Ladies and gentlemen, we’d like to thank you for standing by and welcome to the PAA and PAGP Third Quarter Results Teleconference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session with instructions being given at that time. (Operator Instructions). And as a reminder, today's call will be recorded. I would now like to turn the conference over to your host and your facilitator, as well as the Director of Investor Relations, Ryan Smith. Please go ahead, sir.

Thanks, Steven. Good morning and welcome to Plains All American Pipeline’s Third Quarter 2014 Results Conference Call. The slide presentation for today's call is available under the events and presentations tab of the Investor Relations section of our Web site at www.plainsalllamerican.com. In addition to reviewing the recent results, we will provide forward-looking comments on PAA's outlook for the future. In order to avail ourselves of Safe Harbor precepts that encourage companies to provide this type of information, we direct you to the risks and warnings included in our latest filings with the Securities and Exchange Commission. 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 guidance and non-GAAP reconciliations tab of the Investor Relations sections of our Web site. There you’ll also find a table of selected items that impact the comparability of PAA's financial information between periods. Today’s presentation will also include selected financial information of Plain GP Holdings, or PAGP. As the control entity of PAA, PAGP consolidates the results of PAA and PAA’s general partner into its financial statements. Accordingly, we do not intend to cover PAGP’s GAAP results. Instead, we have included a schedule in the appendix to the slide presentation for today’s call that reconciles PAGP’s distributions received from PAA's general partner, with the distributions paid to PAGP shareholders as well as the condensed consolidated balance sheet. Today’s call will be chaired by Greg Armstrong, Chairman and CEO. Also participating in the call are Harry Pefanis, President and COO; and Al Swanson, Executive Vice President and CFO. In addition to these gentlemen and myself, we have several other members of our management team present and available for the question-and-answer session. With that, I’ll turn the call over to Greg.

Thanks, Ryan. Good morning and welcome to all. PAA reported strong third quarter 2014 results yesterday afternoon reporting adjusted EBITDA for the quarter of 527 million. Solid execution in all three segments combined with certain timing shifts between the third and the fourth quarter periods resulted in across-the-board over-performance relative to the midpoint of our guidance range. These results were $47 million or 10% above the midpoint of our guidance for the third quarter of 2014. Slide 3 contains comparisons for a variety of metrics to our performance in the same quarter of last year and our third quarter 2014 guidance. Compared to last year’s third quarter, PAA realized a 47 million or 10% increase in adjusted EBITDA. Adjusted EBITDA was up 9% in PAA fee-based transportation and facility segments, primarily due to increased production expansion projects across our asset footprint generally in the Permian Basin and Eagle Ford areas in particular. Adjusted EBITDA was up 14% in PAA supply and logistics segment due to the favorable crude oil market conditions, partially offset by less favorable NGL market conditions during the third quarter of 2014. As reflected on Slide 4, this marks the 51st consecutive quarter that PAA has delivered results in line with or above guidance and we remain on track to achieve our 2014 goals. For this quarter, PAA declared a distribution of $0.66 per common unit or $2.64 per unit on an annualized basis payable next week. Consistent with our 2014 distribution goal, this distribution represents a 10% increase over PAA distribution paid in the same quarter last year and a 2.3% increase over PAA distribution paid last quarter. Distribution coverage for the quarter on a standalone basis was 102% and is expected to be approximately 111% for the year. PAA has now increased its distribution in…

Thanks, Greg. During my portion of the call, I’ll review our third quarter operating results compared to the midpoint of our guidance, discuss the operational assumptions used to generate our fourth quarter guidance and provide an update on our BridgeTex acquisition and then our expansion capital program. I'll also provide a little more information on BridgeTex. As shown on Slide 8, adjusted segment profit for the transportation segment was $237 million, which is approximately $7 million above the midpoint of our guidance. Volumes of 4.2 million barrels per day were approximately 91,000 barrels per day higher than our guidance. Adjusted segment profit per barrel was $0.61 or $0.01 above the midpoint of our guidance. Segment profit benefited from higher than forecasted volumes on our Eagle Ford area systems, Basin pipeline, Capline pipeline and White Cliffs pipeline. However, these increases were partially offset by an operational disruption on our Rainbow Pipeline system, which resulted in 18 days of curtailed movements due to the receipt of a large volume of water into the system for at least one producer. Adjusted segment profit for the facilities segment was $149 million, which was approximately $14 million above the midpoint of our guidance. Volumes of 121 million barrels of oil equivalent per month were 1 million barrels below the midpoint of our guidance. However, adjusted segment profit per barrel was $0.41 or $0.04 above our guidance. The increase in segment profit per barrel is most notably due to NGL component gains related to our Canadian fractionation operations and higher throughput volumes at our Cushing Terminal. Adjusted segment profit for the supply and logistics segment was $141 million or approximately $26 million above our guidance. Volumes of 1.1 million barrels per day were in line with the midpoint of our guidance. Adjusted segment profit per barrel…

