Targa Resources Corp (TRGP) 2015 Q2 法說會逐字稿

Good day, Ladies and gentlemen, welcome to the Targa Resources second-quarter 2015 earnings webcast and presentation.

(Operator Instructions)

As a reminder, this conference call is being recorded. I would now like to turn the conference over to Jennifer Kneale, Senior Director of Finance. You may begin.

Thank you, Nicole. I would like to welcome everyone to our second-quarter 2015 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 at www.targaresources.com. We will also be posting an updated investor presentation to the website later today.

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 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, 2014 and quarterly reports on form 10-Q.

Speaking on the call today will be Joe Bob Perkins, Chief Executive Officer; and Matt Meloy, Chief Financial Officer. Joe Bob will start off with a high-level review of performance and highlights. He will then turn it over to Matt to review the partnership's consolidated financial results, its segment results and other financial matters. Matt will also review key financial matters related to Targa Resources Corp. Following Matt's comments, Joe Bob will provide some concluding remarks and then we will take your questions. There are also several other members of the management team available who may assist in the Q&A session. With that, I will turn the call over to Joe Bob Perkins.

Thanks, Jen. Welcome, everybody, and thank you for joining us this morning. I would like to remind you that this is the first reported quarter that includes a full quarter of results from our Targa pipeline, or TPL assets, which were acquired in our merger that closed on February 27. As we describe our results from the quarter, the inclusion of TPL in our field, gathering and processing segment naturally will be the biggest factor in a number of increases, as we compare results to last year and to last quarter.

Turning to Targa's second-quarter results, our reported second-quarter adjusted EBITDA was $303 million as compared to $229 million for the second quarter of last year. This 33% increase was driven primarily by the inclusion of TPL's assets for the full quarter, which more than offset lower commodity prices. Our distributable cash flow for the quarter of $219 million resulted in distribution coverage of approximately 1.1 times. Based on our second-quarter declared distribution of $0.825, or $3.30 per common unit, on an annualized basis. The partnership's second-quarter distribution represents a 6% increase compared to the second quarter of 2014. At the TRC level, the second-quarter dividend of $0.875, or $3.50 per common share annualized, represent a 27% increase compared to the second quarter of 2014. Through the price swings we have seen to date in 2015, our field gathering and processing volumes continued to grow through the first six months of the year compared to the fourth quarter of last year. Natural gas inlet volumes increased in the second quarter compared to fourth quarter across eight of our nine systems. Overall field gathering and processing volumes were up more than 5% second quarter of 2015 over fourth quarter of 2014.

For the second quarter versus fourth quarter, we experienced a slight volume decrease in North Texas from reduced activity levels and from the impacts of severe flooding in the area. In the absence of the commodity price rally, we expect that North Texas volumes are likely to decline for the balance of the year. All of our other field operations had volume increases versus the fourth quarter of 2014. And as we look at expected volumes for the balance of the year in the Permian Basin, the Badlands and South Oak, we expect some continued growth in each of these areas. As you are all well aware, commodity prices continue to be volatile. In May and June spot crude prices rallied to over $60 per barrel, and recently fell below $50 per barrel. Yesterday WTI was about $46 per barrel. While there continues to be uncertainty on price and related activity levels, our current expectations for average 2015 field G&P volumes is 3% to 5% overall growth in 2015 versus Q4 2014. This is slightly higher than our previous guidance of flat to low single-digit growth on the same comparison. For the most part we are seeing continued activity around our field G&P areas of operations, but obviously less than we were experiencing in 2014. We are also seeing Targa's strong operational capabilities, reputation for customer service and willingness to spend capital selectively for attractive projects that have allowed us to capture some existing and future producer volumes from other midstream companies.

Predicting 2016 field G&P volumes continues to be more art than science. Producers have demonstrated a willingness to increase their pace of drilling in almost all of our areas if crude prices improved to, for example, $60 per barrel. However, our ability to predict 2016 prices, and therefore producer expectations for those prices, has not improved. In April we said that if commodity prices didn't improve from April levels, average 2016 field G&P volumes may be lower than 2015. Predicting 2016 field G&P volumes continues to be difficult, but I want to say that we generally feel a bit more optimistic about volumes than we did at the first of the year. As we said, we project that 3% to 5% volume growth from Q4 2014 to average 2015., which likely puts Targa at a better 2016 beginning spot than we were expecting. Looking at DoE US on-shore oil production data, we see a decline in April and May, which probably is a good thing for the industry. That's obviously the net result of some areas growing and some areas declining. We are seeing growth in our most important areas and expect that to continue, at least through the near term, proving that we have strong positioning. So we feel a bit more optimistic for 2015, and to some extent 2016, not because of an improved price outlook, but because of volume results to date.

Moving to downstream, our logistics and marketing division operating margin for the second quarter of 2015 was slightly higher than the same time period last year. As for full-year 2015, I guess we reaffirm our guidance that logistics and marketing division operating margin may be modestly lower than 2014. In the second quarter we exported approximately 5 million barrels per month of LPGs, which was 3% higher than the second quarter of 2014. Demand for LPG exports has been impacted by global commodity prices in the tight shipping market, but we are seeing continued demand for short- and long-term contracts. And we continue to add contracts for the second half of 2015 and beyond. We expect our LPG export activity levels to be at or above Q2 volumes for the remainder of the year. Given our contract portfolio, current market dynamics related to commodity prices, shipping constraints and increased competition, we expect overall second half LPG export operating margins may approximate what we have seen so far this year. Across our other businesses, we have worked hard through the first two quarters of the year to reduce operating expenses, especially in the field G&P businesses, without sacrificing safety or preventative maintenance and while still meeting customer needs for growing volumes. With the inclusion of TPL and the addition of assets throughout 2014 and early 2015, and because fuel and power consumption are included in expenses, it's difficult to see the savings in our reported numbers. When we look at our internal numbers for full-year 2015, we currently expect field G&P operating expenses to be approximately 8% lower than our budgeted expectations, despite the increase in volumes we've been experiences being gathered and processed.

