Plains GP Holdings LP (PAGP) 2016 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the PAA and the PAGP second quarter results conference call.

(Operator Instructions)

As a reminder, your conference is being recorded. I would now like to turn the conference over to your host Ryan Smith, Director of Investor Relations. Please go ahead.

Thank you Lois. Good morning, and welcome to Plains All American Pipeline second quarter of 2016 earnings conference call. The slide presentation for today's call can be found within the Investor Relations and News and Events section of our website at Plainsallamerican.com. During today's call we will provide forward-looking comments on PAA's outlook. Important factors which could cause actual results to differ materially are included in our latest filings with the SEC.

Today's presentation will also include references to non-GAAP financial measures such as adjusted EBITDA. A reconciliation of these non-GAAP financial measures to the most comparable GAAP financial measures can be found under the Investors Relations and Financial Information section of our website.

Today's presentation will also include selected financial information for PAGP. We do not intend to cover PAGP's results separately from PAA's. Instead we have included schedules in the Appendix to the slide presentation for today's call that contain PAGP-specific information.

Today's call will be chaired by Greg Armstrong, Chairman and CEO; also participating in the call are Harry Pefanis, President; Willie Chiang, Chief Operating Officer US, and Al Swanson, Chief Financial Officer. In addition to these gentlemen and myself, we have several other members of our Senior Management Team present and available for the Q&A portion of today's call. With that I'll turn call over to Greg.

Thanks Ryan, and good morning and thank you everyone for joining us. We've been very active since our first-quarter earnings conference call when it was held in early May. Accordingly before we discuss second-quarter results I want to quickly recap our activities over the last three months.

On May 25, we hosted our annual Investor Day event where we provided an in-depth review of PAA's assets, operations, and positioning for the future. We also shared our views on some of the challenges and opportunities associated with three alternative production forecast scenarios. In particular we provided detailed regional information on what we refer to as Scenario B, which we currently believe represents the highest probability among the three alternative scenarios. On July 11, we announced the results of our simplification process between PAA and its General Partner-related entities, which included entering into a definitive agreement to permanently eliminate PAA's incentive distribution rights and economic rights associated with PAA's 2% general partner interest in exchange for 245.5 million units of PAA and the assumption by PAA of AAP's outstanding debt, which is currently approximately $600 million.

At the same time we also announced that PAA's and PAGP's second quarter distribution payable in August would remain at the same level as the first-quarter distribution paid in May, however, effective with the third-quarter distribution payable in November, PAA announced that it intends to reset its distribution to $0.55 per unit per quarter, or $2.20 per unit annualized. That equates to a 21% reduction.

The net impact on PAGP of the simplification transaction and PAA's distribution reduction would equate to a corresponding decrease in PAGP's quarterly distribution of approximately 11%. Collectively, we believe these actions will better align the interests of PAA's equity holders, improve its overall credit profile, reduce its cost of incremental capital, and improve its distribution coverage.

As Harry and Willie will address during the remarks, over the last three months we've also been executing our 2016 capital program and making progress with respect to both asset sales and an asset acquisition. In short, the entire Plains team has been extremely busy and productive, and I wanted to take this opportunity to publicly thank them for their commitment, performance, and the personal sacrifices they made to deliver these accomplishments.

In addition all the other activities, PAA continued to execute well operationally and commercially in the challenging environment. Yesterday evening PAA reported adjusted EBITDA of $461 million, which was approximately $21 million or 5% above the midpoint of our second-quarter guidance. Harry will provide additional details during his comments, but as shown on slide 3, all three segments turned in solid performances; both the Transportation and Facility segments delivered results slightly above the high end of our second-quarter guidance range, while the Supply and Logistics segment delivered in-line performance.

Crude oil prices rallied in late May and in early June leading to a rebound in crude oil rig count consistent with the assumptions we incorporated in the Scenario B production forecast presented during our Investor Day. Thus far it appears lower 48 production volumes are directionally tracking this Scenario B production forecast. While we are encouraged by these developments, we remain cautious over the near-term based on stubbornly high crude oil inventory levels, recent builds and total product inventories, and continued intense competition for the marginal barrel.

Accordingly, although PAA outperformed in the second quarter relative to guidance, taking all the information available to us into consideration we elected to maintain the midpoint of our full-year adjusted EBITDA guidance of $2.175 billion. Notably, based on this guidance and taking into consideration both the simplification transaction and the distribution reset to $2.20 per unit, PAA's pro forma cash distribution coverage for the second half and full-year 2016 is expected to be approximately 1.03 times to 1.05 times, respectively.

Looking forward we expect PAA's adjusted EBITDA to benefit from increases in minimum volume commitments on existing assets as well as numerous capital projects scheduled to come online over the next 18 months. In combination with PAA's large interconnected crude oil midstream platform and the significant operating leverage it provides to sustained increase in US crude oil production, we believe PAA's well-positioned to achieve is targeted minimum distribution coverage of 1.15 times and to deliver attractive distribution growth in the coming years. With that I'll turn the call over to Harry.