Thanks, Harry. During my portion of the call, I will provide a general overview of our financing activities, capitalization and liquidity, as well as our guidance for the fourth quarter and full year of 2014. However, before doing so, I want to discuss our financing plan for the BridgeTex acquisition as well as touch on the accounting treatment for this investment. We will finance the acquisition in accordance with our established financial strategy, which requires at least 55% equity. We have a proven history of being able to rate significant amounts of equity through the use of our continuous equity offering program, and we intend to use this program to raise the required equity. On the accounting side, since we will be a 50% owner in BridgeTex, we’ll account for this investment under the equity method of accounting. It will be reported in one line on our balance sheet titled Investment in Unconsolidated Entity and in one line on our income statement titled Equity Earnings in Unconsolidated Entities. This is similar to other 50-50 JVs that we own including our Eagle Ford JV. As Greg stated in his opening remarks, the transaction is contingent upon the completion of a secondary offering of Oxy’s PAGP shares. As disclosed in our BridgeTex press release this morning, we launched a secondary offering of 55 million shares of PAGP or approximately $1.5 billion. PAGP will not receive any of the proceeds from this offering, but it will result in additional liquidity and tax yield for PAGP. Returning to third quarter items, we completed several financing transactions during the quarter. First, we remained active from an equity financing perspective with our continuous equity offering program. As illustrated on Slide 14, PAA sold approximately 3.6 million units in the third quarter raising net proceeds of $216…

Thanks, Al. As demonstrated throughout the call, PAA has a very high level of organic expansion activity going on in almost every major crude oil resource play. Importantly, PAA continues to execute well and we remain on track to meet or exceed each of our 2014 goals. We are pleased with our positioning and growth prospects as evidenced by PAA’s and PAGP’s perspective midpoint 2015 distribution growth targets of 8.5% and 21% despite being in the midst of a transitioning oil market. These midpoint distribution growth targets will be increased to 10% and 26%, respectively, upon closing of the BridgeTex acquisition. We thank you for participating in today’s call and for your investment and trust you place in us by making an investment in PAA and PAGP. We’re pleased with our positioning and we look forward to updating you on our fourth quarter earnings call in February of 2015. Steve, we’re ready to open it up to questions.

Ladies and gentlemen, we’ll now begin the question-and-answer session of today’s conference. (Operator Instructions). Our first question will come from the line of Brian Zarahn of Barclays. Please go ahead.

Good morning.

Good morning, Brian.

Greg, over the past few months and certainly the past week, you’ve made a lot of project announcements from Diamond to the Oklahoma, Texas, Eagle Ford expansion, Capline study and now BridgeTex this morning. Strategically, can you give us your view of how the impact of all these additions to your asset base impact your three business segments? And also from a higher level, how do you see growth opportunities from these assets being integrated into your system?

The first question is kind of pretty easy. About, Brian, 99% of all capital that we spend on expansion is associated with either our terminal or facilities – our facilities or our transportation segment. So these are all basically underpinned by fee-based arrangements. And from a standpoint of the returns by the way continue to remain very attractive. Certainly competition has increased over the last couple of years, but because these are extensions of existing assets or allowing us to connect two assets together, we’re still able to maintain a high level of mutual synergies within that asset base. So we’re still getting mid to low teens type return against – even a cost of capital in today’s environment that I think when we recalculate, it’s about 7.2%. So we’re looking at 500 to 600 basis points. So financially, certainly very complementary and constructive to future growth. And as Al mentioned, what we spend in really '14 you won’t see until partially in '15 and the most of it in '16 and the same thing for what we’ll be spending next year. As far as – there’s certainly other opportunities for these investments to beget incremental opportunities. We’ve certainly looked at what happens when we get our pipeline to Memphis built, what that will do for the potential to optimize Capline. I can’t say much about that other than to say it opens up a lot of possibilities. The ability to finish the Cactus line and connect it with our assets in South Texas allows us to get West Texas crude oil to the water at Corpus, which we think is going to be probably an advantageous site over some of the other areas on the Gulf Coast. And then we’re really just kind of helping to plumb and re-plumb activities that are going on in Cushing. I think several years ago there was a question; was Cushing going to be relevant given everything that’s moving to the Gulf Coast? And I think the conclusion almost everybody would draw today is not only it is relevant, it’s more relevant and it’s become even more of a spider web of connectivity to be able to be the melting pot, if you will, for all of the different groups coming from different directions. And then the increased connectivity to the Gulf Coast has actually even helped the viability of Cushing long term. So, hopefully, that covers most of your questions. If not, I’ll take another shot at it.