Our performance in the second quarter highlights the diversity and resiliency of our business mix. There were some pluses and minuses, but overall it was a strong performance quarter in the context of weak commodity prices. Given the first two quarters of distribution announcements at TRP, our 2015 distribution growth over 2014 is likely to be towards the lower end of our 4% to 7% distribution growth guidance. At TRC we continue to expect 25% or better dividend growth in 2015 over 2014.

That wraps up my initial comments and now I'll hand it over to Matt. Matt?

Thanks, Joe Bob. I'd like to add my welcome and thank you for joining our call today. As Joe Bob mentioned, adjusted EBITDA for the quarter was $303 million compared to $229 million for the same period last year. The increase was driven by the addition of the TPL assets, which are reported in our field G&P segment. Overall operating margin increased 17% for the second quarter compared to the same time period last year, and I will review the drivers of this performance in the segment reviews. Net maintenance capital expenditures were $28 million in second quarter of 2015 compared to $20 million in the second quarter of 2014, driven by the inclusion of TPL operations, offset by some of the cost savings Joe Bob discussed across all of our operating areas.

Turning to the segment level, I'll summarize the second-quarter performance on a year-over-year basis, and we'll start with our downstream business. In our logistics and marketing division, our second-quarter operating margin increased 1% compared to the first quarter of 2015, driven by partial recognition of the payment received from Noble related to our condensate splitter project, increased terminaling and storage activities and higher fractionation volumes. Fractionation volumes increased by 3% versus the same time period last year. And overall operating margin from fractionation was down slightly as a result of lower system product gains and higher maintenance costs. We loaded an average of 5 million barrels per month of LPGs for exports and second-quarter 2015 operating margin from LPG exports was approximately flat compared to the same time period last year. In our gathering and processing division our field gathering and processing segment operating margin increased by 41% compared to last year, largely driven by the inclusion of TPL. Second-quarter 2015 natural gas plant inlet volumes for the field gathering and processing segment were 2.67 billion cubic feet per day, a 195% increase compared to the same period in 2014. The overall increase in natural gas inlet volumes was due to the inclusion of TPL volumes in West Texas, South Texas, South Oak and West Oak and increases in each of the following business units: 34% at SAOU, 23% at Badlands, 9% at Versado and 7% at Sandhills. Inlet volumes at North Texas approximated second-quarter 2014 levels. And as Joe Bob mentioned, were impacted by severe flooding conditions and subsequent impacts that affected the area throughout the spring. Crude oil gathered increased to 106,000 barrels per day in the second quarter, a 27% increase versus the same time period last year. For the field gathering and processing segment, commodity prices were down across the board, with NGL prices decreasing by 52%, condensate prices decreasing by 47% and natural gas prices decreasing by 45% compared to the second quarter of 2014. Our hedging activities, which mitigate a portion of these price swings, are included in our other operating segment. In our coastal gathering and processing segment, operating margin was down 70% in the second quarter of 2015 versus the same time period last year, as Gulf of Mexico and onshore Gulf Coast volumes continued to decrease.

Let's now move to capital structure, liquidity and other matters. As of June 30 we had $878 million of outstanding borrowings under the Partnership's $1.6 billion senior secured revolving credit facility, due 2017. With outstanding letters of credit of $21 million, revolver availability was about $702 million at quarter end. Total liquidity, including approximately $86 million of cash on hand was about $787 million. At quarter end we had borrowings of $124 million under our $300 million accounts receivable securitization facility. Year to date we have received net proceeds of approximately $375 million from equity issuances, including general partner contributions. From April through July we received approximately $263 million of net proceeds from at-the-market equity issuances and have raised $316 million in net proceeds under the ATM equity program year to date. On a debt compliance basis, which provides us adjusted EBITDA credit for material growth projects that are in process but not yet complete and makes other adjustments, TRP's total compliance leverage ratio at the end of the second quarter was 3.8 times.

Next I'd like to make a few comments about our fee-based margin hedging and capital spending programs for 2015. For the second quarter of 2015 our operating margin was 72% fee-based. For 2015 we now expect at least 70% of our operating margin to be fee-based. Since the end of the first quarter we continue to layer on hedges using costless collars and swaps. And for our current estimate of equity volumes from field gathering and processing, we estimate we have now hedged approximately 70% of the remaining 2015 natural gas, approximately 60% of the remaining 2015 condensate and approximately 30% of remaining NGL volumes. For 2016, based on our estimate of our current equity volumes, we estimate that we have hedged approximately 45% of natural gas, approximately 35% of condensate and approximately 15% of NGL volumes. Moving on to capital spending, we continue to estimate approximately $700 million to $900 million of gross capital expenditures in 2015, which includes 10 months of CapEx related to the TPL systems.

Next I'll make a few brief remarks about the results of Targa Resources Corp. Targa Resources Corp's standalone distributable cash flow for the second quarter of 2015 was $52 million and TRC declared approximately $49 million in dividends for the quarter, resulting in dividend coverage of approximately 1.1 times. On July 21 TRC declared a second-quarter cash dividend of $0.875 per common share, or $3.50 per common share on an annualized basis, representing approximately 27% increase over the annualized rate paid with respect to the second quarter of 2014. As of June 30 TRC had $460 million outstanding borrowings and $210 million of availability under TRC's $670 million senior secured credit facility, and $160 million of outstanding borrowings under TRC's senior secured term loan, resulting in about 2.6 times debt compliance ratio. At TRC we continue to expect a 5% to 10% effective cash tax rate for 2015 and in the near-term beyond 2015, an effective cash tax rate of less than 15%.