Thanks Greg. During my portion of the call I will review our second-quarter operating results compared to the midpoint of our guidance and provide an update on our 2016 capital program. Slide 4 provides a summary of our second quarter 2016 results.

As reflected on slide 4, adjusted segment profit for the Transportation segment was $261 million or approximately $9 million by the midpoint of our guidance. For the quarter volumes were in line with our guidance at approximately 4.78 million barrels per day. Adjusted segment profit of $0.60 per barrel was $0.02 per barrel above the midpoint of our guidance. And this was driven by higher than forecasted volumes on some of our higher tariff pipelines particularly Line 2000 in California and our Canadian NGL lines. The increased volumes on Line 2000 were primarily due to a third-party pipeline that was temporarily shut down during the quarter.

I should also note that the volume impact on the sale of certain of our Gulf Coast pipelines at the end of March was offset by our acquisition of the remaining interests in the CAM pipeline system in late March. We then sold 100% of the CAM pipeline on July 1, and Willie will touch on the impact of this -- that this will have on our third quarter volume assumptions later.

Adjusted segment profit for the Facility segment was $161 million, which was approximately $13 million above the midpoint of our guidance. Volumes of approximately 128 million barrels of oil equivalent per month were essentially line with our guidance. Adjusted segment profit of $0.42 per barrel was $0.04 per barrel above the midpoint of our guidance due to a combination of higher than forecasted throughput at several of our facilities and contracted capacity at a couple of our West Coast terminals was higher than expected. In addition our maintenance capital -- our maintenance and integrity expenses were lower than forecasted. And for the most part, this was a timing issue with the costs expected to be incurred later in the year.

Adjusted segment profit for the Supply and Logistics segment was $39 million, which was essentially in-line with the midpoint of our guidance. Volumes of approximately 1.07 million barrels per day and adjusted segment profit per barrel of $0.41 were also essentially in line with our guidance.

Moving on to our capital program, slide 5 provides a summary of our 2016 capital program including anticipated in-service dates for each project. We have reduced our anticipated 2016 capital program by $75 million to $1.425 billion, primarily as a result of anticipated [diamond] spending getting pushed into 2017.

Also note that in August we plan to place the segment of our Line 63 system that runs from the San Joaquin Valley to Los Angeles back into service. And also the Platteville, Colorado, to Cushing, Oklahoma, segment of Saddlehorn pipeline will be placed into service in August. The Carr to Platteville, Colorado segment of the Saddlehorn pipeline is expected to be completed by the end of the year. And with that, I'll turn the call over to Willie.

Thanks Gary, good morning. I'll provide a brief update on non-core asset sales and discuss our operating and financial guidance for the third quarter and full-year 2016.

As summarized on slide 6, we forecast proceeds near the high end of our $500 million to $600 million range for 2016 non-core asset sales. But I'll note that this does not include proceeds from the potential sale of our West Coast Richmond and Martinez terminals, which is currently in the marketing stage. Since our first-quarter earnings conference call, we've closed on transactions for total net sale proceeds of approximately $130 million. This includes the sale of our 50% interest in the Cheyenne Pipeline LLC to a strategic partner, Holly Energy Partners, and the sale of the Gulf Coast CAM pipeline system. This brings our year-to-date net sales proceeds to approximately $480 million. And we anticipate closing additional transactions, both non-core asset sales and potential sales of partial interests to strategic partners later this year.

Finally we have satisfied the regulatory closing conditions for our acquisition of Canadian NGL assets at Empress, and are scheduled to close within the next week or so. I might add that the volumes related to the assets that we have sold to date are approximately 190,000 barrels a day of pipeline transportation volumes and 4 million barrels of storage capacity.

I will now move to slide 7 to discuss the operational assumptions used to generate our guidance for third quarter 2016, which we furnished yesterday. For our Transportation segment, we expect volumes to average approximately 4.6 million barrels a day for the third quarter, or a decrease of approximately 150,000 barrels a day from the second quarter. I want to highlight that we expect approximately 40,000 barrels a day of additional volume growth in our gathering systems, primarily in the Permian and Oklahoma, which is being offset by the loss of approximately 175,000 barrels a day of the lower-margin volumes from the sale of our Gulf Coast CAM pipeline and an expected shortfall in MVC volumes.

On the margin side, we expect adjusted segment profit per barrel to be $0.68 or $0.08 per barrel higher than the second quarter. This is primarily due to anticipated MVC billings and the resulting selected item adjustments that we anticipate for the third quarter.

For our Facilities segment, we expect an average capacity of 130 million barrels of oil equivalent per month, or an increase of approximately 2 million barrels per month from the second quarter. The volume increase is primarily the result of our acquisition of NGL storage and fractionation capacity at Empress, in addition to new crude oil tankage at Cushing and our St. James terminals.