I’ll just add. Just a real simple way to also say it is really if you just look at it, we’re sort of expanding the integration of our footprint particularly in the Permian and Eagle Ford and Cushing.

I think along those lines, certainly making a greater push towards the water, and maybe you could elaborate a bit on what you’re doing in Corpus potentially? I know BridgeTex is largely contracted, but access to Texas City. And then potentially with Capline, if that does get reversed opportunities in St. James, how do you sort of view the long-term opportunity for process condensate and other export opportunities?

Well, if the government will get out of the way we’ll prove that crude oil is a worldwide commodity. I think what you’re saying, Brian, is basically commerce is functioning not with the help of but despite Washington’s objections. And so once again, we’re trying to balance the system. And light crude needs to find its way into markets that want light crude and we need to continue to bring heavy crude in. And if they put a rule in that says you can’t do that, then we’ll re-plumb the system again. So a little clarity wouldn’t hurt. From a standpoint of question on exports, as we’ve indicated in prior calls, we have probably we think the best asset base amongst all of anybody, especially given our position; the Eagle Ford in South Texas to be able to source, process, segregate, transport and export process crude oil and condensate and we think PAA has the highest volume, the most sophisticated independently-owned condensate processing unit for a stabilized product in the U.S. today. And then once we plumb in, by the way, our Cactus system which will connect West Texas to the South Texas area, then the value of that only improves. So I think what we’ve seen so far is that on the exports, following the issuance of the private letter rulings to Pioneer and Enterprise, a variety of reasons including politics we believe contributed what appears to be a cessation of progress with respect to other companies’ similar request for letter rulings, and it really appears to be regardless of the merits of their proposal. It’s more candidly politics. Clearly that’s frustrating to us and other exports. Year-to-date, we have not exported any product under a self-determination avenue. But since our last few calls, we have sought extensive legal and engineering advice and have been comforted by the recommendations and the advice basically says, everything we’re doing isn’t compliance with our objective and objective interpretation of the various rules and regs under what you would be permitted to export products. So I can’t really give you much more comment on the export issue other than if you ask me a question about it next call, I think I’ll have a short brief answer for you.

Okay, I appreciate that. Last one for me is obviously given your announcements, no impact on your CapEx spending due to a lower crude environment. But maybe you could elaborate a bit more if prices stay roughly where they are and the discounts – some crude is in the $60 range – high 60s or so. Do you see potential impact on producers willing to commit to projects or when contracts come up for renewal? I mean how do you sort of think about this if we’re in an extended period of $75 WTI?

I think we’ve been guilty, as you know, preparing for nine out of the last two recessions. So we’ve been prepared candidly for what’s happening today and actually I’ve talked about it extensively. And so our belief is, is that the duration of these depressed prices probably is – again, it’s in the shortest six months and probably as long as two years. And it kind of helps clear out some of the underbrush. I think it will reduce competition for new organic growth projects. I think there’s some organic projects that have been announced that won’t get committed. I think everything that we have announced is going to get done. It was underpinned by good fundamentals regardless of the frothiness of the market. We also think, by the way, it’s going to open up the door for probably less competition for acquisitions and more focus on fundamental synergies, not how much money you can raise to try and buy assets. So for PAA’s perspective, we feel very well positioned. We do think that there will be a decrease in activity. I mean if you just do the math, a $10 decrease reduces cash flow available to all E&P participants in the U.S., that’s about 32 billion a year. And if you allow 25% for royalties and taxes, that means there’s about a $22 billion hole in the pocketbook for those that were spending 100% of their cash flow. If you exclude the major, some of them will continue to spin through it. You still have a pretty big number when you think – let’s say that $18 billion to $20 billion reduction in cash flow that’s available to fund capital when we estimated that the total amount of capital being spend on just the crude oil drilling activities and…

Thanks for the color, Greg, really appreciate it.

Thank you.

Our next question will come from the line of Steve Sherowski of Goldman Sachs. Please go ahead. Steve Sherowski - Goldman Sachs & Co.: Hi. Good morning. Greg, in your opening remarks, you noted that the difference between the low and high range of Plains distribution outlook was partially due to conservatism just given the lower crude price environment and the potential impact that could have on drillers. I know this is sort of a difficult question, but I’m wondering can you provide any sensitivity to crude oil prices and just the different levels of distribution growth relating to your outlook?

