarily from resource plays -- Wolfberry oil wells, in the case of SAOU, Wolfberry and Bone Springs for the Permian, and high liquid gas wells from the oily part of the Barnett in North Texas.

As an aside, we have recently been asked several times about our exposure to dry gas production. The short answer is that we have little downside exposure to dry gas. Certainly our 2012 guidance is not impacted. I don't believe we have any real dry gas anywhere.

Our drier -- and I say drier in quotes, drier in a relative sense gas -- would be (1) a small volume in Versado, the Moro production drilled more that several years ago. Some existing production in the drier part of the Barnett gas, which we've said we aren't very well positioned in. And (3) some gas from offshore Southwest Louisiana that goes to our westernmost Straddle plants. All of this drier gas is relatively mature production without any meaningful drilling in the last few years. Therefore, with little dry gas exposure today, we believe that Targa's drier gas offers only long-term up side, not near-term or middle-term down side.

Getting back to the segment reports, full-year 2011 coastal G&P segment operating margin increased approximately 62% over 2010. The increase was primarily attributable to a significant increase in higher GPM, key POL volumes at VESCO, and higher system GPM at LOU, due to wellhead volume increases and the optimization of throughput to more efficient higher-recovery plants as well as higher NGL and condensates sales prices and a favorable frac spread environment, as the result of low gas prices relative to NGLs.

The increased NGL production that we are seeing across the Partnership's Gathering and Processing division, as well as from other G&P companies due to the same NGL dynamics we've discussed often, continue to drive increases in operating activity in our downstream assets and continue to create demand for incremental NGL infrastructure.

Annual operating margin for our Logistics and Marketing division increased 47% in 2011 over 2010. The Logistics Assets segment benefited from increased fractionation volumes, primarily due to CBF's Train 3 expansion and from increased LPG export activity, which benefits both our Logistics Assets and our Marketing and Distribution segments.

As you probably know, the Logistics Assets segment also now includes our three newly acquired petroleum logistics terminals -- Channel B on the Gulf Coast, Sound on the West Coast, and Baltimore on the East Coast. They were all acquired in 2011. They're adding fee-based margin for 2012 and providing organic growth opportunities at each site.

Operating margin in the Distribution and Marketing segment increased 41% over 2010, benefiting from export activity and higher NGL prices. For 2012, our previous EBITDA guidance of 10% to 15% growth from our initial 2011 EBITDA guidance range of $465 million to $475 million remains unchanged.

At the time, those 2012 guidance assumptions were based on $4 natural gas, $85 crude oil, and an average price for the Partnership's NGLs of about $1.30 per gallon. That included a $0.75 per gallon ethane assumption. Based on the current pricing environment, which includes approximately $0.50 per gallon ethane, we are still comfortable with the previous midpoint 2012 guidance. That guidance is approximately $530 million for 2012.

And therefore, we are also comfortable with our previous guidance for distribution growth over the original guidance of about 10% to 15%.

Additionally, to give you a sense of the impact of ethane prices for the Partnership, beyond 2012 a $0.25 per gallon drop in ethane prices would result in about a 5% impact on our EBITDA in 2013 or 2014 or later years.

While talking about commodity price sensitivities, we should remind you that Targa is not very sensitive to natural gas prices. As currently hedged, a decrease in gas prices has a slightly positive impact on our 2012 EBITDA. For 2013, a decrease in gas prices has a slightly negative impact on EBITDA. And as we add profitable key POL processing volumes, which benefit from expected continued strong frac spreads, we are actually adding a short gas position that significantly offsets our natural gas link from POP contracts in the fuel G&P segment, a natural hedge.

So to summarize those last few messages -- and Perkins is often too wordy -- we are comfortable with our 2012 guidance at current prices. For 2013 and later years, a $0.25 per gallon drop in ethane prices results in about a 5% impact on EBITDA. And natural gas prices aren't a driver of Targa financial performance.

As we have disclosed, or at least will put in the 10-K, we will spend about $490 million of total gross CapEx in 2011. Supported by continued strong underlying industry dynamics, and working hard to keep up with those dynamics, we have approved and launched an impressive set of organic growth projects for completion in 2012 and 2013, and we try to keep you posted on those projects.

Those projects currently disclosed to be completed in 2012 and 2013 represent a total of over $1 billion in capital expenditures.

So that's a brief overview of our TRP highlights. At the TRC level, TRC declared a fourth quarter cash annualized dividend of $1.345 per share, which was a 31% increase over the fourth quarter of 2010.

Consistent with our previous guidance, we continue to expect 30% to 40% dividend growth for full-year 2012 over full-year 2011.

That wraps up my initial overview. Now we'll hand it over to Matt.

