Targa Resources Corp (TRGP) 2012 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Targa Resources second-quarter 2012 earnings conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session and instructions will be given at that time. (Operator Instructions). As a reminder, today's call is being recorded.

I'd now like to turn over conference over to your host, Mr. Joe Brass. Sir, you may begin.

Thank you, Operator. I'd like to welcome everyone to our second-quarter 2012 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 second-quarter 2012 results to prior-period results, as well as providing additional color on our results, business performance, and other matters of interest.

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 the factors that could cause actual results to differ, please we refer to our SEC filings, including the Partnership's annual report on Form 10-K for the year ended December 31, 2011, and the quarterly reports on Form 10-Q.

With that, I'll turn it over to Joe Bob Perkins.

Thanks, Joe. Good morning, and thanks to everyone for participating. Besides Matt and myself, there are several other members of the management team that will be available to assist in the Q&A session. For today's call, let's start off with a high-level review of performance and highlights. We will then turn it over to Matt to review the Partnership's consolidated financial results, its 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'll provide a few more remarks; and then we'll take your questions.

We had a pretty good quarter on most operational and commercial dimensions, relative to 2011. On the positive side, field G&P inlet was up almost 9%, led by significant increases in North Texas and SAOU. Fractionation volumes at CBF and LCF were up, and Marketing and Distribution volumes were also up. These positives were offset by a couple of factors -- coastal NGL volumes were off, primarily due to planned and unplanned maintenance at VESCO; and prices were significantly lower for the second quarter of this year than for the second quarter last year.

Oil was down about 14%, and NGLs were down about 31%. But, Targa benefited from our growth, our fee-based diversification, and our hedging program. In that down-14%-to-31% pricing every environment, EBITDA was only down 5%, coming in at $123 million. We noted, in the June press release, that the Partnership is expected to have excess distribution coverage for 2012 and 2013, based on our continued distribution growth rates and a commodity price environment that was assuming $2.50 gas; $80 crude; and $0.75 average NGL pricing, which included a $0.30 ethane and $0.80 propane assumption.

Since June, the NGL price environment has improved, with ethane currently at about $0.38 per gallon, and propane at approximately $0.88 a gallon. Even without this recent price improvement, management believes the Partnership is well-positioned for continued increases in distributions to our unitholders, and that ongoing growth CapEx projects provide significant visibility for this outlook.

Our reported second-quarter adjusted EBITDA of $123 million resulted in distributable cash flow of approximately $85 million. Distribution coverage was 1.15 times, based on our second-quarter declared distribution of $0.6425 or $2.57 on an annual basis. Consistent with our 2012 full-year guidance given last fall, the Partnership's second-quarter distribution represents a 13% increase, compared to the second quarter of 2011.

Moving to a brief business overview. With the increased volumes and decreased pricing that I just mentioned, our Field Gathering and Processing segment reported a second-quarter 2012 operating margin decrease of approximately 33%, compared to second-quarter 2011. The hedges for field G&P, which we report as Other in our segment information, reduced its operating margin decrease to about 15%, or only $12 million.

Second-quarter 2012 Coastal G&P segment operating margin decreased approximately 39% over second-quarter 2011, primarily due to lower commodity prices and from lower NGL production, due to planned and unplanned maintenance at VESCO. This maintenance has now been completed.

Partially offsetting the decrease was increased volumes of richer wellhead gas processed at LOU, resulting from increased onshore Louisiana drilling in the Wilcox. Just as we saw volume improvements in field G&P, Logistics and Marketing also experienced volume improvements, driven by the same industry dynamics. The downstream division benefited from increased fractionation volumes due to CBF's Train 3 expansion, which came online mid-year 2011; from increased treating fees, due to our benzene project that came online this January; from petroleum logistics terminals acquired in 2011; and from increased LPG export activity, which benefits both our Logistics Assets and our Marketing and Distribution segments.

With these benefits, second-quarter operating margin from our Logistics and Marketing division increased 37% for the second quarter of 2012 over 2011.

That about wraps up my initial review, and I'll handed over to Matt.