We expect adjusted segment profit per barrel to be $0.38 or $0.04 per barrel lower than the second quarter. The decrease in segment profit per barrel is attributed to higher operating expenses, primarily due to the timing of maintenance and integrity expenses, lower rail volumes, and a more normalized storage market forecasted for our West Coast terminals partially offset by the benefit of the Canadian NGL acquisition.

For our Supply and Logistics segment, we expect volumes to average 1.1 million barrels a day, or an increase of approximately 24,000 barrels a day from the second quarter. The anticipated volume increase is primarily driven by anticipated increase in crude oil lease gathering volumes. We expect adjusted segment profit per barrel to be $0.37 or $0.04 per barrel lower than the second quarter due to lower lease gathering margins and less favorable crude oil conditions partially offset by stronger expected NGL sales results.

Finally, as Greg mentioned previously and is summarized on slide 8, we continue to forecast full-year 2016 EBITDA of $2.175 billion. On the right-hand side of the slide is a directional illustration that serves as a reminder that our full-year adjusted EBITDA profile is U-shaped in nature due to the inherent seasonality of our NGL business. Although this generally has a negative impact on our distribution coverage ratio in the second and third quarter, this is expected and consistent with the guidance we furnished in May. For more detailed information on our 2016 guidance please refer to the Form 8-K we furnished yesterday. With that, I'll turn the call over to Al.

Thanks, Willie. During my portion of the call I will review our capitalization and liquidity, as well as discuss several non-cash charges that impacted our second-quarter financial performance.

As illustrated on slide 9, at June 30, PAA had long-term debt to capitalization ratio of 51%, a long-term debt to adjusted EBITDA ratio of 4.4 times, and $2.9 billion of committed liquidity. While our long-term debt to adjusted EBITDA ratio is elevated relative to historic levels in our targeted range, we remain committed to reducing this leverage ratio and expect to return to the targeted range over time as we benefit from capital projects coming online as well as from proceeds from asset sales, retain cash flow as a result of the intended distribution reset, and from meaningful cash flow growth that will come from an industry recovery.

Additionally, with the disproportionate burden of the GP IDRs removed as a result of the simplification, PAA's incremental cost of equity capital is significantly reduced. Accordingly, with cost-effective access to the equity market, including through the use of our continuous equity offering program, we believe the public equity markets will again be an effective source of capital for PAA to fund growth investments as well as a tool to help manage our capital structure and leverage from time to time.

Additionally, the combination of a simplification and distribution reset reduces annual cash distributions by approximately $320 million per year, which has a meaningful benefit to cash distribution coverage resulting in pro forma 2016 coverage of approximately 105%.

I also wanted to mention that in the guidance 8-K that we furnished yesterday, we assume that the simplification transaction closed in early November. We are currently working on the proxy statement and expect to make an initial filing with the SEC within the next week or so.

Lastly, depreciation and amortization expense for the second quarter is $204 million and includes several non-cash charges related to assets included in our Facilities segment. As a result of current crude oil industry conditions and reduced business activity, we recorded an impairment charge totaling $80 million on two crude oil rail loading terminals and on a small storage terminal that is being shut down. In addition we recognized a charge of $18 million to write off the book value of a non-operated joint venture straddle gas plant that is being de-commissioned. With that, I'll turn the call back over to Greg.

Thanks, Al. We are pleased with PAA's second-quarter performance and believe we are well-positioned for the balance of the year and beyond. PAA has one of the largest and most interconnected crude oil midstream platforms in North America, which has significant leverage to a sustained increase in US crude oil production with no- to low-incremental capital investment. PAA has $2.9 billion of committed liquidity, and our performance is expected to benefit from increases in minimum volume commitments on existing assets as well as numerous capital projects scheduled to come online over the next 18 months.

I want to thank everybody for participating in today's call and for your investment and trust in PAA and PAGP. We look forward to updating you on our activities during our next call in November.

With that Lois, we are ready to open the call up for questions.

Thank you.

(Operator Instructions)

Our first question will come from Kristina Kazarian with Deutsche Bank.

I know you guys touched on this in your comments and it was in the press release a little bit too, but can you help me -- just sync me up on what you guys are seeing regional volume trends-wise kind of and set them relative to where we're thinking towards year-end expectations, particularly like Eagle Ford looked okay, Rocky Mountain weak, Gulf Coast above, kind of those numbers just specifically on those three regions what we're kind of thinking?

I think in all three areas our volumes are in line with what we had modeled in our -- I think, Kristina, I guess you are kind of asking more of a macro what are we seeing relative what we expected to see?

Yes.

And pretty much we're tracking kind of where we thought we were and kind of our scenario would be, the one area that appears to be the most resilient, if not actually kind of overperforming a little bit, is in the Permian. The overall activity levels are generally in line with what we thought. The results from the wells that are being reported are stronger and so that's an area where clearly we have our biggest footprint and we're not ready to declare absolute victory right now but we're certainly looking at it with cautious optimism.