What we try to do, Steve, is first off, we’re not really exposed to the direct impact of commodity prices but we are, as you point out, exposed to the indirect that is to say if there’s less volume in transport, our fee-based activities won’t have as much volume. But in many areas, we’re the critical player in connecting those markets. And so we think we’d probably get the base loaded. Some cases, for example, on basin, we had the cheapest tariff out of the basin. I think our all-in price is probably $0.75 to $0.80 a barrel competing against at the margin $3.50 to $4 a barrel. So we feel pretty good about our position going forward. With respect to the range of 7% to 10% with the midpoint of 8.5%, if we were at our lower end of our EBITDA guidance, we would still be somewhere within that 7% to 10% distribution growth able to meet that distribution growth objective using just organic growth and still meet, as Al mentioned, our kind of minimum target coverage of 105 to 110 coverage. So we think that’s rather unique quite candidly across the MLP space because we think many others are – weren’t carrying as much coverage as they came into this. So, we think we got a pretty resilient range there. If you’re asking me what oil price would we be at the higher end, lower end range, really that’s not the relative question. It’s what the activity levels are doing out there. And again, we’re in all the right basins with the right assets, so we feel pretty good about the range that we put out there. I think if there’s conservatism, it’s certainly in the supply and logistics. I think we’ve got 570 million is our forecast…

There is a minimum level of capacity that’s required to have an efficient movement of crude of the Capline 40-inch pipeline, so it needs a fair amount of crude.

About 250,000 to 300,000 barrel a day is probably close to the bottom end of the minimum, Steve. And if you think about it, it’s a couple of issues. One is the turbulent velocity, the ability to keep the oil churning enough to not let water settle on the bottom of the pipe. And the second is transit time. Probably anything around 250,000 to 300,000 barrels a day, you could walk backwards faster than that’s oil moving through the pipe. And so I think it puts pressure on all the owners to look at alternatives. Two of three owners are already going to explore those, and we think for the reasons you just mentioned when that thing goes into service, there’s a tendency when reality shows up, people start making rational decisions.

It’s not just Diamond, there are other projects to bring Bakken crude oil into that Patoka area as well. So when you look at combination of all of the projects that are being developed, it does put a lot of pressure on the south and north movement.

We’re optimistic that as the calendar rolls forward, we’ll probably have some alternatives to do something constructive with Capline. To put it in perspective, I think it’s probably less than one-half of 1% contribution to our EBITDA right now. So anything that we can do with that is potentially huge. Steve Sherowski - Goldman Sachs & Co.: Yes. No, understood. Thank you. That’s it for me.

Thanks, Steve.

Our next question will come from the line of Mr. Mark Reichman of Simmons & Co. Please go ahead. Mark Reichman - Simmons & Co.: Hi. Just a few questions. If you consider recent pipeline announcements, what are your expectations for Cushing inventories through 2015?

Mark, I’m going to not ask your question not because we don’t think we have an answer but because we think we have a competitive advantage in knowing our answer. But we certainly have a view. Yes, I think today we’re probably running around 22 million barrels of inventory. It’s been as high as well over 40 and we’ve got a shale capacity up there that’s probably 80. And keeping also in mind here – again, I’m going to get kicked under the table if I go too far, but between Cactus, BridgeTex and Permian Express 2, in the next 12 to 18 months you’re going to see almost 700,000 barrels a day of light sweet crude getting aimed directly towards the Gulf Coast under take or pay contracts. And there’s not 700,000 barrels a day of light sweet crude to back out of the Gulf Coast. And so that tends to tell you that you may start to see some crude back up in the Cushing and there’s plenty of tankage to fill that up. But it’s a little bit like one of those – I can’t remember the name, water sprinklers that kind of goes back and forth where it kinds of just ratchets across and ratchets back. We think that you’ll see volumes that kind of yo-yo up and down in Cushing for some time to come. It’s going to be the pressure relief valve to balance the system. Mark Reichman - Simmons & Co.: I appreciate that. And with respect to the evolution of condensate supply in the Permian, is it becoming more challenging or is the market adjusting to the condensate production?

Right now it’s price adjusting in some areas, but the forecast – the increase there, it’s gone from, just to put it in perspective, five years ago the Permian Basin production as a whole was probably 850,000 barrels a day. It’s double. Today’s it’s 1.7 and we’re forecasting that it’s going to increase another 50% again. The majority of that volume coming on is really light stuff. So the bottom line is, is the issue is going to have to be dealt with and we think quite candidly Cactus is a part of the answer, BridgeTex is a part of the answer. But trying to get it to the right home and where you can do something with it, whether that’s a process of turning it into something exportable or blend it with something heavier and turn it into something that’s digestible to the refiners. And so right now, everything goes into one common stream and the Delaware Basin is probably where some of the latter production is, probably not as light as the light stuff in the Eagle Ford but lighter than the common stream at Midland. So probably going to end up with some segregation of the lighter grades coming out of the Delaware Basin.