Thanks, Joe Bob. I'd like to add my welcome and thank everyone 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 fourth quarter of 2011, the Partnership reported net income of $75.5 million, compared to $35.9 million for the fourth quarter of 2010. The income per diluted limited partner unit was $0.75 and $0.39, respectively. These quarterly results reflect non-cash hedge charges of $1.3 million in 2011 and $9.3 million in 2010.

As Joe Bob mentioned, adjusted EBITDA for the quarter was $146.3 million, significantly above the $114.1 million for the same period last year. The increase was primarily the result of higher operating margins across our businesses in both the Gathering and Processing and the Logistics and Marketing divisions, and of lower general and administrative expenses.

Gross margin increased 17% for the fourth quarter compared to last year, also with increases across both divisions, and I will review the drivers of this performance in our segment review.

Operating expenses for the fourth quarter increased 5% compared to last year, primarily due to increased maintenance, fuel, and utilities.

Interest expense increased $3.1 million compared to the fourth quarter of 2010, driven by a higher effective interest rate.

Gross maintenance capital expenditures were $24.6 million in the fourth quarter of 2011, compared with $20.8 million in 2010. Adjusting for the non-controlling interest portion of maintenance capital expenditures and certain reimbursements from TRC to the Partnership, net maintenance capital expenditures were $17.1 million in the fourth quarter of 2011, compared with $15.6 million in 2010.

Turning to the segment level, I'll summarize the fourth quarter performance on a year-over-year basis for all the segments, and then I'll summarize the performance on a sequential basis. We'll start in our Gathering and Processing segment.

Overall fourth quarter 2011 plant natural gas inlets for the Field Gathering and Processing segment was 633 million cubic feet per day, a 5% increase compared to the same period in 2010. Field Gathering and Processing operating margin increased by approximately 25% compared to last year, driven by increased volumes and higher NGL and condensate prices, partially offset by lower natural gas prices.

North Texas, SAOU, and the Permian business natural gas inlet volumes increased approximately 17%, 6%, and 6%, respectively, 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 primarily by increased well connects, primarily from the prolific Wolfberry oil play.

As a note, when Targa uses the term Wolfberry, we are using it broadly to refer to the full suite of formations and various completion combinations across the Wolf Camp, Sprayberry, Dean, and other related Permian formations. Our producer customers may have their own favorite terms, and the completion combinations will vary across these large resource plays and vary over time.

In 2011, SAOU set another record for single-year well connects, and we expect a similar number of well connects in 2012.

The Permian business benefited in large part from the volume growth at Sand Hills, both from Wolfberry and Bone Springs developments.

Partially offsetting these substantial inlet gains was a year-over-year decrease in Versado natural gas inlet volumes caused by wellhead production declines and greater-than-normal operational issues. We expect to reverse this decrease this year due to new well connects and a return to normal operations. Over time, Versado may enjoy additional benefit from Avalon Shale, Bone Springs to the west, and Wolfberry to the east. We are starting to see encouraging activity around the system.

For the Field Gathering and Processing segment, natural gas prices decreased 6%, while NGL and condensate prices were 27% and 11% higher, respectively.

Turning now to the Coastal Gathering and Processing segment, operating margin increased 59% in the fourth quarter compared to last year. The increase was driven by higher GPN key POL volumes at VESCO and [Laury], increased inlet and average GPM at LOU, largely due to increased wellhead volumes, higher NGL and condensate sales prices, and favorable frac spreads.

Coastal G&P segment plant inlet volumes were approximately 1.6 billion cubic feet per day, a 1% decrease compared to the same period in 2010. While over all the Coastal G&P segment inlet natural gas volumes decreased, inlet volumes at VESCO increased 25% and volumes at LOU increased 16% when compared to fourth quarter 2010.

Relative to other Coastal G&P volumes, LOU wellhead and certain new VESCO volumes are richer in NGL content. As a result, NGL production for the Coastal segment increased 6% in the fourth quarter of 2011, as compared to last year.

Next I'll provide an overview of the two segments in the downstream business, starting with the Logistics Assets segment. Fractionation volumes for the fourth quarter of 2011 were approximately 20% higher compared to 2010. Again, due primarily to the 78,000 barrel a day Train 3 fractionation expansion at CBF, which operated for approximately eight months in 2011.

Fourth quarter operating margin increased 22% compared to the fourth 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 10% compared to 2010, primarily a result of increased export activity, higher CBF throughput, and our investments in increased connectivity to our petrochemical customers.

Operating margin for the segment decreased 4% over the fourth quarter of 2010, largely due to the very strong performance in the fourth quarter of 2010, partially driven by last year's earlier and colder-than-normal winter.