Okay. And then how about (indiscernible) from the asset sale program or additional interest in other projects? I know you guys touched on this as well, but any color on timeframe or thought process there?

Yes, so we've got, as I note -- this is Willie. As I noted in my narrative, we've got a number of deals that we expect to complete by year end. And I think what you'll see is they're going to be consistent with other projects we've done where we've taken on strategic partners like the sale of the Cheyenne pipeline, part of the Cheyenne pipeline to HollyFrontier or Saddlehorn.

You'll see some of that and we also have some additional non-core asset sales that we are evaluating, but probably the biggest thing that's in progress right now, Kristina, is the West Coast terminals, Richmond and Martinez deal. So we've been very pleased with the values that we're getting and the progress that we're making.

I might just add, Kristina, I think about a year ago we made the observation that as we entered this -- get farther into the cycle that we thought there'd be a need for rationalization of assets and we thought there might be some consolidation. We've been wrong on the consolidation so far, but the rationalization of assets, not only are we doing it, as Willie mentioned we've got a couple of joint ventures we've announced.

We've got a few more that we're working on, we're kind of knocking on wood to see if they move forward, but -- and I think some announcements here recently reinforced that everybody's trying to figure out how do you rationalize the existing capacity and also rationalize the expansion that's been going on in the midcourse.

So I think we will continue to see some of that. And PAA is well- positioned because we are in just about every area there, so we're looking hard at it. We think the industry in the whole -- it is not unique to us. Everybody is looking at trying to figure out how do you get more out of less.

And the last one from me, when I'm thinking about the projects that are coming online in the back half of this year, could you remind me how I'm supposed to be thinking about cash flow ramp on things like Cactus?

Cactus, I think the volume increases are expected to be actually next year.

So -- sorry -- it comes online 4Q 2016, right? So how do I think about cash flow ramp once it is online? [Have I] got that wrong?

There's two things. I think, number one, we've got expansion to be able to handle incremental volume. That's going to happen right around the beginning of the first -- fourth quarter. We have a MBC step-up, one of which, the largest, is tied to a third-party's expanding their project. And right now we would estimate that is going to be probably end of the year, first part of next year. So you should start to see it when we report first-quarter results.

Thanks, guys.

Thank you.

Shneur Gershuni with UBS.

Hello. Good morning, guys. Just a couple of quick questions here. I guess when I sort of think -- look at the slides that you put out, in looking at slide 5 you talk about your major capital projects that you have coming forward. And I look at every single one of them and it says yes under MBC contractual support. I was wondering if you can give us a sense of the incremental EBITDA by 4Q 2017 that is sort of generated just by the MBCs for all of these projects, relatively speaking, to kind of where you were at the beginning of 2016.

I don't have that right in front of me. I think the best source of that would probably be in the Analyst Day presentation. Al had a slide in his section that showed -- I don't know that it's actually going to get you to just the fourth quarter, I think it's kind of a full run rate as all these projects come on, but you can kind of visually scale it by looking at the dates that the in-service timings come on with the target level there. I can't remember how they --

Order of magnitude, it was -- I think the slide was just over $200 million, of which a good portion of that, I'll say two-thirds of it, roughly $150 million was in 2017 and then the remaining piece was the Diamond pipeline startup at the end of 2017 for 2018.

That was a component of these projects, not every one.

Okay. Thank you. And then as a follow-up -- actually I have two follow-ups, but the S&L segment, there's kind of been a lot of questions about when the spreads will recover, what you're thinking about in terms of spreads recovering, just sort of get to kind of the $500 million or plus promised land. I realize it's difficult to express it in hubs, which hub should move and so forth.

I was wondering if maybe if we can think about it a different way. When you think about domestic crude production, both offshore/onshore, what production level do we need to get to to generate a scenario where spreads do expand to create the opportunities?

I'm not saying it has to go up to the crazy spreads we saw a couple years ago, but do we need to get back to $9 million? Do we need to get to $9.3 million, $9.4 million? Is there kind of a number that we should sort of be thinking about as to when you would be thinking about an expansion in spreads that would benefit the S&L segment?

I think it's going to be more regional than that. I don't know that you can think of it in aggregate. First off, we don't include Alaska in anything that we talk about and we really don't include the offshore, so we're really talking about lower 48. And as a practical matter, we're talking about really lower 47, because California is kind of an island into itself.

It varies by area. I think the other thing that you need to include in your thoughts as to what volumes need to be raised or levels need to be achieved is part of it's associated with the spreads are tight in certain areas because of the MBCs and the over commitments that we have.

And so there are people that have a short -- they are long transportation, but they are short barrels and so they are competing for those incremental barrels to try and minimize that transportation cost. As certain of those contracts expire or get reformatted, that will be a surrogate, if you will, for volume increases.

And so part of it is just the function of volumes, as you suggest, and part of it is a function of the regional balances and that's going to change with the passage of time. In some cases 100,000 barrels can have a fairly potential significant increment to the margin relief on the competition side.