Thanks, Joe Bob. I'd like to add my welcome, and thank you for joining our call today. Let's start with a review of the consolidated results. For the second quarter of 2012, the Partnership reported net income of $46.8 million compared to $55.2 million for the second quarter of 2011. Income per diluted limited partner unit was $0.35 and $0.55, respectively. As Joe Bob mentioned, adjusted EBITDA for the quarter was $122.9 million compared to $129.8 million for the same period last year. The decrease was primarily the result of lower operating margins in the Gathering and Processing division and in the Marketing and Distribution segment, partially offset by higher Logistics Assets operating margin and by higher commodity hedge settlements.

Overall gross margin decreased 2% for the second quarter compared to last year. I will review the drivers of this performance in our segment review. Gross maintenance capital expenditures were $15.5 million in the second quarter of 2012 compared to $21.6 million in 2011. Adjusting for the noncontrolling interest portion of maintenance capital expenditures from the Partnership, net maintenance capital expenditures were $13 million in the second quarter of 2012, as compared to $15.6 million in 2011.

Turning to the segment level, I'll summarize the second quarter's performance on a year-over-year basis. We'll start in the Gathering and Processing segments. Overall second-quarter 2012 plant natural gas inlet for the Field Gathering and Processing segment 665 million cubic feet per day, a 9% increase compared to the same period in 2011. Field Gathering and Processing operating margin decreased by approximately 33% compared to last year; driven by lower natural gas, NGL, and condensate sales prices, offset by increased throughput. These segment results do not include the impact of our hedging program.

North Texas and SAOU natural gas inlet volumes increased by approximately 23% and 12%, respectively, with slight decreases in natural gas inlet volumes at Permian and Versado. For the Field Gathering and Processing segment, natural gas prices decreased 50%; while NGL prices decreased 31%; and condensate prices decreased by 12%.

Turning now to the Coastal Gathering and Processing segment, operating margin decreased 39% in the second quarter, compared to last year. The decrease was primarily driven by lower commodity prices and lower throughput volumes, due to a decline in offshore supply and outages at VESCO, partially offset by increased inlet and higher liquids content at LOU, largely due to increased wellhead volumes. While the overall Coastal G&P segment gross NGL production decreased 17%, we expect the segment's gross NGL production for the third quarter to recover from the lower level reported in Q2.

Next, I'll provide an overview of the two segments in the downstream business. Starting with the Logistics Assets segment, second-quarter operating margin increased 37% compared to the second quarter of 2011. This impressive increase reflects the strong fee-based growth we are experiencing across our downstream business. Joe Bob will comment on our high-quality growth projects later in the call.

In the Marketing and Distribution segment, operating margin for the segment decreased 14% over the second quarter of 2011, reflecting a lower price environment, partially offset by increased LPG export activity and higher export margins.

With that, let's now move briefly to capital structure and liquidity. At June 30, we had $140 million of outstanding borrowings under the Partnership's senior secured revolving processing facility; with outstanding letters of credit of $70.2 million; revolver availability was about $890 million at quarter-end. Total liquidity, including approximately $90 million of cash on hand, was approximately $980 million, leaving us with ample flexibility to pursue organic growth and acquisition opportunities.

Total funded debt at June 30 was approximately $1.5 billion, or about 49% of total capitalization. And the Partnership's consolidated leverage ratio at quarter-end was approximately 2.9 times, below 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. Our hedge percentages are similar to how we hedged in years past. Relative to the Partnership's expected equity volumes from our field G&P segment, we estimate that we have hedged approximately 60% of 2012 natural gas, and 75% of 2012 combined NGL and condensate. For 2013, we have hedged approximately 45% to 55% of expected 2012 equity volumes for natural gas, NGLs, and condensate.

Moving onto 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.

Before we move on to TRC discussion, I'd like to discuss our previous estimated EBITDA guidance for 2012. First, as a reminder, we plan to provide financial guidance on an annual basis, and do not intend to adjust our previous annual guidance on a quarterly basis. We have provided, and may provide on occasion, additional updates, if conditions warrant. For example, we initially provided 2012 EBITDA guidance in the fourth quarter of 2011 that was based on $85 a barrel for crude; $4.00 an MMBTU for natural gas; and an average NGL price of $1.30 per gallon, which included ethane, at $0.75 per gallon.

Then, in the first quarter of 2012, as NGL prices fell significantly, we stated that our EBITDA range remained unchanged for 2012, and that we were still comfortable with the midpoint of approximately $530 million; which assumed ethane prices of $0.50 a gallon, with crude still at $85 a barrel, and natural gas still at $4.00 an MMBTU.