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

Thank you, Matt. Five months have passed since we acquired TPL. We really like the assets, our people are working as one team and the target team is continuing to mine opportunities across our combined footprint. We are working on connecting West Tex and SAOU later this year, enhancing options for our producer customers and allowing us to spend capital even more efficiently, with West Tex, SAOU and Sandhills connected together in the Permian Basin. These interconnections, you will recall that we connected SAOU to Sandhills last year, provide more flexibility to meet customer needs and to access existing capacity for growth. Along with the connection of West Tex and SAOU, we may also restart the idled 45 million cubic feet per day Benedum plant in Upton County. These projects do not require much capital. Given that we are operating at near capacity in the Permian Basin, the flexibility associated with connecting existing systems and existing plants and having an idle plant to restart is very valuable.

We also expect to complete the Buffalo plant in Martin County in 2016, with timing dependent on volume growth. We can have that plant completed and running in six months. Six month after we make the decision with our joint venture partner Pioneer Natural Resources, to go ahead with the final stages of construction. Similarly, activity around our Versado system in the Western part of the Permian Basin continues. We are adding another compressor station and laying a new 16-inch line to better access available capacity at our Monument plant, serving additional volumes from the Delaware Basin to the Southwest. This is an example of capital spending that isn't significant enough to be a single line item on our published CapEx projects. But it is a capital well spent, given the returns associated with bringing new volumes to an existing plant that has available capacity. In the Badlands we are making solid progress in securing right of way to lay pipe on reservation lands, which will allow us to secure volumes from wells that have already been drilled. Due to time required to move from right-of-way acquisition, to approval, to construction, this progress will likely not impact volumes until late this year or in 2016. Our Little Missouri 3 plant came online in the first quarter and we are continuing to see natural gas volumes increase to more than 50 million cubic feet per day in July. At the same time, crude oil volumes also ticked higher in July to more than 110,000 barrels per day. Given crude prices to date, we have seen a significant decrease in rig activity in the broader Bakken and in the number well permits filed in North Dakota. If you look at our systems across McKenzie, Dunn and Montreal Counties, we are positioned in one of the most active areas of the basin, as evidenced by the number of rigs running around our system relative to the rest of the basin. The right-of-way progress on the reservation is particularly important because it will allow us to lay previously delayed pipe and capture volumes that will support our system in 2016 and beyond.

We are now seven months through a roller coaster year related to prices for crude and NGLs, where in the second quarter alone Mont Belvieu propane prices, for example, moved from a high of $0.58 per gallon in April to a low of $0.31 per gallon in June, and we are at about $0.36 per gallon as of yesterday. During such times of price volatility, interconnected flexible facilities, including LPG storage, can become increasingly valuable. We're optimizing the use of our facilities for customer and Targa business needs. As domestic production has increased this year, we have seen continued demand for fractionation services. Construction on train 5 continues and it should be in service mid 2016. We are also through the first public notice period related to our train 6 permit, with a similar size and scope as trains 4 and trains 5. We continue to work closely with Noble as they near a decision point on determining whether to move forward with a new terminal at Patriot, a condensate splitter at Channelview, or some combination of both projects. Subject to final project scope and permitting, we would expect that the splitter or terminal or both projects would be operational in 2017.

In closing, we have been operating in an uncertain environment and I am incredibly proud of our execution across the Targa footprint in the second quarter. We cannot control commodity prices but our day-to-day focus is on safety, meeting customer needs, cost savings and efficiency of capital spending without sacrificing customer service or ignoring low-cost options which may benefit Targa in the event of increased activity in the future. Continued execution across our well-positioned diversified asset base has resulted in a strong first half for Targa. There is upside potential in the balance of the year, most obviously from the following: First, tailwinds associated with potential improvements and commodity prices from our current levels; Secondly, in the field achieving volumes that are greater than expected from existing production, continued success competing for take-away gas and efforts to continue to drive costs lower; And third, improving LPG export volumes and/or LPG export unit margins from our expected levels, perhaps as the market benefits from additional vessels coming online in the back half of the year. Targa's strong execution performance in the first half of the year is driving quarter-over-quarter distribution and dividend growth consistent with our expectations for the year and we will continue to execute in the second half of the year.

With that, lets open up the line for questions, operator.

Thank you.

(Operator Instructions)

Matthew Phillips, Clarksons.

Good morning, guys.

Good morning.

A quick question on the hedge book. You have an add back of DCF of $24.8 million. I was wondering how that squares with the $17.1 million, the gross margin on the commodity derivatives activity?

Yes, sure. Good question. The $17.1 million in the other operating margin is essentially a legacy Targa or existing Targa hedge addback. The TPL hedges in acquisition accounting were put on the books at fair value. And so, as we collect those proceeds, it's not hitting the income statement. So we're adding back the cash received in the quarter as those contracts settle. So you'll see that on a quarterly basis, as we essentially receive the cash from the TPL hedge book.

So the TPL hedges are added backwards, the legacy Targa hedges are on the income statement?

Yes, they are already in there, yes.

Okay, great. Thanks. And then, moving onto LPG exports. You all had about a 15% decline from 2Q, from 1Q into 2Q. However, looking at the vessel data, it looks like July was a record month for the US. Can you confirm if you've seen an uptick in July exports, and what that might mean for margins?

We have seen some continued -- I'd say we have seen some strong activity here thus far third-quarter. As Joe Bob said, that we would expect the back half of the year to approximate Q2. Things may gets a little bit better for us, but that's kind of what we're seeing right now.

Approximate 2Q on a margin basis, or a volume basis or both?

What we said, was approximate Q2 for the back half of the year on a volume basis. I would say we've seen things a little bit stronger than we had in the previous few months. But we expect volumes to approximate that second quarter.

We also said that performing better than that was a potential upside.

Right.

And we said that our guidance continued to remain for the downstream to perhaps be modestly lower in 2015 than 2014.

Okay.

We like to outperform expectations.