With that review of fourth quarter results, let's now discuss a few key sequential comparisons for the fourth quarter of 2011. Starting with the Field Gathering and Processing segment, drilling and production activity remained strong in liquids-rich SAOU and Sand Hills and in the oilier part of the Barnett Shale play.

Fourth quarter operating margin for the Field Gathering and Processing segment increased 4% compared to the third quarter of 2011. The increase was primarily the result of the increased plant inlet volumes and NGL production in North Texas and increased condensate prices.

Moving to the Coastal Gathering and Processing segment, operating margin for the segment increased 32% compared to the previous quarter. The operating margin increase was driven primarily by higher volumes at VESCO, which were impacted by maintenance work in Q3 2011, and by higher LOU volumes compared to the third quarter.

Turning now to the downstream business, the Logistics Assets operating margin increased 24% sequentially, resulting primarily from annual take-or-pay payments realized in the fourth quarter.

Fractionation volumes for the fourth quarter 2011 increased slightly, as the third and fourth quarters of 2011 realized the incremental impact of CBF Train 3.

The Marketing and Distribution segment operating margin increased 55% compared to the previous quarter. The increase was primarily the result of seasonal factors benefiting wholesale propane and stronger NGL prices.

With that, let's now move briefly to discuss capital structure and liquidity. At December 31, we had approximately $510 million in capacity available under the Partnership's senior secured revolving credit facility, after giving effect to outstanding borrowings of approximately $498 million and $93 million in letters of credit. This capacity and $56 million of cash on hand resulted in approximately $566 million of liquidity.

Total funded debt on December 31 was approximately $1.5 billion, or 52% of total capitalization, and the Partnership's consolidated leverage ratio at quarter-end was approximately 3 times, still at the low end of our target range of 3 to 4 times.

We've already had a busy and productive start to 2012 financing, having completed two capital markets transactions resulting in over $565 million of new capital raised.

We closed a public offering of 4.4 million common units, including the full exercise of the underwriters' over-allotment option, which resulted in net proceeds to the Partnership of approximately $165 million. TRC participated in the offering, purchasing 1.3 million units for approximately $50 million. TRC also contributed $3.4 million to maintain its 2% general partnership interest.

We also closed on a private offering of $400 million of 6 3/8 notes due August '22, issued to par.

The senior unsecured notes offering benefited nicely from the improvement in our credit ratings over the last year. In May 2011, S&P upgraded the Partnership's corporate and notes ratings to BB. This January, Moody's upgraded the Partnership corporate rating to BA2 and the notes rating to BA3.

The net proceeds from both the debt and equity offerings were used to reduce borrowings under our senior secured credit facility. Giving effect to the January debt and equity offerings, the Partnership's pro forma liquidity as of December 31, 2011, was over $1 billion, and pro forma leverage ratio was approximately 2.8 times, leaving the Partnership in an advantage position to fund future organic growth and acquisition opportunities that Joe Bob mentioned and will discuss later in the call.

Next I would like to make a few comments about our hedging and capital spending programs for the year. As of December 31, we estimate the Partnership has hedged approximately 60% to 65% of its 2012 expected natural gas and 75% to 80% of its 2012 expected combined NGL and condensate equity volumes.

Moving on to capital spending, we estimate on a net basis approximately $650 million of capital expenditures in 2012, with approximately 12% of the total comprising maintenance capital spending.

The estimate does not include our share of the investment related to our minority 38.8% ownership in the expansion of Gulf Coast Fractionators.

As I wrap up, I'd like to make some brief remarks about the results of Targa Resources Corp. At December 31, the balance of the TRC HoldCo loan was $89 million. Also at year end, there were no borrowings under the $75 million senior secured revolving credit facility.

At December 31, TRC had a cash balance of approximately $90 million, which gave us total liquidity of $165 million.

In conjunction with the TRP offering in January, TRC used about $50 million of its cash to purchase 1.3 million of the NGLX units.

TRC standalone general and administrative expenses in the fourth quarter were about $1.8 million, and we expect a similar amount of G&A expense in the first quarter of 2012.

On January 12, TRC declared a fourth quarter cash dividend of $0.33625 per common share, or $1.345 per common share, on an annualized basis, representing an approximately 9% sequential increase and 31% year-over-year increase.

TRC's stand-alone distributable cash flow for the quarter was $14.1 million, and $60.2 million for the full year 2011.

This concludes my review, and I'll now turn the call back over to Joe Bob.

Thanks, Matt. To conclude our prepared remarks, I'd like to provide an update on some of our growth project activity.

In the fourth quarter of 2011, we announced the North Texas Longhorn project, a 200-million-cubic-feet-a-day cryogenic gas processing plant, in response to increased production, significant producer activity, and expected increases in inlet gas and NGL volumes. The project, estimated to cost about $150 million, is expected to be on line in mid-2013, and is backed by significant new acreage dedications.