Okay. And then one final question. When I looked at your Analyst Day slides, and you sort of looked at your Permian production outlook, while it is upward sloping, it was very conservative relative to a lot of industry pundits out there and so forth. Recently I believe it was Pioneer had sort of talked about an opportunity to get to five million barrels, which would basically double current Permian capacity in terms of takeaway.

How do you think it actually plays itself out? Do you actually see opportunities or scenarios where you would actually need to build more takeaway capacity out of the Permian?

Also are more basins further north effectively looking to connect capacity to the Permian to sort of take advantage of the capacity as it gets to the Gulf of [Nederland] and so forth? I just wondered if you could talk about that in those contexts?

First off, the question of whether we need five million barrels a day out of the Permian is more a function of a macro issue that none of us are in control of. Its more of a world supply demand balance. I think what we're all willing to sign off on is there's a huge amount of resource out there and you can certainly create a scenario that if there's worldwide demand for the crude, you could actually achieve very, very high levels of production out of the Permian.

I don't recall exactly what Pioneer's date that they put on that five million barrels, I don't think there was one. But clearly you step on the accelerator, you take your foot off the accelerator, you're going to change those volumes quite a bit.

So part of it is just going to be we're all going to have to monitor the demand for -- in the world for crude oil in general. And if the answer is we are the swing producer, the Permian is the best place to get it.

What we feel pretty good about is, if you recall the upside scenario that we shared at the Analyst Day, I think Willie went through about half of the pipeline upside was associated with the Permian. So if you believe it's going to get anywhere north of three million barrels, much less five million barrels, every pipe out there is going to be full and we're all going to be talking about a need for expansion or new pipelines.

I think the reality is there's probably enough expansion of the existing pipelines, probably in the order of magnitude, hearing Willie, 200,000 or 300,000 barrels a day by adding new pumps or incremental DRA, so you don't necessarily need a new piece of pipe to handle 2.8 million to 3 million barrels a day, but you clearly do if you get on up to the numbers you are talking about.

We're at, like, two million barrels a day in the Permian right now, so three million barrels a day requires another one million barrels a day of volume.

When you sort of look at the map, do you see scenarios where other basins look to solve any tightness that they have in terms of getting production out to sort of effectively bring production into the Permian to take advantage of the expansive network that already gets you to the Gulf? Do you see that as kind of a source of incremental volumes that can effectively use those pipes as well too?

I don't think so. This is Willie. There is a lot of capacity from pushing down. I think if you believe the numbers that you were talking about on the Permian, I think barrels will continue to flow out of the Permian because I think there's been enough infrastructure that's been built that allows it to get to the Gulf, with the exception, perhaps, of the Eastern Gulf, the Louisiana refineries.

I think what we've seen so far, Shneur, is what you really want to do is you want to get to a market hub, and the cushion is far and away the most liquid. Obviously we're building pipelines out of there, but Red River going to East Texas and Louisiana and then one across to Memphis on Diamond. So right now I don't feel like there's anybody's going to try to build a pipeline from, let's say, the Rockies down to the West Texas to access those barrels.

And I think everybody realizes that at 2.5 million barrels a day of takeaway capacity, and there's another pipeline in the wings that will be brought on the next couple of years. If you believe the kind of volumes that I think we're all willing to believe about the Permian, you're going to need the pipeline capacity you have there, so no need to build a pipeline there, jam the area and then wish you had more capacity coming out.

Like Willie said, there's so much infrastructure that already can deliver crude from the Bakken and the Rockies and et cetera into Cushing, and there's plenty of takeaway capacity out of Cushing, so wouldn't seem to really need to try and tie into the infrastructure in the Permian.

Cool. All right, guys, really appreciate the color. Thank you very much.

Thank you.

Jeremy Tonet with JPMorgan.

Good morning.

Good morning, Jeremy.

The facility segment seems to kind of keep outpacing our expectations a bit here. I was just wondering if you guys have seen much benefit on gas storage side or if there's anything else that's kind of been proving to be better than expected in that segment?

I think for the most part it's really just been a lot of -- a lot more activity almost across the board at all the facilities, whether it's our condensate processing, our dock at St. James, throughput through Cushing, throughput through St. James, it's all really expanded. I will let Dean Liollio, he's sitting here, he can touch on what we see with natural gas.

Yes, Jeremy. It's location based, particularly [Time Prairie] being the strongest and we're seeing good response as we previously announced with new contracts there and contracting into the future long-term, so we're seeing some uptick particularly at that facility.

Might be a little longer-term in nature than the current quarter, but --

I think we probably can say we think we've got the bottom part of the cycle for gas storage in the rear view mirror right now. We have seen probably uplift of 10% to 20% in rates at the margin. And it's tied a lot to -- with respect to gas storage to the commencement of LNG exports and the demand for versatility in your supply stream and the ability to store on short notice and pull out on short notice.