Yes. Well, margins from this have fallen off since 4Q for the past two quarters. But I mean, if volumes are coming back, I would think that might give you a little margin strength. Is that reasonable?

I think we've kind of tried to triangulate it all we can here.

Okay. Thank you.

Sunil Sibal, Global Hunter Securities.

Hello, good morning, and congrats on a good solid quarter.

Thanks, good morning.

A couple of questions from me. In terms of the LPG export volumes that you saw second quarter, is it fair to assume they were all primarily contacted volumes or you had some spot volumes in there too?

Yes, we haven't given a detailed breakdown of what is spot and what is contracted. I would say we have seen, as we've continued to over the previous quarters, a significant portion of our volumes loaded are contracted. But we were able to load some shorter-term or spot cargoes as well in the second quarter.

Okay. That's helpful. And then on the hedge book for 2016, it seems like on NGLs you maintained your hedge positions from the first quarter. I was wondering if you could give us some insight in terms of your thought process on that, and what levels you feel comfortable hedging that [expire]?

Yes, we have layered on some hedges, on the first quarter, we layered on some hedges. In the second quarter, we've actually layered on some additional hedges here early in the third quarter. We've added some costless collars. We've added some swaps for the various products, crude, NGLs, and natural gas. Given this environment, I don't think we're looking to kind of catch up to get back to those targeted levels all at once. But we do continue to take a disciplined approach, and try to continue to layer on some amount of hedges where it makes sense.

Okay. And then lastly, some of your producer customers have been pretty vocal about economics of building, even in the wake of this commodity price weakness. I was kind of curious, does that jive with what activity levels you are seeing in your efforts?

We, obviously we read the same public statements, then we have communications that aren't public. I would say that our broader knowledge is consistent with the public statements of our customer base. And we even referenced in our comments that, for example, some producers intend to increase in the activity levels at, for example, $60. We are encouraged by the activity levels to date, but we're not very good at predicting prices.

Okay. That's a very helpful, and that's all I had. Thank you guys.

Yes, thank you.

Brandon Blossman, Tudor, Pickering and Holt & Company.

Good morning, guys.

Good morning.

A follow on to the gathering and processing throughput volumes. So the comment was 3% to 5%, up [15%] over I believe Q4 of 2014. Is that just producer, your current customer base as the volume increase, or is there some presumption of market share -- incremental market share grab there?

The actuals achieved to date have been both. We tend to be conservative about our projections going forward. I would like to believe that we continue to benefit from takeaway gas, but we haven't overestimated that.

Okay. Fair enough. I'll try the LPG export at a slightly different angle here. Is there anything in the back half of 2015 into 2016, that would point to your volume throughput being different than the US in total numbers, as we see those -- that data roll out?

I'm not sure we've got a real good projection of forward US data. We've got a pretty good handle on how our volumes are likely to behave, and we built that into our comments, and the answers to the last question.

Right. Fair enough. And then more discreetly, on a per unit basis G&P OpEx looks like it's trending down very nicely over the last two or three quarters. What should we expect as far, again on a per unit basis, the trajectory through the back half of 2015 on that metric?

We're going to continue to work on maintaining the cost reductions that we've achieved, and realizing additional cost reductions. I don't have a prediction for you in terms of a percent trend, but the efforts are going to continue and our people are very focused on it.

So flat to down is a fair takeaway there?

We are pleased with the downward trend that we can see by our internal numbers, and that are harder for you all to see from reported numbers, despite increases in volumes. I mean, that's pretty extraordinary in the gathering and processing patch. And with expected continued growth for 2015 in those important areas, we still expect to do so without increasing our cost.

Okay. Awesome. Thank you very much.

Darren Horowitz, Raymond James.

Joe Bob, a couple of quick questions on field G&P, and I appreciate the comments around the plus 3% to 5% overall volume growth, even net of what is going on in north Texas. But what I am more concerned about is the margin expectation. To the extent that you can comment, just trying to get a feel for the lower operating expense you expected continue through the back half of this year, with regard to the aggregate impact on gross operating profit for field G&P, how much lower? Or what's the variability in terms of your back half of 2015 margin, versus what you already experienced in the first half of 2015?

As we look second half versus first half, we expect to achieve similar or better, and I think that's about as precise as I can be.

Okay. Let me jump over to North Texas specifically the amount, from a contractual perspective, POP contracts. I think previously you had said, that somewhere around 30% of the 2015 margin was going to be POP, and a lot of that was really around North Texas. I'm just curious, now that you got half of the year behind you, and you are looking forward with the TPL assets, what's that level of expectation for POP exposure in the back half of this year and into 2016? And from a re-contracting perspective, as maybe you think about shifting some of that exposure to a more fee-based composition of cash flow, how do you think about the margin degradation, maybe being offset by volume improvement or cash flow security

Yes, hey, Darren, it's Matt. I just want to talk about North Texas, just to clear one thing up there first, the North Texas is a POP business up there. So we do have some fees kind of embedded in those contracts where there's gathering or compression or others. But we think of North Texas as POP, and we don't really see that changing as we come, back half of this year and into 2016.

Okay. And then last question from me, and Joe Bob, again, I appreciate it being difficult to predict crude oil prices. We struggle from the same affliction. But I'm wondering, just with regard to the Badlands assets, McKenzie, Dunn, Mountrail counties right. Like a lot of that hinges, not just on the absolute price, but on the discount to TI, because I think that's probably where the greater challenge is. So what are producers telling you, just from a net back perspective, in terms of where the cash price gets more economic?

As opposed to me describing what the producers are telling me and not telling the public, what I can see is activity at the price levels that we've seen since the first of the year. And that activity as you know isn't driven by the spot price in the particular month, but their outlook for those prices. It's one of the best oil basins of the world. The differentials as a percentage have moved around since the first of the year.

Thank you.