In addition to the Longhorn project, other North Texas expansion activity continues, with activity levels and growth capital investment expected to be similar to 2011.

With continued producer activity and new acreage dedications at SAOU and Sand Hills, we already have further expansion approved and under way in those two areas as well, with more expected in the future.

The benzene treating project is now on line as of January. This project complements the LSNG unit, provides additional fee-based margins, and is backed by a term user pay contract.

A $360 million fee-based 100,000 barrel a day Train 4 expansion at CBF is scheduled for a second quarter 2013 startup and, as we've previously mentioned, this capacity is fully booked for term, with high levels of frac-or-pay commitments. Further, due to the additional demand we see for fractionation capacity, the Partnership is working on an additional 100,000 barrel a day Train 5. We're continuing engineering, preparing permits, and conducting commercial discussions.

Our approximately $250 million international-grade propane export project, which are additional facilities at both our Galena Park Marine Export-Import Terminal and our Mont Belvieu complex, is proceeding. This project is expected to be operational by the third quarter of 2013.

We're currently pursuing incremental growth capital investment at all three of our new petroleum logistics terminals. Also look for us to continue our terminal acquisition and development strategy.

The $35 million fee-based expansion of Gulf Coast Fractionators -- we sometimes call it GCF -- where we have a 38.8% interest, is underway and is scheduled for completion in the second quarter of 2012.

In conclusion, we are pleased to report significant operating margin increases for each of our segments on a year-over-year basis. These results clearly illustrate the growth we are seeing across all there is of our operations. We feel good about the continued strong industry fundamentals, continue to increase our skill and diversity.

We had approximately $300 million of growth investments come on line in 2011, and as mentioned earlier, we have over $1 billion in announced growth projects coming on line throughout 2012 and 2013. These are attractive projects with attractive returns and attractive multiples to EBITDA and they provide a high degree of visibility on incremental fee-based business and a high degree of visibility on our financial performance through 2014. And we are continuing to develop high-quality projects to satisfy our customers' needs.

The Partnership delivered strong growth in 2011 and with our $1 billion in liquidity, a 2-point times pro form leverage ratio, strong distribution coverage, the Partnership is positioned well for future growth.

As Matt clearly outlined, with our January financings completed, we have essentially funded all our announced projects.

As always, we are actively pursuing third party acquisition opportunities but remain thoughtful and disciplined in our approach. We do not have to make a large acquisition to achieve meaningful growth, and with that consistent mind set, any future acquisition will be complementary to our strong outlook.

Again, we're very proud of our 2011 fourth quarter and full-year results and proud of all the Targa employees that made it possible.

Thank you, Operator. And to the extent anyone has follow-up questions, please have them log in now.

(Operator Instructions) Darren Horowitz, Raymond James.

Morning, guys.

Hey Darren.

Joe Bob, a couple of questions for you. The first, within Field G&P, given your comments around the exposure to the higher liquids content wells in the Barnett, how should we think about North Texas plant inlet and gross NGL production volumes ramping this year as more of those wells come on line? Is the progression going to be more linear from kind of the fourth quarter actuals, or do you think it's going to a little bit more lumpy?

That's probably more sculpting than I was planning on doing today. We do have lumpiness. What happens, people drill -- sometimes they drill several wells and then complete. But I think you will see 2012 over 2011 to have meaningful growth.

Okay. And then, last and final question for me, big picture -- based on the industry's announcements for additional gas processing, NGL pipeline, and NGL frac capacity, certainly including your discussion about a possibility for Train 5, when you look at the amount of NGL production that's going to grow over the next couple of years relative to the ethylene industry's ability to enhance consumption of ethane, do you think we get to a point, over the next couple of years, where supply outpaces demand and possibly alters the net-backs that producers are realizing at the wellhead, pressuring ethane prices? Any sort of kind of 30,000-foot-type color would be appreciate.

Sure; I'll give you my 30,000-foot answer, which isn't a whole lot different than my 30,000-foot answer probably on the last call. But as we look at it, the pet chem industry is heavily incented to create more effective capacity. As you come out of these turn-arounds, we may see pet chem effective capacity over 1 million barrels ethane a day. I'm confident of that because I don't underestimate the ability of engineers with profit motive and capital to squeeze out more barrels, and they've been doing that over the last couple of years, as you can see.

Then you have additional engineering and ultimately major world-scale projects being added. That's a little hard to measure because I can only go by when they say they're going to be bringing them on. Then you have constraints on natural gas liquids even getting to Mont Belvieu. Natural gas pipelines won't be on line for a while.