And it’s not inconceivable to not end up with separate systems, one that carry what you and I would refer to as crude oil and others to carry condensate if the economics make sense. Mark Reichman - Simmons & Co.: Right. And then also in the press release this morning, I guess the level of shipper commitment on the BridgeTex was 80%. And I thought there was a second open season. Is that the level of shipper commitment following that second open season? And is that kind of where you’d expect it to kind of level out under these longer term commitments?

It does include the second open season. So the capacity is going to be – the rest of the capacity is market driven to the extent the arbitrage there to move to the Gulf Coast versus Cushing that will go to the Gulf Coast and BridgeTex will be able to handle some of the extra capacity going to the Gulf Coast.

Mark, remember that 10% of it by tariff structure has to remain available to walkup shippers. So if you were at 90% contractually committed, you would effectively be 100% of what you could commit. So effectively, as Harry has mentioned, 80% is contracted, 10% is walkup, which only leaves 10% available for the swing there. If we did expand it, there is the ability to expand with pumps, so I think another 60,000 barrels a day and that would – you’d be looking at contracts or at least supportable demand to be able to support that expansion. Mark Reichman - Simmons & Co.: Great. Thank you very much. I appreciate that.

Thank you, Mark.

Our next question will come from the line of Vikram Bagri of Citi. Please go ahead.

Hi. Good morning, guys. It’s actually Faisel from Citigroup and Vikram’s with me too. I just wanted to understand the guidance on the transaction, about 1.5% accretive. I just want to make sure that that includes sort of the $100 million in EBITDA you talked about and that – does that $100 million EBITDA assume a full utilization of the pipeline? And I have some follow ups related to that.

The accretion is based upon what we would forecast the cash flow contribution would be, so we’ve given a range I think of 100 million to 105 million. That number will move as you go forward in time, because of tariff escalations which are tied to standard indexing, Faisel. So the 1.5% is tied to effectively achieving that run rate. That does not assume 300,000 barrels a day move through the system 365 days a year. It assumes effectively probably a 92% type utilization of the pipe. And the reason for that is, as you really can’t run 300,000 barrels a day 365 days a year, so there’s standard metrics that you’ll use whether you assume that you run 22 or 23 hours out of a 24-hour day. But it assumes a fairly high utilization of the usable capacity once you’ve allowed for operational management. Does that make sense?

Yes, that totally makes sense. I just want to understand – obviously, you’re debt financing it initially with your loan facility or bank facility and then you talked about how you plan to finance this with equity over time. So I’m just wondering, does the 1.5% include sort of the issuance of equity or does it include your normal sort of ATM sort of issuances?

It includes the issuance of equity but we’re planning on using it through the ATM. So when we came up with those numbers, we – like we do with all of our forecasting, we forecast our equity needs are funded throughout the year. And so we’ve layered that in throughout our forecast for 2015. So we’ll just either maintain or step up the CLP program or the at-the-market program a little bit to meet that funding. I’m not going to rule out that if the markets become very enticing that we would do an overnight deal, but we really don’t have to do an overnight deal because we’ve pre-funded so much of our 2015 capital program. All we have to do is let the CLP program run on autopilot, then it’ll fund the balance.

We also burden that accretion calculation with long-term fixed rate deal issuance as well. We don’t plan to keep stuff on CP at 30 basis points when we’re talking accretion.

Okay.

So the assumption in the model or the accretion that we gave you is 55% equity financed, 45% is debt financed using our 10-year cost of capital. And our 10-year cost of capital today is probably in the 3.6, 3.7 range.

Okay, makes sense And then on BridgeTex, did Magellan have a ROFR on this asset, so they’re the operator? And I guess was there a horse trade that went on in the background here with the Houston leg of the asset in order to I guess to extinguish that ROFR?

Yes. I’d say horse trade, goat trade and pig trading.

Okay, makes sense. I just wanted to make sure I wasn’t missing anything. And then just on the rest of Oxy’s interest, I mean clearly coming ahead of the lockup period here, it’s a little bit of surprise to the market. What’s the indications on the rest of their position? Is that going to come sooner than later?

Well, I think that’s totally in the hands of Oxy in general and Steve Chazen in particular. You’re not going to put those guys in a corner. They don’t have to have money, they’ve got a lot of it. I think clearly this is a strategic element of their buyback plan. And if you recall, if you follow their slides in the past conference calls, I think they’ve equated starting probably three quarters ago that their holdings in PAGP equated on an after-tax basis to a set number of Oxy buyback shares.

Yes.