That's about as best we can describe. And like we said, we have several reasons in the Bakken to be optimistic about volumes. Even at low North Dakota activity levels, the activity levels around our system are better. And given the activity levels around our system, we still have some backlog of volumes that we are going be getting, to thanks to progress on rightaway on the reservation, but it's going to take us a little while. And thanks to the progress at the Little Missouri 3 plant provided for helping to put out flares, and meet customer needs of gas production that was already there and have not been captured

T.J. Schultz, RBC Capital.

Hey, good morning.

Good morning.

On field G&P volumes, I guess, the question is on 2016. I think the optimistic outlook that you guys commented in the remarks, is just the fact that you are likely to have a better beginning level? Or is there something specific, maybe you guys gleaned here were recently with the swing in crude to $60, and now back down, that gives you more optimism maybe about producer activity, kind of within this oil range that we've been bouncing around?

Our feeling a bit better about it, has to be in the context of a lot of those things you just mentioned. But it wasn't kind of the short-term movement in prices. Number one, and the primary reason is that volumes have performed better than we expected, despite prices over the first half of the year. If you took our last quarter call, for example, spot prices and forward prices are lower than our last quarter call. But given those prices, the volumes have exceeded our expectations. So the volume to price relationship is important in our feeling a bit better. And then, yes, the US data around supply and demand and a breakover on crude volumes which occurred a little later than we thought it would, I think works into the mix as you referenced. But that primary thing, and we tried to say it, is we feel a little bit better, because volumes have done a bit better in spite of pricing.

Okay. Thanks. On exports, I think you said you are adding contracts. Just any color on the appetite for short-term versus long-term contracts? And then also, just any update on the constraints that ship availability is having for you guys through the rest of the year?

We've added [both] since our last call. We are more contracted, than not contracted in the near term. We know that ship constraints are a factor. Our ability to predict exactly how fast those additional ships come on, or where they come on, is not as good as other analysts out there. But we know our customers have felt the ship constraints. We sort of gave you an expectation, and then also pointed to it as a potential upside, relative to our overall expectations.

Okay. Thanks, Joe Bob.

Jeremy Tonet, JPMorgan.

Good morning.

Good morning.

Congratulations on the good quarter there. I just had a question on the TPL hedge book, it came in a bit stronger than what we were anticipating. So just wanted to see if we have a static commodity price environment, whether the pace of cash gains is going to be stable through 2015, or if it's more front half of the year weighted?

So we'll be filing the Q here shortly. It will have an update of all of the hedges that we have on. So it really depends on your commodity price expectation for the amount of cash that we'll receive in any quarter.

Exactly. I was just curious if it was -- the contracts were more weighted to the first half versus the back half for the TPL hedges you picked up.

Yes, we will have less amount hedged, and at lower prices kind of generally as we go through time. So I think that's a fair assessment.

Got you. I appreciate that. And Joe Bob, I wanted to touch on some of the things that you are saying before. I know it's a very difficult question. But I'm just wondering system-wide, if you're looking at the futures curve, is there a number in your mind, where you feel good about continued growth if [2016] is at $50 versus $60, is there any goalpost you could give us there, as far as how you think the Targa assets would react there, and when you would see growth?

Boy, I wish I was that smart (laughter). Honest to goodness, I wish I was that smart. I think I kind of admitted already, that our first of year expectations, volume connected to price, volume was a little better than the price connection. I don't have a magic milestone or goalpost for you out there.

Fair enough. Just one last one from me. As far as the Noble payments around the splitter, I was just wondering for modeling purposes, does that stop at a period of time? Should we be taking that into consideration?

Yes. It stops in the third quarter, part way through the third quarter.

Got you. And is that anything material that we should note, just so we don't overestimate there?

Yes, good question. We haven't given the specific number, so it is going to be tough for you to triangulate. I'll just say that it's not large enough, so we had to disclose it as a dollar amount variance but --

And we only disclose we have to disclose.

Right.

As we put that out when we first -- recognize we have confidentiality -- we, first of all, really good relationship with Noble, and we have confidentiality requirements. Those confidentiality requirements say we disclose, what we have to report, and we spent a lot of time with accountants to make sure we got that right.

Fair enough. Makes sense. Thank you for the color.

Shneur Gershuni, UBS.

Hello, good morning. I was wondering if you we could expand on the integration process with [Atlas] a little bit. It sort of sounded like if I heard correctly, that you might be seeing some very large capital efficiencies. I believe you said at one point, that you got an idle plant that you can start up and connect and so forth. I was wondering if you could sort of lay that out for us, as to how that could possibly impact margins on a go forward basis? Is there a lot more opportunities like this, where you can have capital efficiencies, or I guess, capital avoidance and still pick up volumes. Does your margins further expand with capacity utilization ticking up. I was just sort of wondering if you could expand on that a little bit for us?

Yes, I certainly understand the question. Five months have passed since we did the acquisition. Assets are terrific, particularly in the Permian Basin, mix terrifically with our existing assets. People are working as one team, one Targa team for Targa bottom line.

We did sort of give early conservative synergies to you all, which makes you want more, and I understand that. You'd like more detail. You'd like the variance analysis against the plans. But what's really going on, is we won't have a separate report of the progress on those synergies. Instead of the way that we're managing it, the way we're working it, is those become embedded in our results. It's one of the ways that we've kind of outperformed our expectations, and it will continue to be. You pointed to a couple of the factors, and we alluded to them. When you combine those systems, you have capital efficiency opportunities. You have the opportunity that we've always had, but even more so of getting gas to available capacity, and we have started up idle plants throughout our whole history. It's just another opportunity to do so, for the benefit of the combined system. I hope that's helpful. But I also know it's not exactly what you wanted.