In the near term, that supply-demand balance is constrained by the pipelines. In the longer term, it's about what all have the pet chems been able to accomplish before the world-scale crackers come on? It gets a little sloppy, it corrects pretty quickly.

Thanks, Joe Bob.

Stephen Maresca, Morgan Stanley.

Good morning, everybody, and thanks for all the detail and color; it's very helpful. Just a couple of follow-ups. One of your peers is having a frac go down in the second quarter. Will there be any impacts to you guys positively from that? And are there any other fracs that need to go down for maintenance that you're aware of?

On an annual basis -- I think I can say this -- almost every frac goes down for some period of time for some maintenance, typically in the first or second quarter. I don't know which one you're referring to and I'm not the best expert on my peers.

Well, one of them mentioned yesterday that NB-1 would go down in May. It was (inaudible) that said it.

And you understand what that sort of does to supply and demand. If you have a frac go down on the margin, you have less [spectronic] being produced. You also have Y grade sort of piling up a little bit. That happens every year. On the margin, a frac going down improves pricing; certainly that spot pricing.

We're also aware Gulf Coast Fractionators will be going down late April for a turn-around, and coupled with the expansion that they plan to bring on line.

They've timed those together per COP. That late-April turn-down will allow them to bring on the additional 145,000 barrels a day as well, and they're expected to be off 35 to 40 days. We're a partner in that facility, so --

Okay, thanks for that. Second one, just review on the international propane, or the exporting propane project you have, and I guess the status of that and just would you see more opportunities like that, given kind of where the US is versus the world in propane.

These are global commodities. We have been exporting propane almost to the maximum extent we can right now, domestic-grade propane. That project is expected to be on, as we discussed in the script.

The additional opportunities -- and boy, that would be a high-class problem -- if we get to capacity it wouldn't be hard for us to increase capacity at our facility.

Okay. And the final question is -- you mentioned, Joe Bob, that Versado volumes will reverse this year, 2012, higher. And just briefly, what's driving that?

You bet. Of all of our Field Gathering Processing areas, we've had less activity at Versado than we have had at the other areas. 2011 relative to 2010, on an annual basis, was down for two reasons -- natural decline and less activity, but also we had more than normal operational issues associated with both winter and summer problems at Versado in 2011.

I expect that to return to normal. We also have some interesting, though not as robust, activity around there and our expectation is increased production over the course of 2012 versus 2011 due to both more normal operations and well connects. So it will tick up.

All right; thanks a lot.

Cathleen King, Bank of America.

Thanks, good morning and congrats on the results. First question for me, actually directed at Matt. Just wanted to confirm the TRGP 2012 guidance for cash taxes. Are you still -- do you think still a good number is it'll be about equal to 20% of pre-tax DCF?

Yes, we put that 20% out there last year and we're still comfortable with the kind of 20% effective cash tax rate coming out of pre-tax DCF; that's right.

Okay. And then, I know you gave the hedge-up date for 2012. Can you do the same for 2013?

Sure. For 2013, on the NGLs and condensates, we're about 35% to 45% hedged based on 2012 volumes. And then on the gas side, we're about 30% to 40% hedged.

Okay. And so, is there anything that you're waiting for there to add more hedges or are you just kind of going to do that throughout this year?

That's not all tracked; go a little lighter with our prior program. At the same time, Matt's percentages are based on 2012 expected volumes, whereas previously we were talking about 2011 volumes, and those volumes have gone up. Consistent with my discussion of the natural gas side of our equation, those percentages are of our Field Gathering and Processing.

But as an entity, as we increase our frac spread exposure, we start to have internal hedges relative to the gas short associated with frac spread contracts. So if that percentage goes down, we will be discussing it in that fashion with you-all because we're taking an internal hedge view of the frac spread that we see over the next several years.

You're saying if your NGL hedges go down, or your natural gas hedges go down?

No, I was speaking purely to the natural gas side. NGL hedges, you would probably see us increase somewhat over the course of 2012 so that the end of '12, we would be talking about a higher percentage hedge for '13.

Okay, fair enough. And then, I know you guys talked about this in the press release, so I was just looking for more color on the LSNG customers that chose not to use that facility this quarter. Does that just have to do with the vending treating expansion coming on line? Just what are the drivers of that, and do you expect that to continue?

There was a small period of time where it would have been unavailable as we brought benzene up, but that was not the reason. They are now linked -- benzene treating makes the LSNG facility even more commercial for the customer's application. It is a little spotty, driven by market forces; I won't go into all the details. But there will be times when it runs and times when it's running full out. But you don't have to worry about that in the near term because it's got a take-or-pay on both the benzene side and on the LSNG side, making it fee-based.

Got it. And then, on coastal G&P, the higher GPM volumes, the sustainability of that that you see going forward?