Okay. So I don’t think they’re trying to buy it back all overnight in one deal. This is the first step of what I think would be a prudent liquidation. What this transaction gives them is, as you mentioned, the acceleration and we’re part of the horse trade. I don’t think they really wanted to sell this asset. We approached them and said, we’ve got something to offer to you that nobody else can offer through a ROFR or otherwise, and you got an asset we want. We’ve got something that we think we can deliver to the table and we structured a win-win transaction. This offering will increase the float quite a bit and that decreases the level of percentage of overhang of what they have remaining. And I think their buyback plans are over a multiyear period on the stock and I think we can be a part of that. And certainly they’ve shown faith and patience in this. We tried to catalyze this first transaction using tools that we had available to us to give them something they couldn’t get from somebody else to get an asset that we wanted.

Okay, yes, it makes sense. And then on the preliminary CapEx guidance, the $1.5 billion to $2 billion for next year, a pretty wide range. It sounded like these current commodity prices aren’t really going to dictate too much of that differential. What really is sort of driving the difference between the low end and the high end there, just so I understand sort of the flexibility?

Yes, I think what you should take away from that is a lot of projects – we don’t have the multiyear, multibillion dollar projects which we think is a virtue, because those tend to be the ones that get extended, have overruns and just have a lot of frustration. What we had indicated last year when we were pressed on the calls about what should we expect for next year – just real quick, if you go back to 2012, I think we started the year with 1.2 billion of target and we ended up at 1.6 billion. We ended up this year – I think we started at 1.5 or 1.6 and we ended up at 2, and we gave indications about six months ago that we thought we would at least have roughly 1.5 billion plus or minus. The takeaway is, is that we’ve got at least that plus we’ve got other projects that allow us to think we can fill it on up to 2 billion. And hopefully, Faisel, we’ve started at the bottom and work our way up as we bring projects to bear, I think another distinguishing difference about PAA relative to others is we don’t announce and include it in our capital guidance until we’ve actually got a deal as opposed to based upon a speculative or hopeful open season about what we might want to build. Generally speaking, we announce transactions when we’ve got something done. So thinking about it, 1.5 billion to 2 billion, so I’ll just pick the midpoint of 1.750 billion gives the ability for analysts to model what’s going to impact our P&L not in 2015 but in '16, '17 and '18 because these projects generally have a 12 to 18-month gestation period where you’re in the execution, then you’re in the ramp up phase. So effectively every time we announce this, it really has minimum impact – in a capital program minimum impact on the next year and the year after that. It’s the second and third year.

Okay, got you. And then last question for me. On the St. James terminal and also your rail terminal in Canada – in terms of St. James, what’s the capacity now at the terminal to bring rail into that facility? And are you moving sort of neat bitumen yet or is that a plan with some of the assets you have?

No, we’re making modifications so we can bring in heavier Canadian crude. I’m not sure it will be neat bitumen, it’d probably be under blended crude that would probably work better into the terminal than neat. But the facility at St. James can unload two unit trains a day, so 130,000, 140,000 barrels a day. We’re just making the modifications to accommodate the heavier crude stream and a little bit of segregation in the unloading facilities.

Okay, so it’s not – it can’t take heavy crude yet, but it will be able to shortly.

Correct.

Got it, okay. Thanks, guys.

Thank you.

Our next question comes from the line of Abhi Sinha from Wunderlich Securities. Please go ahead.

Yes. Hi. Good morning, everybody. So just to follow up on the previous question on the BridgeTex pipeline, when you said your model is based on 90% utilization, what is the ramp up period you have [maintenance] (ph)? Is it a year, a year and a half or it’s less than that? Right now, I think it’s 50% utilized or lower than that?

No. There’s two issues there. One, volumetrically – some of the contracts, Harry, don’t actually start until early next year.

Yes.

So right now, some of the barrels coming through there are some of the lower tariff barrels, so the ramp up is not so much volume metric ramp up, but there is some of that, but it’s more value ramp up. So probably by the time we get to March 1, 2015, we should be at the full physical and contractual run rate capacity.

All right, sure. And then another thing I want to ask is about the Midland Cushing differential. I mean we see that tightening probably because of BridgeTex came online. What trend do you expect there as BridgeTex ramps up and how does that impact the S&L segment, how should we think about that?