Maybe I'll ask this a little differently (laughter). A classic analyst question. So should ex commodity impacts, I mean, the commodities can to move up and down and so forth. But should we expect the IRR on capital deployed at least over the next six to nine months, to be significantly higher than it has been in the past? Or so differently should we see ex commodity impact margins improve, just as you are able to take advantage of these capital opportunities? Is that a fair way to be looking at it?

I understand that question, and it's an easier question to address than the question from like last quarter, are your IRRs going to go down in this environment? In reality, when we are working hard in this environment doing a lot of smaller projects, taking advantage of the low hanging fruit, benefiting from takeaway gas with small expenditures, those returns are very attractive. Okay? They are very attractive against smaller dollar amounts, and that's showing up in our bottom line. I like expanding on the answer to your question, because it works against the hypothesis which is not -- we're not seeing as the case, that our returns are going to go down. We may not be spending as large of chunks of dollars, which is good and proper in this environment, to take those and defer them until needed. But the dollars we're spending are getting attractive returns, and I think that flows to our bottom line.

Okay. No, that's actually a great answer. As a follow-up to all of the questions about your positive outlook with respect to the Permian. I think you started off by saying, you hate, we were surprised on the volume side, and so therefore were sort of carrying it through and so forth. I was wondering if maybe you could expand a little bit as to why the volumes are outperforming expectations? Is it producers using better completions? Are they targeting better wells? Are they drilling more wells than you initially thought? I was just wondering if you could sort of carry that through, as to why volumes have actually been performing better? Not that that's a bad thing, but and to why that will continue to be the case over the next six to nine months?

First of all, kind of the last factor in your question, it's not because they're drilling more wells than we thought, not appreciably to any extent. But it is a combination of some of the factors that you mentioned and some others. I would start with they are drilling with more limited budget, in the best spots, and their technology has improved, such that the best spots are more productive than they have been in the past. And those best spots are where our systems are, and that's to a great extent, and that's the reason for us having underestimated it. Maybe we were too conservative. I'm not terribly surprised, but is a pleasant surprise on the margin, for the volumes to be outperforming where the prices have been. Secondly, we have been successful, because we're working hard, willing to selectively spend capital, and have a very good reputation with customers out there, that we're winning packages of gas that are coming up for renegotiation on the margin. And strong competitors do that during tough times. Those two factors maybe a little bit too of, when you have a little less activity and you have been working to catch up all along, you get pressures down where you want them to be in the field. That benefits our customers, and it benefits us on volumes. Those are kind of the three areas that are in my head. And it's not because drilling was a whole lot higher.

So weaker competitors with poor balance sheets are basically disadvantaged right now, relatives to somebody like yourself? Is that a fair way to think about the volume, the market share comment?

I think I'd put a little softer than that (laughter). It is not just a balance sheet, it is also the reputation for customer service.

Okay. Great. All right. Thank you very much, I really appreciate all the color.

Michael Blum, Wells Fargo.

All right, thanks. I will try to be brief here. Just curious for what you're seeing from the perspective of ethane rejection, if there's been any change in the way that you're running your plants?

For running our plants, we've looked at that every day, and we're doing more, not less ethane rejection where we can.

And would you say that's from what you see out there, from other volumes that come into your system, is that sort of consistent?

Yes, broadly so. We see a lot of the pipelines as you know coming into our CBF fractionation facility, and certainly across the board you would characterize it as getting lower on ethane content, meaning that more ethane is being rejected.

Okay. Great. And then, you gave some pretty good updates on the various projects that you have in the backlog or the potential backlog. So is it fair for me to just takeaway from that, that effectively you're still seeing pretty good demand for incremental projects, and you haven't seen any real material change? Which I think of something that a lot of people are thinking about.

Well, our backlog, it's a list of those defined products that people have seen in the permitting process or customers have talked about us working on for the most part. There's not a decreased demand for any of them. As we said really, back to the first of the year, it's a matter of when, not if for almost all of those products. Increasing NGLs coming into Mont Belvieu continue. They're coming a little bit slower than we might have expected in the early part of 2014. But demand is still there, back to that, when, not if.

Okay. And then, Matt I apologize if I missed it. I was writing quickly. Can you just repeat what was the Q2 ATM equity issuance?

Yes, I said that -- in the script -- I think it was 263, yes $263 million and that also includes July, which I think -- it will be in our Q, as a subsequent event of about [$23] million or so.

Okay, great. Thank you.

That includes the GP stuff?

That was ATM, so the G&P amount was a separate number that we gave.

Which we also put in Q.

Yes.

That's why my number was off.

John Edwards, Credit Suisse.

Yes, thanks for taking my questions. Just back to the LPG export, just asking it a different way, I think you said there was a mix of spot and contracted, would it be fair to say the majority is contracted?

Well, we're setting a record on trying to drill down on that (laughter). I know that some of our competitors may give more detail than we do on our export volumes and our mix of contracts. We are really making a competitive decision on how much we want to say, for the good of our unitholders and the good of our shareholders. So I appreciate you drilling down but.

Okay.

But it is correct, there is a mix. Yes.

Okay.

And John, just the other thing I want to make sure is we take away, is we have said the majority of our volumes are on contracted volumes. I don't want you to take way that the majority is short-term or spot contracts.

It sounded to me that like we were trying to figure out, if on the increment that was added, what was the percentage of increment added?

No. All right. Fair enough. And then, just kind of extending some of the earlier questions asked, but you have expressed optimism in 2016 based on the volumes that have materialized so far. And I was just curious to what extent pricing might impact that optimism? If we stay in this sort of sustained price environment that we're currently in, rather than the improvement that a lot of people are calling for, I'm just wondering how would that temper your optimism if at all? I mean, if perhaps that people are responding to things based on price expectations going forward, not the current [sloppy] environment that we're in.