Two things. The GPM increases that we saw were adding winter gas to the mix from interesting connections because Dennis is well-positioned and has state-of-the-art cryotechnology. So not only do we try to get it there, producers like it going there. But it's mostly our ability to connect to the richer gas that has been the improvement.

Those trends, and that richer gas being produced by producers, will continue to make it available. At the same time, a little longer term than your question may have implied, the Gulf of Mexico as we see it is returning to normal, whatever that means, by the end of 2012. That will mean an up-tick in activity in areas where they can quickly get the supply to shore, and we've got a great catcher's mitt along the Gulf of Mexico and expect, in my term, get more of our market share of what I hope is an up-tick over the next few years from the Gulf of Mexico.

Additionally, we used to be talking about Mars B sort of outside of our forecast, but that's getting closer and closer. That's a great example of a sort of next-door neighbor platform, major development by Shell, that is dedicated to our system.

And also, in the Coastal segment, we saw an increase in wellhead production at LOU. So we're actually seeing drilling activity, which has been on the steady decline over the last several years, start to pick back up and we're seeing wellhead volumes increase at LOU, which is significantly higher in GPM compared to the gas we were getting off the interstates.

Okay, thanks; that's great color. And then, final one for me -- your previous 2012 gross CapEx guidance was about $500 million, and now that's up to $650 million. So could you just talk about the key drivers there?

Yes, if you look through the disclosure -- and we'll put out kind of more of the details on our gross CapEx in the Investor presentation -- you'll see posted where I kind of have a list of that. But the growth portion of that is going, in roundabout figures, from low $500 millions up to $600 million in gross CapEx. And the two largest piece of that difference is a $45 million additional expansion program at SAOU in Permian out in West Texas, and then $20 million of additional expansion CapEx in North Texas. This is gathering and processing, laying pipelines, compression projects in those two areas.

So that's $65 million of the delta, and that's the largest pieces.

Okay, great. Thank you so much.

Michael Blum, Wells Fargo.

Thanks; good morning, everyone.

Hey, Michael.

A couple of questions. One -- Joe Bob, when you talked about adding key POL exposure down the road, maybe I missed it, but can you explain what you're talking about there and where you're thinking you may be adding that exposure?

Sure. Without naming the specific platforms that we're getting it from, what our gas marketing group has been doing, and very much to the benefit of our Coastal Straddle plants, is accessing and purchasing natural gas off the grid; then we have the ability to process it. With that very large frac spread, frankly, I want to buy any wet gas we can to process it for the liquids. That's key POL.

Now, key POL, in our industry, I understand has a really bad connotation but I kind of like to call it what it is. In the old days, people had long-term key POLL contracts that could go upside-down. Here, we can purchase this on a very short term, but we have a long-term outlook that the frac spread's going to attractive and we've got a competitive advantage in terms of being able to process it at our Coastal Straddle plants.

So that may be more detailed than you were asking about, but that's what's driving part of that GOM increase at our Coastal Straddle plants, is just a flat purchase for us to process.

Okay, great. No, that's very helpful. The other thing I wanted to ask you about was in West Texas, as you expand the systems out there and as production grows, do you have adequate NGL take-away to get to Mont Belvieu?

Our NGL take-away -- I'm proud of how we planned ahead up to this point. I'm aware of other people who have had to go into ethane rejection because they didn't have as much pipeline take-away as they wanted. That has not occurred to Targa yet, and we talked about projects where we added take-away, particularly for SAOU, and since SAOU could take it down that additional interconnect, it made more room for us on our existing capacity on West Texas pipeline for Sand Hills and Versado.

That's been key forward-looking planning. We're getting to the point where Targa and the rest of this industry, as we develop additional gathering and processing in West Texas, will have to wait on the new NGL pipelines to be completed and interconnected, and at that point we will be able to get the capacity we need. You will probably see those new projects -- and we're working on multiple of those new projects, gathering and processing for [EMP] development in the Permian Basin -- coincide with the natural gas liquids pipelines being completed.

If you go all the way back and look at the MP activity, the real EMP is sort of waiting on that as well.

Great. Just two more quick ones for me. One, any update in terms of your progress on trying to expand the business in the refined products terminal area?

What we've said is that when we started this in December of 2010, we wanted to have three acquisitions made by the end of 2011. I think we met that pretty well. And that each of those would come with growth projects, and we just mentioned that all of those growth projects are being worked on at this point. I expect them to be significant contributors to fee-based income, 2012 and beyond, just those three locations.

We are working on other like deals. Obviously, that work is covered by CAs. We were going to continue that strategy and we've said publicly a couple of times that we may even bring on a terminal at a Targa location, so it could be developed as well as acquired. But we've got talent working on it and we find it highly complementary to what we do.

