Ladies and gentlemen, thank you for standing by, and welcome to the PAA and the PAGP Second Quarter Results Conference Call. Later, we will conduct a question-and-answer session, and instructions will be given at that time. And 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.

Thanks, Louise. Good morning, and welcome to Plains All American Pipeline's second quarter of 2016 earnings conference call. The slide presentation for today's call can be found within the Investor Relations and News & 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 the 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 Investor 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 of U.S.; 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 the call over to Greg.

Thanks, Ryan. Good morning, and thank you, everyone, for joining us. We've been very active since our first quarter earnings conference call that 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 of what we referred 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%. Selectively, we believe these actions will better align the interest in PAA's equity holders, improve its overall credit profile, reduce its cost of…

Thanks, Greg. During my portion of the call, I'll review our second quarter operating results compared to the midpoint of our guidance and provide an update on our 2016 capital program. Slide four provides a summary of our second quarter 2016 results. And as reflected on slide four, adjusted segment profit for the Transportation segment was $261 million or approximately $9 million above 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 interest 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 sale will have on our third quarter volume assumptions later. Adjusted segment profit for the Facilities 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 in 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…

Thanks, Harry. 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 of 2016. As summarized on slide six, 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 with 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. 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'm now going to move to slide seven to discuss the operational assumptions used to generate our guidance for third quarter 2016, which we've 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…

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 nine, 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 and 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, retained 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 that 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 the 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 assumed that the simplification transaction will close 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 has been shut down. In addition, we recognized the charge of $18 million to write off the book value of a non-operated joint venture, Stratogas, plant that is being decommissioned. 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're 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 sustain increase in U.S. 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 through our next call in November. With that, Louise, we're ready to open to call up for questions.

Thank you. And our first question will come from Kristina Kazarian with Deutsche Bank. Go ahead, please.

Good afternoon, guys. 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 and set them relative to where we're thinking towards the year-end expectations, particularly, like, Eagle Ford looks 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 all of the – in all three areas, our volumes are in line with what we had – that we had modeled in our – I think, we're seeing that – I guess, you've kind of asked more of a macro, what are we seeing relative to what we expected to see?

Yes.

Yeah. And pretty much, we're tracking, kind of, where we thought we were and kind of our scenario B. The one area that appears to be the most resilient, if not actually kind of over perform 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, yeah, we're not ready to declare actually a victory run now, but we're certainly looking at with cautious optimism.

Okay. And then, how about progress on 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?

Yeah. So, we've got, as I noted – this is Willie. As I noted in my narrative, we've got a number of deals that we expect to complete by yearend. And I think what you'll see is they're going to be consistent with other projects we've done, where we've taken our strategic partners like the sale of Cheyenne Pipeline – part of the Cheyenne Pipeline, the HollyFrontier or Saddlehorn. You'll see some of that, and then we also have some additional non-core assets that we're evaluating. But probably, the biggest thing that's in progress right now, Kristina, is the West Coast terminals, Richmond and Martinez. So, we've been very pleased with the values we're getting and the progress that we're making.

If I might just add, Kristina, I think, about a year ago, we made the observation that, as we entered this – got further into the cycle that we thought there'd be a need for rationalization assets and we thought there might be some consolidation. We've been rolling the consolidation so far, but the rationalization by 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 reinforce that everybody is trying to figure out how do you rationalize the existing capacity and also rationalize the expansion that's been going on in the mid-core. So, I think we'll continue to see some of that, and PAA is well positioned because we're in just about every area there. So, we're looking hard at it. We think the industry in the whole – it's not unique to us. Everybody is looking at trying to figure out how do you get more out of less.

Okay. And last one for me. When I'm thinking about the projects that are coming online in the back half of this year, just remind me how I'm supposed to be thinking about cash flow ramp on things like Cactus?

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

Comes online – so, sorry, it comes online 4Q 2016, right? So, just how do I think about cash flow ramp once it's online, if I don't think I got that wrong?

Yeah. 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 MVC step-up, one of which the largest is tied to a third-party's expanding their project. And right now, we would estimate that's going to be probably end of the year or first part of next year. So, you should start to see it when we report first quarter results.

Okay. Thanks, guys.

Thank you.

Thank you. Our next question will come from Shneur Gershuni with UBS. Go ahead, please.