We are feeling a bit better about the volume outlook for the remainder of the year and for 2016 is not based on looking at a single case or a single price. It's based on us looking at multiple forecasts related to multiple pricing and what we think is likely. The most important thing for -- that we are communicating is that our volumes and our volume outlook at whatever price scenarios we're looking at has done better. It did better against the actuals, which actually were lower prices than we expected. And going forward in price environment that's flat for today, our volume feeling would be better than it was at the beginning of the year for that same price outlook, and if you get to the higher price outlooks, and have volumes greater than we expected for higher price outlooks. Does that make sense to you? (multiple speakers) Otherwise we're trying to predict the prices and I'm not trying to predict the prices.

Selman Akyol, Stifel Nicolaus.

Thank you. Congratulations on a good quarter in light of a tough market.

Thanks.

If we could just continue on the volume question for just one second, because I haven't heard you kind of addresses this. And I understand your cautious outlook on volumes, and you are pleased with the way things came in. But in terms of just a forward look, any way you could talk about what the weather impacted you this quarter in terms of your volumes?

This quarter's weather impact was primarily a North Texas, and we pointed to it, because it was a fact in some of the producers in the area had pointed to it. It's difficult to extract. We might have been flat, quarter to quarter in North Texas if it weren't for the weather impact. I don't know that for a fact. I do know that as I project where we are, and where we are going, that it was appropriate to signal that unless there's some bump due to price, North Texas is likely to continue to decline. Not dramatically, but to continue to decline. When we said it weather impact, it was not just the flood. It was the impact post-flood on electricity connections, even some washed out pipelines that took a while to repair, primarily on the electricity side, because they just didn't have the crews to take care of everything at once. And some of the more remote locations didn't get taken care of for quite a while.

Thank you very much. On the terminaling and storage fees, there was some incremental there. Is there more to be repriced, or is there any additional color you can give there?

Yes, I think the comment Joe Bob referred to is just in an environment where you have some contango in the forward curves, there is storage becomes worth more, and there's some opportunities for additional income.

Okay. And then the last one for me when your coastal plants, is there any outlook for idling any more plants there, or should we assume that is done?

The consolidation of the coastal straddles has been going on for in many ways, much of our career. We've said before that Targa is well-positioned to benefit from those consolidations. We have one of the strongest positions. We would like to call it a catcher's mitt, and as less efficient plants are idled, we tend to capture more than our share of the remaining gas. And I just wanted to credit the people working the coastal gathering and processing for figuring out ways to save dollars, make more money with less volumes, get richer gas when it's available, and the producers are working to get richer gas. It's a small part of our operating margin, but boy did they work hard to keep that small part as high as possible.

Thanks very much.

Faisel Khan, Citigroup.

Thanks, it is Faisel from Citigroup. Just a few questions, in the --from your press release. The condensate pricing differed quite substantially from field gathering to -- from the coastal gathering systems, and that difference was sort of wider in the quarter versus last quarter, even on a percentage basis versus last year. Can you kind of discuss what is going on there, is that quality differential? Is that a sort of a real transportation differential? It just seems a little bit wide, even looking at the WTI versus LLS.

Yes, coastal is usually different than the field, it gets priced more at the LLS, so you have to look at the differentials from where we're picking up that coastal in the field, relative to the LLS, which is typically it tracks closer to Brent. So it's just those various differentials. I will say that the condensate, it does not have a big impact on our operating margins, so it is not something that we focus a lot on. But it is due to those impacts.

And occasionally there are quality differentials that might impact a single quarter. We market it the best we can, relative to supply and demand in the localized markets.

Obviously, because the differentials obviously narrowed in the quarter. So I was just try to understand if maybe there is a constraint to there -- in that -- I guess, in your field gathering system.

No, I don't have a -- I think we are more talking about market dynamics than anything.

Yes, fair enough. And then, in your press release you guys mentioned that the fractionation results were impacted by lower system products gains. Can you discuss it exactly what that means? Is that just -- are you talking about rejecting ethane, or are you talk about sort of -- ?

No, it really has more to do with our Mont Belvieu complex and volumes going through our fractionator. There is opportunities to blend the various products at the back of our fractionator, before we sell those products to market. So there is pluses and minuses throughout the system, and those amounts vary from quarter to quarter.

Okay. And then also you guys discussed in your results also lower refinery LPG supply. I would've thought with refiners running all out in the quarter that LPG supply would have been up over the quarter. But because of talking about it being down, just trying to understand that dynamic too.

I understand directionally what you're describing. But what we've always say in practice is, about the time we think going to be getting higher supplies from refineries we don't. It is pretty difficult to predict. What we're really good at doing, is managing it in the short-term, to do the best with what we get. There were some refining downtimes on the West Coast. Don't really want to point or pick at any particular customer, but that shows up in our overall result.

Right.

Okay. So you guys have access to the California refining LPG?

Yes, that's --

Okay.

Some of those are our customers, and what we also know on the margin is that, not just pointing to West Coast, some refinery customers have actually used some of those products as fuel on the margin. So it's a difficult trend to track. What we are is very opportunistic, in adding that refinery services business to the overall propane closeout marketing business.

Okay. And last question on your hedges, just want to make sure is there no -- is there a lag effect from the hedges? Or is it -- as you guys showed the volumes in the quarter, those volumes sort of are represented through your hedge contracts. I mean, there's no difference from quarter to quarter (multiple speakers) how do you recognize that?

No. There's no lag. As the cash comes in for the month that we've hedged, we will recognize that as either income or we'll put it as an add back on cash flow statement, to the extent the cash is received.

Okay. Makes sense. Thanks for the time, appreciate it.

Chris Sighinolfi, Jefferies.

Hey, guys, This is Corey filling in for Chris.

Hey, how are you?

Not bad, just a quick question. I'm sorry to go back to Noble really quick, What is the threshold, out of curiosity for what you have to disclose?

Sorry. Good try (laughter). I understand the question. I can't answer it. And by the way, absent a Noble contract, I am not sure that I would get a concrete answer from our internal accountants or our auditors anyway. They sort of know it, when they get there. And at some point we say, okay, I think I understand, and we report it accordingly.