We think a lot of these steps that we’ve taken both in – Cactus will come on stream in the second quarter of next year and BridgeTex we just talked about will be fully up and running, let’s say, by March 1 where everything is kind of a [blind out] (ph). And I think Permian Express too is supposed to come on stream late in 2015. And then as Harry mentioned, we’ve done a lot of debottlenecking behind the scenes to be able to get crude within the basin to the right place. I think the answer to your question is somewhat characterized on Slide 13. And what you’ll see on the Slide 13 of our earnings call right there is that we’ve shown what the ramp up we think is in production growth, which on the near term, even though prices have come down, probably is going to maintain that trajectory. It’s the outer part of that curve that’s probably – as Harry mentioned if prices are a little bit lower for an extended period of time. But what happens is there’s just not a lot of slack in that picture that you see there for refineries to go down or for pipelines to have to pull maintenance. So anytime you have a refinery, let’s say – everybody plans for it, Abhi, and so what happens is if you got a 200,000 barrel a day refinery that knows it’s going to go into a five-day turnaround, they try to create a 1 million barrels of storage to be able to move their crude into and probably get a chance to pull it. If we end up with that refinery staying in the turnaround for 10 or 15 days, you’re going to back the system up and also differentials are going to widen out. So, as we get that tightened up, it’s going to be an issue of just how many operational interruptions did you anticipate and how many did you not. And if production starts to rise faster, I mean we’ve been rising – I think we started the year thinking production was going to rise at an average of like 20,000 barrels per day per month and I think we hit a period in there where it was closer to 30,000 barrels per day per month. That’s a pretty big difference on a four or five-month basis. So we don’t think the issue of the Midland Cushing differential having volatility has gone away, but it does feel like it’s going to narrow up quite a bit.

And that’s reflected in the guidance for next year.

Sure. Thanks a lot for that color. One last question, if I could, just on a bigger picture. I’m trying to understand like what rules does rail have in defining the spread between WTI and brand here? I mean, how much demand on the East Coast for light sweet, I think 600,000, 700,000 barrels, let’s say, you think needs rail service? I know they are many moving parts to it, but just based on the rail needs, do think there’s a flow that could be defined to this spread here?

It’s almost like those two markets are a little detached now. It seems crude from the Bakken, we have a lot of rail facilities, it makes sense to go to the East and West Coast and that’s where it’s going to go unless you can get lower price rent-based crudes into the East Coast. But you’ve got declining production in the North Sea. So it seems like the markets are a little bit detached there.

Abhi, if I can steer back to the question on the WTI Midland Cushing differential, one thing and our guys pointed out to us, when we had $85 oil in a $10 differential, you had a $75 net wellhead price or close to the wellhead and today’s it’s $78 WTI in a $2 differential, you would actually be getting a higher price at the wellhead today than you might have a point in time. So part of our enthusiasm for the Permian is that and in relative terms, the price has come down on an index basis but at the wellhead hasn’t come down there as much. And the fact is you can argue that once these things are debottlenecked, it will actually go up slightly if the index stays at the same level.

Got it. Sure. Thank you. That’s all I have. Thank you very much, sir.

Our next question will come from the line of Colton Bean of TPH. Please go ahead. Brad Olson - Tudor, Pickering, Holt & Co.: Hi, guys. It's Brad Olson.

Hi, Brad. Brad Olson - Tudor, Pickering, Holt & Co.: Just a couple of hopefully pretty quick ones. As I’m thinking about your position moving crude out of the Permian, you’ve got obviously the Duncan, the Longview Pipeline, which you announced last night. You’re buying an interest in BridgeTex and obviously Cactus is also coming online here in the next couple of years. When I think about – or in the next year or so. When I think about kind of what each pipeline gives you in terms of market access, you’re obviously pursuing kind of a variety of different routes out of the basin. How should I think about the opportunity to expand BridgeTex, opportunity to expand Cactus, and maybe the interplay between those and the opportunity to build a new line from Duncan to Longview?

You should probably think of it as probably nobody but PAA could do all that, because all of those, Brad, are basically extensions of our existing system or connecting our existing systems in a way to improve flexibility to the producers and that’s what it’s all about. I mean none of us knows exactly what the future holds either for absolute oil prices or for which areas are going to want a particular type of crude oil. What we do, though, is we know where the markets are, we know where the production is and we plumed our system together to give them the ability to get just about anywhere. And if we can’t get there by pipe, we can get there by rail. And so I guess you would – we’re building a business platform and improving upon it every year as opposed to building projects and that’s probably just a big distinction between us and some people that aren’t in the business that are trying to get into the business. They can maybe be able to compete with us getting from point A to point B but we’ll take it from point A to B, C, D, E, F or G. And nobody knows for sure which one of those you’re going to want to do three years from now. Brad Olson - Tudor, Pickering, Holt & Co.: Got it. And so when I think about BridgeTex’s obviously going into Houston, Cactus giving you the ability to dump off in Corpus Christi and then Longview also offering different market access, is the thought there that at different times you’re going to see different producers looking for different market outlets? And really anybody who gets on the plane system in the Permian could access any number of those market outlets?