As commodity prices continued to decline and into the second quarter, we provided some additional information regarding coverage ratios in June, under then-current commodity prices. Assuming $80 a barrel for crude, $2.50 an MMBTU for natural gas, and $0.75 a gallon for NGLs -- which included a $0.30 a gallon for ethane -- we estimate a Partnership will have excess coverage while continuing its distribution growth. So we do not see a need for any further update to our guidance at this time.

Going forward, we expect to provide our annual financial guidance for 2013 sometime in the fourth quarter of this year. Before handing the call back to Joe Bob, I'd like to make some brief remarks about the results of Targa Resources Corp. On July 11, TRC declared a first-quarter cash dividend of $0.39375 per common share, or $1.575 per common share on an annualized basis, representing an approximately 36% increase over the annualized rate paid, with respect to the second quarter of 2011. TRC's standalone distributable cash flow for the second quarter of $17.3 million resulted in dividend coverage of just over 1 times the $16.7 million in total dividends declared for the quarter.

TRC's standalone, general, and administrative expenses in the second quarter were $2.2 million. AT June 30, the balance of the TRC HoldCo loan due 2015 was unchanged at $89.3 million. And there were no borrowings under the $75 million senior secured revolving credit facility. At June 30, TRC had a cash balance of approximately $28 million, which gives total liquidity of approximately $103 million.

That concludes my review. So, I'll now turn the call over to Joe Bob.

Thanks, Matt. I'll just make a few final comments. As previously mentioned, producer activity in North Texas in the Permian Basin is increasing volumes. As you probably know, we will install an additional 60 million cubic feet per day of processing in the Permian Basin by the end of the year, and expect that additional capacity to soon be fully utilized. And we are currently evaluating other Permian Basin plant additions.

Similarly, with the North Texas capacity filling up, we're glad that the 200 million cubic feet a day Longhorn plant is in progress, and expected mid-2013. On the downstream side, our CBF Train 4 construction continues, and is expected to start up in the second quarter 2013. And, we have previously mentioned, this capacity is fully contracted for term with high levels of frack-or-pay commitments.

Our $250 million international-grade propane export project, which adds facilities both had our Galena Park Marine export/import Terminal and at our Mont Belvieu complex to provide for the export of low ethane propane, is scheduled to be operational in the third quarter of 2013. The project is fully contracted.

We are currently executing growth projects and pursuing additional contracts and growth capital investment at each of our three petroleum logistics terminals, while continuing to work on additional petroleum logistics project development and acquisition opportunities.

So, as the Partnership's financial results and these organic growth projects indicate, our diverse set of assets performed pretty well in the second quarter, and are providing us very interesting opportunities for the future. We expect the impact from our highly visible growth projects -- which are primarily fee-based --- to provide the margin, scale, and diversity that will support continued distribution growth, even in the current price environment. And, with the benefit of substantial liquidity providing flexibility to expand our diversified midstream platform, the Partnership is positioned to invest in even longer-term growth.

So, in summary, assets performing well; highly visible, primarily fee-based projects, providing margin, scale and diversity; supporting continued distribution growth; and well-positioned to expand and invest in even longer-term growth. That is why we feel good about the guidance and updates that have been provided to you previously.

Matt reminded all of us on this call about the additional information provided to our annual guidance back in February. We're comfortable with that update at those prices. Matt reminded us, also, about our June update on 2012 and 2013 coverages at a price deck that is lower than the first half of the year and lower than current prices. We are still comfortable with that update at those prices. And he said, we do not see the need for further updates on the subject at this time.

So with that, we'll open it up to questions. I'll turn it back to you, Operator.

(Operator Instructions). Darren Horowitz, Raymond James.

Good morning. Joe Bob, as it relates to your comments around Permian growth, in order to keep pace with Avalon and Bone Springs production, do you think that producer demand could support maybe another two or three processing plant additions, and maybe an aggregate somewhere on the order of another 200,000 to 250,000 of MMCF capacity?

I think those numbers would be reasonable for just Targa. And I don't think you were asking -- were you asking just Targa, or across the industry, Darren?

I was just asking -- just Targa.

That's very possible.

Okay, in terms of lead time, as you guys are thinking about it, is it fair to assume somewhere around maybe 18 months, as soon as you get the green light? And maybe, from your perspective, if the scale that I just outlined is correct, aggregate costs somewhere around $250 million or $300 million?