Okay. And then, last question -- could you just talk about the thought process, or the rationale, for the GP buying some of the units in the offering?

Sure, Michael; this is Matt. A couple of things. The primary reason that TRGP purchased the $50 million is we had the cash set aside of about $80 million, $90 million, and it was earning little to no return in the money markets. We were able to push out part of that tax liability that was disclosed at the IPO from really a seven-year schedule to a 14-year schedule through the tax election we made.

So we used a piece of that $50 million to buy units to earn, basically, just a better return versus the cash sitting there and earning money-market returns. But also, with that investment, we'll get additional tax shield in the form of additional depreciation on that purchase and it'll help shield some of the taxes for the next several years as well. So we had two benefits of the TRC for purchasing those units.

Michael, as you can -- we've got a lot of smart people here and they were looking at sort of other ways to get return on that cash and get tax shield. The understanding of NGLS was probably a lot higher, and our ability to explain to investors what we were doing, a lot higher there than some of the other things we considered.

Got it. Thank you very much for everything.

Vedula Murti, CDP Capital.

Good morning. Hello, Joe Bob.

How are you doing?

I'm doing well, thank you. In your prepared comments, I think toward the end, you did reference about acquisitions and that they're not necessarily integral in terms of achieving the current business objectives and everything like that. I think when we've had opportunities in the past to sit down with yourself or the other people there, you've indicated, I think, in the past that you were seeking to want to raise the credit profile of the Company such that you get to an investment grade. And that basically having a better mix of businesses in terms of more fee-based, stable as opposed to perhaps more at least perceived commodity-exposed types of businesses would facilitate that. And that an acquisition of some type would be very helpful with that.

Can you just kind of talk a little bit about that and where -- if that's the case, where you're thinking about what types of more stable assets would help you accomplish that goal?

Sure. I'll actually go to the part of the question that you asked in the middle and then get to the whole question, if I don't say I did it, Vedula. When we talk about achieving the metrics for investment grade, we see that as the result of the things we're doing. And we can see in our near-term headlights and our longer-term headlights the consequence of the projects we're adding -- increased fee-based, increased scale, increased diversity -- already happening. And I think ultimately could result in investment grade. But that's the result of the strategy we're pursing.

An acquisition, likewise, if it brought some of those same metrics -- scale, diversity, more fee-based -- could just get us there faster.

Okay. I guess I kind of was -- I guess, how important is it to accelerate the achievement of that? Because beyond just metrics, it's also the numeric classification of business risk or whatever that also kind of plays into that. There are companies that have plenty of good metrics but because their classification of business risk is lower, the agencies are somewhat hesitant sometimes.

When I start trying to explain to agencies, and perhaps they're moving views, I'm getting out of my league. But I believe that our outlook and what we're doing can get us to investment grade based on my understanding of the agencies today. The acquisition is not a, gosh, I've got to go do the X Y Z acquisition to get there. If an opportunity at value and fit comes along, its ability to help us with getting an investment grade will be one of the considerations.

This is Jim Whalen. I'd like to add to what Joe Bob said. What we're doing could get us to the parameters that one might say ought to be investment grade, given the current investment grade parameters by the rating agencies. Whether the agencies stay in those parameters or whether they select to make us an investment grade is their decision and not something we have control over.

Okay. And I guess my last thing is, at least it would appear to me that your currency right now would be quite attractive. I'm just wondering whether you kind of perceive that your currency provides you the types of valuation such that if an opportunity would present itself, that you'd feel comfortable with that.

Yes, we feel pretty good about that currency and we do think it's very valuable and we have no hesitancy to use that currency to do the transaction we think would be meaningful for us down the road.

We like both currencies, but I think you were also referring to the potential of using TRGP's currency. Our boards, plural, feel that both currencies are valuable and they won't view that as cheap. It's a nice thing to have in our pocket but it's not burning a hole in our pocket.

All right, thank you very much.

John Edwards, Morgan Keegan.

Yes, good morning, everybody. I'm just following up Vedula's question. Just curious, as far as where you think EBITDA needs to be to get to an investment grade. Any thoughts about that.

I think you've exhausted our thoughts on that one. (Laughter)

I think you've exhausted the thought. But EBITDA is one of the metrics so it's not, it needs to cross this line and we're going to get there. It's one of the things they'll look at. And so the higher the EBITDA, it changes other metrics. So it's not just an EBITDA thing.

Okay, fair enough. And then, if you could just elaborate a little bit -- you reiterated guidance and you were talking earlier in your comments about what your previous assumptions were. If you could talk a little bit about what your assumptions are now in that guidance reiteration.