Great. Thanks for that. And then turning over to the pipe segment, looking at your guidance 3Q into 4Q there's a bit of a ramp in the volumes there. Could you walk through or give us some color as far as how much of that is kind of MBCs with projects coming online versus expectations for production growth coming back?

This is Willie again. I would characterize it as we've got some MBC ramp ups, but we also -- as we outlined at the Investor Day -- we have a pretty significant chase on what we call the lease gathering of the first purchased barrels to get into the system and we're seeing progress on that as well.

Jeremy, what I would say is our macro production model is -- assuming continued declines through 2016 into 2017, so it is not from an industry recovery.

Yes, it's more a market share issue or project completion issue.

Okay, great, thanks. That leaves the next question with regard to rails loading, onloading, looks like that steps down a bit here. Is that MBC rolls over the back half of the year or do you expect less differential activity?

Part of it's with some of the new pipes coming on, especially out of the Rockies, and probably impacts rails more than anything. It's not MBC rolloffs. At the margin you are seeing the differentials change or volumes being pulled away to other transport mechanisms.

Great. Thanks, that's it for me.

Thanks, Jeremy.

Brian Gamble with Simmons & Company.

Good morning, guys.

Good morning, Brian.

Following that last thought on the pipeline growth, Greg, you've walked through (inaudible) in detail, I think it was during your remarks, it might have been during Willie's, but talking about the opportunity specifically within the Permian to start gaining volumes as some other longer-term contracts roll off and because you've got the pipes, you can easily get in there and [reference] the first barrels come in and maybe some market share gains there. Are you having to sacrifice any -- are you having to sacrifice any margins to gain those barrels?

I think the indication you gave us earlier was that because your rates were such they would allow you to essentially use those same rates moving forward and gain barrels and not necessarily sacrifice any margins. Is that what's happening there or are you just essentially being able to get in there with the extensive opportunity set that you're giving producers and gain barrels that way?

No, we're being aggressive at the lease. So when we look at the business, because of the integrated system where the objective function is the integrated margin, not just one section's margin.

To answer your question, you're not having to discount your pipeline terrace but you are sacrificing gathering margin and, again, you can look at it kind of on a consolidated basis and say net/net the Company is doing better than they would to lose the barrel, perhaps, to somebody that's going to take it to another pipeline system.

And part of this Brian, is, again, it's all influenced by the MBCs to some extent because if somebody's got a commitment on a pipeline that has a higher tariff but they have a shipper pay you on that, or contract obligation, they are going to view that as a [sunk] cost and the total [were assets] on that's at the gathering margin. So the producers are benefiting right now from that intense competition.

Great. Appreciate that color. And then as far as the bump on the S&L business Q3 to Q4, typical seasonality there, but given what we're staring at, maybe a more hypersensitive market than normal, specifically NGLs, we saw a pretty decent run-up in May and June in the prices and they've come up precipitously since then. I guess, just given what your operating group is seeing now, how much confidence in there that says the fourth quarter is going to be typically -- or allows the typical strength that's there during the calendar year?

A lot of that NGL volume was contracted for -- but a seasonal contract, so we're very confident that over the winter season we will generate that NGL seasonal type of revenue. There's always a question of whether you see stronger weather or weaker weather conditions in fourth quarter versus first quarter, so there could be some slippage one way or the other between fourth quarter and first quarter, but the volumes contracted.

Yes, Brian, so we will have the volumes in our storage and they're committed for to be pulled, but they don't have to pull it -- let's say, they can pull it in the fourth quarter or in the first quarter, depending upon when they need it for weather balancing. So, as Harry said, were going to capture the margin over, let's say, a four- or five-month period, we just don't know if it's the first three months of the four or five months or the last couple of months.

We feel pretty good about our forecast. Obviously if there's an erratic weather pattern, it could shift some of that profit from the fourth quarter to the first, but the real seasonal swing that you see there, and you saw it on the graph -- the chart that Willie had, that's been that pattern for many years.

And we've had situations in the past where we've either had margin push from the fourth quarter into the first quarter of the next year or we've had situations where they've actually pulled it into the fourth quarter and we've had a lurch and that you shouldn't get carried away and annualize it.

So we feel pretty good about the forecast that we have out there. It reflects everything that we know as of the time we put the forecast together.

Great. And then last one for me, Greg, you mentioned consolidation. It really hasn't happened yet. We've got plenty of rationalizations, some assets changing hands, a big one last night with, I guess, on the crude side. But as far as the trends there on the M&A markets, anything changing in your view over the last few months or even since the Analysts Day that has prohibited things from happening that may loosen up in the back half of the year? Just any color from your perspective would be appreciated.

Yes. If you ask me what area have we been consistently wrong in, its in projecting the more consolidation because we see the rational -- the reason for it, but it's one of the hardest things to make happen. There is all kinds of issues that get involved in that. I think any time you end up with a -- let's call it a head fake or a resurgence in the market that makes every body feel like we're only three or four months away from everybody pulling out of a down cycle, it tends to freeze all discussions.