The timeline is approximately correct. The $250 million to $300 million depends on what sort of capacity we're putting in place. But the numbers you sort of ranged earlier are -- you were a little too high for the range I heard. If you want to repeat it, we can check it.

No, that's okay. Shifting to the propane export project, based on what you're seeing out there from a supply/demand perspective, would it be possible for you to contemplate, maybe, another expansion? And when you look at the existing scale of your project, first from an incremental CapEx, is it possible to load of few more ships and maybe pick up another 1 million barrels of export capacity?

This is Mike Heim. We are already working on a duplication of what we have already announced. And even without that, we can shoehorn in an extra load here and there. But the basis under which we define the project has been fully marketed. So we're moving forward on to the next piece.

With a lot of interest.

Yes. And it's way down the road.

Okay. Last question for me, Joe Bob. If you could, from a demand perspective, just give us some color on whether or not you're close to the go-ahead on CBF Train 5.

No, I probably won't tell you about that. But we are having ongoing discussions; we've got room for it; the permits are in process; most of the engineering is well along the way. And when we're ready to announce it, you all will be the first to know.

Thank you.

Gabe Moreen, Bank of America Merrill Lynch.

Hi, good morning, everyone. Couple questions on the Marketing and Distribution side of things. On the short-term distribution opportunities, which you cited from supply and market conditions -- just wondering if we can get more color on that. Is that related to the export activity that was mentioned in the Marketing and Distribution side of things? Or is that something else?

Well, to your question, there are short-term opportunities, both with respect to the exports, where we've had a few more spot cargoes here and there. Just watch public reports; you'll see sometimes we squeeze in more than we tell people we can. Onshore, we have a very talented logistics group, and we find short-term opportunities to help people with supply/demand.

And was any of that short-term opportunity related to tight frac capacity in the second quarter? Even if that was the case, would that show up in that segment, too?

No, it wouldn't show -- not much would show up in that segment. We do have sort of ancillary fees associated with our fractionation. But that's not what we were referring to.

Okay, and I guess, did you realize any upside from the tight frac capacity in the second quarter?

Yes.

Okay. And then, last question on the Marketing and Distribution segment; also, about that multiyear propane exchange agreement. Just wondering if there is any color, in terms of settlements of that contract going forward and future payments -- how that might shake out over the rest of the year or in 2013, 2014?

No, I don't have a comment on that.

Okay. That's all I got. Thank you.

TJ Schultz, RBC Capital Markets.

Good morning. In field G&P, can you just expand on the comment in the press release that volumes were impacted by pipeline curtailments, and what you're seeing there? And also, the nature of some of the operational issues, and if any of that may spill into the back half of this year?

There were some operational issues in the quarter, with natural gas liquids pipelines, in particular. Those repairs and planned maintenance, for the most part, hopefully, are behind us.

And those were all third-party. Those were not (multiple speakers).

Yes, thank you.

Okay. In the LOU segment, or at LOU, you mentioned volumes were benefiting from the Wilcox. Can you just expand on current producer activity focused on the Wilcox now, and maybe your latest thoughts on the Tuscaloosa?

The Wilcox activity continues to increase, and we benefit from -- we capture our fair share of Wilcox wells. And it's very meaningful when that rich production is added to the LOU business mix. The Tuscaloosa Marine Shale -- I'm not sure that my comments are particularly helpful -- but from what I read, and what I hear from producers, I'm cautiously optimistic.

Yes. Fair enough. Thanks, guys.

(Operator Instructions). Ethan Bellamy, Baird.

Hey, guys. One quick one. Beyond Enterprise, have you caught wind of any other competitors sniffing around the propane export market?

Sure, everybody's got an idea about an export project. But they are very, very expensive where you can get to the water. It's densely populated or has a heavy industrial development, so the pipes to dock -- -- docks are easy, docks are cheap. But the pipe is the most important thing. And then, on top of all that, you got to have the right storage. And the most important thing is, you have to have low ethane propane. And if you don't have it, you're just wasting your time.

Okay, thank you.

I'm showing no further questions at this time. I would now like to turn the conference back over to Joe Bob Perkins for closing remarks.

Thank you, Operator. And thank you, everybody, for your interest and questions. To the extent you have any follow-up questions, please feel free to give Matt a call, or contact any of us. Thank you again for your time today.

Ladies and gentlemen, this concludes today's conference. Thanks for your participation, and have a wonderful day.