Hi. 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 and looking at slide five, you talked about your major capital projects that you have coming forward. And I look at every single one of them and it says, yes, under MVC contractual support. I was wondering if you can sort of give us a sense of the incremental EBITDA by 4Q 2017 that's sort of generated just by the MVCs for all of these projects relatively speaking to, kind of, where you were at the beginning of 2016.

Shneur, I don't have that right in front of me. I think the best source of that would 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 – came in reality.

Order of magnitude, it was – I think the slide was just over $200 million. Of which, a good portion of that, I'll say 2/3 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.

And that was a component of these projects, not everyone.

Right.

Okay. Thank you. And then, as a follow-up – actually, I have two follow-ups. But the ethanol segment, there's kind of been a lot of questions about when spreads will recover what you're thinking about in terms of spreads recovering to sort of get to kind of the $500 million or plus promised land. And I did – I realized it's difficult to express it in hubs, which hubs should move and so forth. I was wondering if maybe if we can think about it in a different way. When you think about domestic crude production, both offshore and 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 of 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 ethanol segment?

Shneur, I think it's going to be more regional than that. I don't know if you can think of it in the 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. So, it varies by area. I think the other thing that you need to include in the – your thoughts as to what volumes need to be raised – or levels need to be achieved, is part of it is associated with the spreads are tight in certain areas because of the MVCs and the over-commitments that we have. And so, there are people that have a short – they're long transportation, but they're short barrels. And so, they're competing for those incremental barrels to try and minimize the transportation cost. As certain of those contracts expire or get reformatted, that will be a surrogate, if you will, for volume increases. And so, a part of it is just the function of volumes as you suggest and part of it's 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 who had sort of talked about an opportunity to get to 5 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 where – or scenarios where you would actually need to build more take-away 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 and Nederland and so forth? I was wondering if you can sort of talk about that in those context?

First off, it's – the question of whether we need 5 million barrels a day as a Permian is more a function of a macro issue that none of us are in control of. It's 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 there's – 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 5 million barrels. I don't think there was one. But clearly, you step on the accelerator or 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're 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 3 million barrels, much less 5 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, order of magnitude – hearing Willie – 200,000 barrels 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 barrels to 3 million barrels a day, but you clearly do if you get on up to the numbers you're talking about. And we're at, like, 2 million barrels a day at the Permian right now. So, 3 million barrels a day requires another million barrels a day of volume.

In sort of like – when you 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 bringing production into the Permian to take advantage of the expansive network that already gets you to the Gulf? Do you kind of 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's a lot of capacity from Cushing down. And I think if you believe the numbers that you were talking about in the Permian, I think barrels would 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.

Yeah. I think what we've seen so far, Shneur, is that – what you really want to do is you want to get to a market hub and Cushing is far and away the most liquid. Obviously, we're building pipelines out of there, both Red River going to East Texas and Louisiana and then one to – across to Memphis on Diamond. So, right now, I don't feel like there's anybody that's going try and 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 would be brought on in 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.

And 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 is plenty of take-away capacity out of Cushing. It wouldn't seem to really need to try and tie into the infrastructure in the Permian.

Sure. Right, guys. Really appreciate the color. Thank you very much.

Thank you.

Thank you. And our next question comes from Jeremy Tonet with JPMorgan. Please go ahead.

Good morning.

Good morning, Jeremy.

The Facilities segment seems to, kind of, keep outpacing our expectations a bit here. And I was just wondering if you guys are seeing much benefit on gas storage side, or if there's anything else that's kind of improving be better than expected in that segment?

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

Yeah. Jeremy, it's location based, particularly Pine Prairie being the strongest and we're seeing good response, as we previously announced with new contracts there and contracts being into the future long term. So, yeah, we're seeing some uptick, particularly at that facility.

I feel it's longer term in nature than the current quarter, but...

Correct.

I think we probably can say we think we've got the bottom part of the cycle for gas storage in the rearview mirror right now. We've 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 Pipes 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 MVCs with projects coming on line versus expectations for production growth coming back?

This is Willie again. I would characterize it, as we got some MVC 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 and the end of 2017. So, it is not from an industry recovery.

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

Okay. Great. Thanks. And then, that leads to next more – question with regards to rails loading, unloading. It looks like they're steps down a bit here. As the MVC rolls over the back half of the year or do you expect less kind of a differential activity?

Part of it is was some of the new pipes coming on, especially at the Rockies and probably impacts rail more than anything, but it's not MVC roll-off.