We mentioned before and we gave you the prices that resulted in midpoint guidance of $530 million, and what we're saying here is we're reiterating that we're comfortable with $530 million, and that is in light of kind of current commodity pricing. And so we know the question that's on most investors' mind is, well, what does that mean in terms of ethane? And so that current $530 million of guidance is taking into account approximately $0.50 ethane.

Okay. And my other questions were answered; thank you very much.

Okay.

You bet; thank you.

Craig Shere, Tuohy Brothers.

Hi. Two questions. First, intrigued by this ability to pay methane prices for gas in the market that has a little liquids left in it and then process that out. I guess my first question is, is it reasonable to assume, as we probably all agree the frac spreads will be there for quite some time to come, that the market producers, whoever's selling that, is going to continue selling that at methane pricing? Is there a point at which the market just gets smarter, or you just have the resources and so they can't take advantage of it?

For Coastal Straddle plants, wet gas has to come to shore. And the Straddle plants are in a position to take that gas from the pipelines, process that gas, remove the liquids, and to put back an equivalent MMBTU amount to replace it. Because the MMBTUs for the liquids are worth a lot more than the MMBTUs for the gas. I would characterize that as a fairly available arbitrage.

And the Gulf producers are -- there's no way for them to --

They can build a large processing plant out in the water, build new pipelines for liquids back to shore -- it just doesn't work that way.

There is always the possibility that some of these volumes that are being processed by us under this arrangement could be converted by a producer into a traditional processing arrangement; that's always the case.

And that negotiation occurs in the context of, what does it look like to be processed as key POL instead? And we've always said, we're largely indifferent. We want to have a value negotiation on that PLP versus key POL versus --

Okay. So you'd be amenable if they wanted to change the effective contract structure. I mean, there is no contract structure for you processing something out the way you are.

If that particular situation of them having a negotiation exists, we're always trying to meet our customer needs.

Last question -- kind of an interesting point you-all made, and I'm sorry I missed some of the start of the call. But about the propane export opportunities. Because with the very warm winter, some others have been commenting about the prospect of propane even being an additional weight on ethane during the year because the crackers can't work with propane. So it sounds like you think that the global markets will resolve any overhang on propane. Is that what you're saying?

Let me take a step back. For months now, propane has been exported pretty much to the extent that it can be because of the price of propane in the United States versus the price of propane where there are growing propane markets. That's just supply-demand, but right now, the ability to export more is constrained.

This has been one of the warmer winters in the last 50 years compared to the last two years being some of the coldest winters over the last 50 years, and propane pricing has been affected. It's lower, inventories are just very, very full of propane, and propane is impacting ethane pricing on the margin. There's a certain amount of propane that can go into light crackers with the ethane, and I promise you the pet chems are making that economic decision every day, taking in sort of how much propane they can based on the crack spread of propane to ethylene, versus the crack spread of ethane to propylene. That's their job. They're optimizing just like we're optimizing.

You used the term a drag -- I believe that propane pricing is currently a drag on the margin to ethane pricing.

But short term and very long term, propane and butanes have to be exported and we think that's going to be an excellent situation for us with our Galena Park expansion.

They're global commodities. They go as the products that they can and the products that are most economic. Propane can go straight out, ethane can't go straight out. Ethane goes out at ethylene, primarily; propane sometimes goes out as ethylene. And that's a great facility to have over time.

Right now, we can only send out domestic-grade propane and we've been running three to four of the smaller ships, 145,000 barrel a day ships, out a month. After that project, we'll be able to run several ship out but there are just constraints right now. The opening of the Panama Canal will improve that as well.

When is that project going to be done, again? I'm sorry.

Third quarter of 2013, we estimate right now.

Great. I appreciate all the insights.

Okay, thanks.

Bradley Olsen, Tudor Pickering.

Hi. Good morning, guys. I just have one quick one, following up on Craig's questions on the propane export facility. With so much refining capacity coming out of the Atlantic Basin, either on the US side of things or over in Europe, we've seen major refineries getting shut down. Have you guys seen increased demand for propane exports as it seems like we'll see less propane supply from refineries going forward?

Whatever's being offset by refinery shut-downs on propane production -- and that's occurring -- I think with the amount of Y-grade pipelines and fractionation capacity, that will more than offset refinery loss of propane.

But as far as your dock project, you guys haven't seen incremental interest since we've seen all these announcements of refineries coming off line in the last three or four months?

We've got high interest from global players seeking to get propane to multiple markets.

Okay, great.

The interest in the export projects by a number of players is still the same; it's very high.

Okay, great; that's what I was looking for. Thanks a lot, guys.

There are no further questions on the phone lines.

Thank you very much for listening to us, thank you very much for participating in the call. If you have any further questions, please contact Matt, me, or any of the team.

Ladies and gentlemen, this concludes today's conference; you may now disconnect. Good day.