I got a job for you as a marketer for us. And by the way, don’t forget the Diamond Pipeline which will get you up from Cushing to Memphis. Brad Olson - Tudor, Pickering, Holt & Co.: Got it, that’s helpful. Just trying to think about it as kind of an integrated system. And when we – I guess there’s been a lot of talk notwithstanding the drop in crude price about acceleration from producers in the Delaware further west in the Permian. And it seems – and correct me if I’m wrong here, but it seems like where the Basin pipeline has I believe a 240,000 barrel a day capacity all the way west into Southeast New Mexico, it seems like your pipeline would be about the closest proximity to some of the activity we’ve seen around the Pecos River where there’s a lot of this kind of Delaware drilling activity going on. Have you seen opportunities to potentially expand that 240,000 barrel a day portion of Basin? And with the activity from Duncan to Longview with potential expansions inside the Permian, is there an opportunity to really meaningfully expand Basin here in the next couple of years?

Brad, first I mentioned and part of my comments in the script that we are expanding the segment of basin from Wink to Midland by 500,000 barrels a day and that will be in service in first half of next year and as you could imagine we’ve got a few tackles coming out of Wink to give us better access from the Delaware Basin into Wink and then hopefully on to Midland where we can access all different markets. And then I also commented that we’re pretty aggressively looking at expansion of – extension of the Sunrise system from Colorado City up to Wichita Falls, which in essence creates another 200,000 barrels a day plus or minus into Cushing from the Permian Basin.

And I think what’s behind the curtain that you’re kind of alluding to is we’ve got a lot of other projects moving – that we’re thinking about extending and modifying our system as you go further west from Midland and into that area, the Delaware Basin, and that may get you a part of what fills the gap between the $1.5 billion and $2 billion on our cap budget for next year. Some of those – again, we don’t usually announce those until we have a crystallized project as opposed to a theoretical project. Brad Olson - Tudor, Pickering, Holt & Co.: Great. That’s great color. And just to jump around a little bit, on the BridgeTex acquisition, you made some comments about a potential right of first refusal between Oxy and Magellan, but I guess my question is from a little bit of a different angle, was there a – is there a ROFR that exists between PAA and Oxy as a result of Oxy’s ownership of PAGP that would have influenced the outcome here with the BridgeTex deal?

Amongst all the owners in PAGP that are in the private entity that the portion hasn’t converted into the PAGP shares, there are ROFRs in there, yes. Brad Olson - Tudor, Pickering, Holt & Co.: Got it. Okay. And then just one final one. As far as the expansion in the Eagle Ford with Enterprise, the 2017 dock expansion, I know you guys have kind of talked in the past about how uniquely positioned you are to handle some of the segregated condensate that has arisen from kind of the peculiarities of our export laws. And I guess I’m trying to understand whether that dock expansion, is that specifically focused to handle segregated condensate volumes or is it really kind of a multi-product dock that really will be positioned for kind of whatever comes out of the Eagle Ford?

Brad, probably the better way to say it is on our Eagle Ford pipeline system, we have several segregations on the pipeline originating from Gardendale all the way down to Corpus Christi. We have an existing terminal there, so already segregating various grades of condensate and crude. And we can already go into a barge dock or an existing barge dock into third party dock facilities. What we’re seeing and expecting is that longer term, the movements out of Corpus Christi are going to be on larger sized vessels and there’s going to be more demand to be able to load ocean going vessels out of Corpus Christi whether it’s for any of the three or four grades of Eagle Ford condensate, they are plus. You’ve got Cactus crude that’s also coming down into that same facility. Does that make sense? Brad Olson - Tudor, Pickering, Holt & Co.: Yes. That’s helpful. I guess the one…

Brad, I’d just make the point that if part of the question is whether the viability of that project is underpinned by a belief about exports or not, it’s not. I mean the ability to export or optimize through exports would be just that it’d be an optimization of that, but this was going to get billed regardless. Brad Olson - Tudor, Pickering, Holt & Co.: Okay, great. And I’m probably going to expose my ignorance of Corpus Christi geography here, but I know there’s a bridge in Corpus Christi that has been talked about as maybe being an obstacle to larger kind of Suezmax type vessels coming directly into the port. I think they’re talking about raising that bridge in '17 or '18. Is your project designed to coincide with that development, if at all?

I’m not exactly sure where our facility is located to the bridge, but I know that we’ve done a draft analysis and we can move vessels into and out of – the ocean going vessels into and out of our facility. Brad Olson - Tudor, Pickering, Holt & Co.: Okay. Perfect. That’s all I needed.

I think it’s independent of whatever they do with the bridge. Brad Olson - Tudor, Pickering, Holt & Co.: Okay, great. Well thanks a lot for the color, guys.

Thank you.

There are no further questions in queue at this time.

We really appreciate everybody’s time and attention on the call and those investors that are with us and hopefully will be with us for your trust in us. So we look forward to updating you on our call in February for the year-end results and the 2015 guidance discussion. Thank you.

Ladies and gentlemen, that does conclude our conference call for today. On behalf of today’s panel, I’d like to thank you for your participation in today’s conference call and thank you for using AT&T. Have a wonderful day. You may now disconnect.