But at the margin, you are seeing the differentials change or value is being pulled away to the transport mechanism.

Great. Thanks. That's it for me. Thank you.

Thanks, Jeremy.

Thank you. Our next question comes from Brian Gamble with Simmons & Company. Go ahead, please. Brian D. Gamble - Piper Jaffray & Co.: Good morning, guys.

Good morning, Brian. Brian D. Gamble - Piper Jaffray & Co.: To follow on that last thought on the pipeline growth, Greg, you walked through at the Analyst Day in detail, I think it was there in your remarks or might have been during Willie's, but talking about the opportunity specifically within the Permian to start gaining volumes with some others' longer-term contracts kind of roll off and because you got the pipes, you can essentially get in there and you just reference it; the first barrels come in and maybe some market share gains there. Are you having to sacrifice any margins to gain those barrels? I think that the indication you gave us earlier was, 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 margin. Is that what's happening there? Or are you just essentially being able to get in there with the extensive opportunity set that you've given producers and gain barrels that way?

No, we're being aggressive, at the least. 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.

So, to answer your question, you're not having to discount your pipeline tariffs, but you're already sacrificing gathering margin. And again, you can look at it, kind of, on a consolidated basis to say, net-net, the company is doing better than they were to lose the barrel perhaps to somebody who's going to take it into another pipeline system. And part of this, Brian, is, again, it's all influenced by the MVCs to some extent because, if somebody has got a commitment on the pipeline that has a higher tariff but they have a ship-or-pay view on that or contract obligation, they're going to view that as a sunk cost and the tug war on that is at the gathering margin. So, yeah, the producers are benefiting right now from that intense competition. Brian D. Gamble - Piper Jaffray & Co.: Great. I appreciate that color. And then, as far as the bump on the ethanol business Q3 to Q4, typical seasonality there. But I guess, given we're steering at maybe a more hyper-sensitive market than normal, specifically NGLs, we saw a pretty decent run-off in May and June of the prices and they've come off precipitously since then. I guess, just given what your operating group is seeing now, how much confidence in there that the fourth quarter is going to be typically – or allow the typical strength that sits there during the calendar year?

A lot of that NGL volume is contracted for – it doesn't – but a seasonal contract. So, we're very confident that, over the winter season, we'll generate that NGL seasonal type of revenue. There's always a question of whether you see stronger weather or weaker weather conditions in the fourth quarter versus first quarter. So, there could be some slippage one way or the other between fourth quarter and first quarter, but the volume is contracted for.

Yeah, Brian, so we'll 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 third quarter – excuse me, fourth quarter or in the first quarter, depending upon when they need it for weather balancing. So, as Harry said, we're going to capture the margin over, let's say, a four-month or five-month period. We just don't know if it's in the first three months of the five – four or five months or the last couple of months. We feel pretty good about our forecast. Obviously, if there's a erratic weather pattern, it could shift some of that profit from the fourth quarter to the first quarter. But the real seasonal swing that you see there, and you saw it on the graph that – or 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 first year – next year or we've had situations where they've actually pulled it into the fourth quarter and we've had the – large of that, you shouldn't get carried away and annualize it. So, we feel pretty good about, I think, in the forecast that we have out. It reflects everything that we know as of the time we put the forecast together. Brian D. Gamble - Piper Jaffray & Co.: Great. And then, last one for me. Greg, you mentioned the consolidation really hasn't happened yet, but you got plenty of rationalization, 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 market, anything changing in your view and over the last few months or even since the Analyst Day that has, I guess, prohibited things from happening that may loosen up in the back half of the year? Just any color from your perspective would be appreciated.

Yeah. If you ask me what area have we been consistently wrong in, it's in projecting the more consolidation because we see the rationale – the reason for it, but it's one of the hardest things to make happen and there is all kinds of issues that get involved in that. I think, anytime you end up with a, let's call it, head bake or resurgence in the market that makes everybody feel like we're only three months or four months away from everybody pulling out of a down cycle, it tends to freeze all discussions. So, 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. So, again, if you go back, I think we had this discussion five years ago, when 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, it remains to be seen. Brian D. Gamble - Piper Jaffray & Co.: I appreciate that, Greg. That's all for me.

Thanks, Brian.