Either we need to pull out of the cycle and then people say okay we've now got our relative valuations reset, you probably have an opportunity to have some discussions. Or alternatively we stay in a lower cycle for longer and people run out of options to be able to either take care of their balance sheet or be able to have a discussion about what growth is going to look like when they come out of the cycle.

And that kind of forces the discussions. Obviously the rally that we've had over the last 60 days in crude oil prices probably caused people to pause a little bit and say why should I even think about it if we're just around the corner from having to pull out of this cycle?

Again, if you go back, I think we had this discussion five years ago and we said we thought consolidation made a lot of sense. It did, but it didn't happen and we've seen a couple of transactions that have fallen apart for other reasons. So we feel comfortable rationalization is occurring and we think consolidation should occur. Whether it does or not remains to be seen.

Appreciate that, Greg. That's all for me.

Thanks, Brian.

Richard Verdi from Ladenburg.

Hello, good morning, and thank you for taking my call. I just have a few high-level-type questions. Most of my other questions have been addressed in some sort of fashion.

On net growth projects (technical difficulty) I'm wondering, what is the Company looking at that could push any of the projects out longer or result in any of the projects coming to fruition sooner? And at the same time, what else is out there that could reduce or increase the amount of capital allocated in any of the projects?

The projects are all in progress. It's kind of hard to see much change in the timing of any of them. Obviously probably the biggest concern out there would be weather. Permitting, especially if you get into some local areas, Richard, could be a challenge, but I don't think we're going to see much in the shift of these projects.

I think at the beginning of this year we said we had about $2 billion of spend left to fulfill these obligations or commitments that we had made, $1.5 billion of that coming in in 2016 and about $0.5 billion coming in 2017, this chart shows we've had some projects coming a little bit under budget. So that's changed. We've also had others that we've changed the scope and so that's kind of offset.

The biggest change so far is Diamond, for example. I think it's a permitting issue that is going to cause us to have some of the capital spent early next year instead of fourth quarter this year. So don't expect much there.

As far as what could change, our capital outlook, obviously with the simplification, we've taken a step change in our cost to capital. We think there's certainly some room for what I call some minor to modest projects out there, and mainly to do with plumbing.

Some of these areas that are being developed are continuing to creep in terms of broaden their footprint. We think there's enough takeaway capacity in most areas to service the foreseeable needs, and so all you really need to do is be re-plumbing some of the existing infield infrastructure or extending it to be look to get to that takeaway capacity.

But I think we -- and I think we're seeing the discipline pretty much throughout most of the industry, are commanding an appropriate rate of return for that. Even though it's still competitive, I don't think the markets are quite as silly as they were, being down -- things down in the single-digit returns which we saw some of that in 2014.

That's great color. Thank you. And also, I believe the MBC -- I believe they were backed by about 78% of investment-grade customers and 47% of those, somewhere around a figure were [above A rated] with a majority non-investment grade being refiners on [demand core projects]. Just wondered if you can give us an update on the credit profile with counterparties? Is that still the same or has that changed?

Yes, no material changes from what we talked through on the February call. And I think you're referring to some of the slides we had in the analyst or the Investor Day materials, no material changes to that.

Okay, great. The last question, dovetailing off of that. For the Analyst Day -- I believe this is really compelling. The Company's laid out how there's possibly about $1 billion of EBITDA on the table from rationalization and optimization efforts. And I was hoping you could provide me with some color on when this concept might begin to materialize.

Let me take a stab at that. So there's two buckets, right? There's the $600 million in facilities and transportation and there's a $400 million commercial. And the way you ought to think about that is the $600 million is directly leveraged to recovery. So as more barrels get produced, we should get our fair share of the market or more. And as we see increases in production volumes, you should see us capture part of that $600 million and we're starting to do it already.

The commercial piece is a little more complicated. And there was an earlier question that related to the timing of market -- timing of when do you get into a tight market situation. And I would look at that $400 million as that's not one that's going to be ratable directly to recovery. You've almost got to get to the point where -- and let's use the Permian as an example.

If you get to a 90% -- maybe within 100,000 to 200,000 barrels a day close to the takeaway capacity, there will be opportunities where we can capture additional volumes. And that's when you'll see that hit. So the $600 million should be ratable to recovery; the $400 million will be lumpier and more tied to basins becoming a tighter in supply and demand balance.

We get better margins as both volumes (inaudible).

Right.

As it tightens up, we should see better margins.

Yes, it's absolutely margin related.

And then, Richard, that was on slide 48 of the Analyst Day. I think Willie's comments are absolutely on point, realizing that you may have ratable production increases in one region and to the detriment of another region, but the area that I think we and one of the earlier questioners asked, I think everybody's pretty confident about is the Permian.