Got it. And I guess, just to dovetail on that, I'm assuming because it your recognizing revenue before anything's in the ground yet, you are assume the project is a go. Just out of curiosity, what would be the impact to you guys, positive or negative, if the project was a no go?

I am not prepared to discuss that either.

Okay.

What we said when we announced the deal, is that relative to the original [channel] view splitter agreement, we were not economically disadvantaged by renegotiating the agreements. And that's all I can say.

Okay. That's helpful. And then, just a last question from me, and then I apologize if I misunderstood what you said. I think you said with respect to contracts, you are more contracted, than not contracted in the near-term. That implies, let's call it, 3.25 to 3.5 million barrels a month, just wondering how we compare that to last month what you said quarter about more than 4.2 million barrels a month for 2015, and then 4.2 million barrels a month in 2016?

Okay. Just to be clear, we didn't say -- we said more, which is greater than half. Okay? So we're not saying we are more or less than the previous number that we gave. We just said, that we're not going to get into the dialing in, the exact amount that we're contracted and the exact amount of spot. So I wouldn't read from that we are less.

Okay. So you can't reiterate if you are in line with the 4.2 million barrels a month in 2015?

Oh, I could, but I'm not going to.

Okay (laughter). I appreciate it.

[Garth Brody], Bank of America Merrill Lynch.

Hey, guys, just a quick one for you. I think you mentioned when you give your hedge numbers for the NGLs, that you were 80% hedged in 2016, versus 30% for the rest of this year? Did I hear that right, and if I did what's the -- ?

No we're not a 80% hedged? I think we're 16% for NGLs, I think said 15%.

15%, that would explain what I misheard. That's perfect. Thank you, guys.

Eli Lipsky, Citadel

Hey, guys. It's Eric McCarthy with Citadel. I was hoping you could elaborate a little bit on the point you made about transitioning packages of the gas, what basins are you seeing those in, when, where are there further opportunities?

Okay, I'm not -- you may have interpreted transitioning from a term I used as takeaway, kind of going back mostly we're finding volume increases from our dedicated contracts with existing producers. Those volumes were better than we thought in an our important price sense, the Badlands the entire Permian Basin. West Oaks South Oak surprised us to the positive, particularly those large Permian Basin positions in Badlands are coming from our existing acreage. But across the board, we've also been successful and that's a compliment to our people, of winning a whole lot more, many, many more deals, and much, much more volume on takeaway then we have lost. Takeaway being, a contract came up for renewal with someone else, and we got it. Now that's on the margin. It's a positive on the margin, it's biggest part of the positive surprise. But I don't have more information to provide you, other than to say that we track it by deal, and track it by volume, and report that to our Board. And the wins are a whole lot more than the losses. But mostly, the positive volume surprise is from our existing contracts in our existing dedications.

Okay. So no real color that you can offer on -- is that part of what drove the Eagle Ford volumes, or is it producers shifting to different processors in the Permian? Nothing more you can offer?

I will say that my win/loss ratio on volumes or deals, is way to the Targa side on every basin.

Okay.

Thank you.

Ethan Bellamy, Baird.

Joe Bob, how would you handicap the potential for elimination of the crude oil export ban, and if that occurred, what would that do to your strategy?

Everybody frowned at me, because they thought I would start talking politics.

I would love to hear you do that.

Well, we're running out of time.

I won't. I don't handicap anything moving fast in Washington. If it were to happen, we're always trying to help as a midstream player. Everybody just did a big sigh of relief. I think that is as much as I can do with the intro.

So just a follow-up there. How does that potential outcome factor into your risk analysis on things like the condensate infrastructure and agreement with Noble?

That question I can't address. Recognizing even with export bans or opening up condensate, you still have needs for particular assets. Student body won't go right or left based on a change in the law, and our customers with their contracts and their portfolio of opportunities, will decide whether those investments continue to make sense. That's what we'll respond to.

And absent near-term moves in Congress, that is impacting people's longer-term outlook about assets. Even with the opening of selected condensate exports, you continue to need splitters on the US Gulf coast to some extent, within refineries, outside refineries, where it's going to a splitter is on the other side of the water. Where is the best place to be importing products and moving it around? That is a global -- it's a global market with of lots of solutions.

Thanks much. I guess, I'm asking the right questions if you tell me no (laughter).

Boy, I'm going to get a bad reputation. I really try to answer all of the questions. We can only answer some of them so much.

Charles Marshall, Capital One Securities.

Good morning, everyone.

Hey, good morning.

Just a quick follow-up on your opening comments, sorry, regarding distribution growth for the year coming in -- expected to come in at the lower end of the range. Given your sort of better expectations in the back half of the year in field G&P volumes et cetera, is your guidance range at the low-end, does that includes your updated forecast for the remainder of the year, or could that slide more to the right, on the higher end of the range depending on where (inaudible) could go?

No, we took into consideration both our outlook in the field, and our logistics and marketing business into that 4% to 7%, and then, on the towards the lower end of that. We're also part way through the year. We had a distribution increase of $0.01 in the first quarter and then $0.005 in the second. So then, as we're just part way through the year, so we have a better handle on just how the average is going to shake out.

And then, we try to drive it smoothly.

Okay, I appreciate that. On one last quick one. Regarding the potential ethane export project, is there any update there that you can provide for us?

No update.

Okay. Thanks.

Thank you. I am showing no further questions at the time. I would like to hand the call back to Joe Bob Perkins for any closing remarks.

Thank you, operator. Thank you everybody for your patience and interest. To the extent that you have any follow-up questions, please feel free to contact Jim, Matt or any of us. Good day.

Ladies and gentlemen, thank you for participating in today's conference. That does conclude today's program. You may all disconnect. Have a great day, everyone.