Thank you. Our next question is from the line of Richard Verdi from Ladenburg. Please go ahead. Richard A. Verdi - Ladenburg Thalmann & Co., Inc. (Broker): Hi. 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 that growth project (41:04) wondering what is the company looking at. They could push any of the projects out longer or result in any of the projects coming to fruition sooner. And at the same time, wells is out there that could reduce or increase the amount of capital allocated to 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, you'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 kind of fulfill the obligations or commitments that we have made, $1.5 billion of that coming in 2016 and about $0.5 billion coming in 2017. As this chart shows, we've had some projects come in a little bit under budget. And so, that's changed. We've also had others that we've changed the scope. And so, that's kind offset. The biggest change so far is Diamond, for example, I think it's a permitting issue that we – it's going to cause us to have some of the capital spent early next year and fourth quarter of 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 of 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 broadening their footprint. We think there's enough takeaway capacity in most areas to service the foreseeable needs. And so, all you'd really need to do is be re-plumbing some of the existing in-field infrastructure or extending it to be able to get to that take-away capacity. So – 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 into single-digit returns, which we solved some of that in 2014. Richard A. Verdi - Ladenburg Thalmann & Co., Inc. (Broker): That's great color. Thank you. And also, I believe, the MVCs, I believe they were backed by about 78% of investment-grade customers and 47% of those, somewhere around that figure, were above A-rated, with the majority non-investment grade being refiners on demand pull projects. (43:53) I was just wondering if you can give us an update on the credit profile with counterparties. Is that still the same or has that changed?

Yeah, 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. Richard A. Verdi - Ladenburg Thalmann & Co., Inc. (Broker): Okay. Great. And then the last question, dovetailing off of that, for the Analyst Day, and I believe this is really compelling, the company 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.

Yeah, 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 in 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 it 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 just 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 take-away 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 tighter in supply and demand balance.

And better margins as opposed to volume and...

Right.

As it tightens up, we should see better margins.

Yeah. It's absolutely margin related.

And then, Richard – and that was on I think 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 is pretty confident about is the Permian and half of that pipeline and 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. We're right now around 2 million barrels a day in the Permian. So, as we get to 2.3 million barrels a day, you're starting to get close to capacity and things tighten up and realizing that even with what sounds like 200,000 barrels a day of capacity relative to the 2.5 million barrels a day that's currently there, if a refinery goes down or another pipeline develops a problem, it's 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.

So, there will be more pipeline capacity in 2018 out of the Permian, too, so that will 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 that. So, we're not forced to just build organically to grow, but we've got a lot of capability in the existing system. Richard A. Verdi - Ladenburg Thalmann & Co., Inc. (Broker): That's super. That's great color. Thank you very much for the time guys. I appreciate it.

Thanks, Richard.

Thank you. We have a question from the line of Patrick Wang from Baird. Please go ahead. Patrick C. Wang - Robert W. Baird & Co., Inc. (Broker): 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 times 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?

Yeah. I'll take a shot at it. Clearly, the most preferred and best alternative to de-lever is cash flow growth, and we expect cash flow growth from the capital projects, the MVCs that will come on, as well as ultimately from an industry recovery. Industry recovery is 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 is 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. But 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 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, 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.

Yeah. I would also say, Patrick, that every move that we make from this point forward is going to be with the focusing 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 proven thing for us to do. You'd probably see us finance it with a little more equity than we would normally do on our 55, 45. (51:01) So, it's – we're going to beat this thing with everything we've 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 and the rich – adjusted risk profile to be an attractive investment for our equity holders. Patrick C. Wang - Robert W. Baird & Co., Inc. (Broker): Okay. That's very helpful. That's it for me. Thanks for the time.

Thank you. Our next question is from Justin Jenkins with Raymond James. Please go ahead. Justin S. Jenkins - Raymond James & Associates, Inc.: 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. It looks like, based on unit count guidance for 4Q 2016, there's some decent ATM issuance planned. Can you guys just give us a sense on how opportunistic you plan to be with ATM in the back half of 2016 and into 2017?

Yeah, 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. Justin S. Jenkins - Raymond James & Associates, Inc.: Okay. When I do the math there, it looks like there's between 5 million units and 10 million units. Just curious if there's a decent chuck of ATM in there and then maybe how we think about it in the 2017 on the ATM?

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

I think, to use your number, I mean, 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, a fairly minor impact on DCF per unit. Justin S. Jenkins - Raymond James & Associates, Inc.: Okay. No, that's perfect. I appreciate the color guys.

Thank you.

Thank you. And 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.