And half of that pipeline in facilities uplift came from Permian related. And so, for example, to get to the level that would then trigger some incremental benefit to the gathering and marketing as well would be roughly about a 15% increase in production from current levels.

Right now around two million barrels a day in the Permian, so as we get to 2.3, you are starting to get close to capacity and things tighten up and realizing that even with what it sounds like, 200,000 barrels a day of capacity relative to the 2 and a half that's currently there, if a refinery goes down or another pipeline develops a problem, it is going to create a backup in the system.

And so you can't run these things at 100% of capacity. So, again, you almost have to adopt a regional perspective with respect to pipeline and also with respect to the supply and logistics.

There will be more pipeline capacity in 2018 out of the Permian, too, so that ought to ramp up over time.

And Richard -- this is Willie, again -- I think it goes without saying, we've gotten quite a bit of feedback and questions on that slide. The point we were trying to make on it is we've got a very, very robust system that's got capacity and we're focusing our organization on making sure we optimize and capture all of that, so we're not forced to just build organically to grow, but we've got a lot of capability in the existing system.

That's super. That's great color. Thank you very much for the time, guys, I appreciate it.

Thanks, Richard.

(Operator instructions)

Patrick [Wayne] from Baird.

Hey, good morning. You previously commented on the ability to maintain that one times plus distribution coverage even in that bearish scenario C, or even worse, but today it sounds like scenario B is the most likely outcome based on current dynamics.

Can you touch on the leverage side of this outlook and perhaps weigh in on the relative contributions of the drivers to reach the targeted 3.5 to 4 times ratio, whether it's between the distribution reset, equity, EBITDA growth? And then to the extent the latter is contingent on that production recovery?

I'll take a shot at it. Clearly the most preferred and best alternative to delever is cash flow growth, and we expect cash flow growth from the capital project, the MBCs that will come on, as well as ultimately from an industry recovery -- industry recovery's a little bit timing-wise, a little bit outside of our control.

Clearly in the meantime, as we look at using proceeds from asset sales that is very significantly deleveraging as well. So really kind of a combination of all three of those, with one being the timing's a little bit more uncertain. I think in our scenario B, we didn't assume a meaningful industry recovery until basically mid-2017, so roughly about 12 months from now.

One of the other key points, though, is with the simplification, the IDR removal and arguably some removal of the uncertainty around our stock and what the distribution reset would be, equity is also a tool. And really what we're -- we're not trying to say by X date we're going to be at X level exactly, but we think the combination of really all four of those will really drive and see significant improvement in our leverage.

And really probably on the last point is just to reiterate our commitment to seeing our leverage come down to maintain our investment-grade ratings at both agencies, Moody's and S&P. So, again, not a specific time that we're going to tell you, but really we see all four of those coming into play.

I would also say, Patrick, that every move that we make from this point forward is going to be with a focus in on how do we make sure we're not stepping farther away from those credit metrics.

So, for example, if we make an acquisition, but we're selling an asset, say, for the same exact dollar amount, but the acquisition obviously is going to have a better multiple for us than the one that we sold in terms of benefiting our leverage to the extent we make an acquisition and -- or a capital expenditure, that's not currently on the table, but is a prudent thing for us to do, you'd probably see us finance it with a little more equity than we would normally do in our [55/45], so we're going to beat this thing with everything we got in the artillery.

But the commitment there is extremely strong to bring it back in within a reasonable time period and then build coverage on the distribution. And we think we can do all of that and still be very competitive with our peers with respect to large-cap peers in the rich adjusted risk profile to be an attractive investment for our equity holders.

Great. That's very helpful. That's it for me. Thanks for the time.

Justin Jenkins with Raymond James.

Hey, good morning, guys. I appreciate the color this morning. Most of mine have been asked and answered, but I guess I'll just follow up real quick on the last comments you made. Looks like based on unit count guidance for 4Q 2016 there's some decent APM issuance planned. Can you just give us a sense on how opportunistic you plan to be with ATM in the back half of 2016 and into 2017?

I'll take a shot at that. We will look at it on an opportunistic basis, but I think what you're seeing there is the assumption of the shares being issued as a result of the simplification.

When I do the math there, it looks like there's between five and 10 million units. Just curious if there is a decent chunk of ATM in there and then maybe how we think about it in the 2017 ATM.

Yes, like we said, we are assuming we'll take an opportunistic approach with equity. But the large chunk of what you're seeing is the number of shares coming in from the simplification. But we have assumed some opportunistic usage of our ATM.

I think, to use your numbers, 10 million units would be roughly 1.5% issuance. When you run it through the offset of the interest expense, it has a fairly meaningful impact on deleveraging, very minor impact on DCF per unit.

Okay. No, that's perfect. Appreciate the color, guys.

Thank you.

At this time, there are no further questions in queue. Please continue.

I want to thank, again, everybody for participating in today's call and we look forward to updating you on our call in November.

Thank you. And that does conclude our conference for today. Thank you for your participation and for using AT&T executive teleconference. You may now disconnect.