Plains GP Holdings LP (PAGP) 2014 Q3 法說會逐字稿

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'll 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, Stephen. 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 website at www.plainsalllamerican.com. In addition to reviewing recent results, we will provide forward-looking comments on PAA's outlook for the future. In order to avail ourselves of the 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 section of our website. There you will 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 Plains GP Holdings, or PAGP. As the controlling 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 sheets.

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 overperformance 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 2014.

Slide 3 contains comparisons for a variety of metrics for 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 PAGP based Transportation and Facility segments, primarily due to increased construction expansion projects across our asset footprint generally in the Permian Basin and Eagle Ford areas in particular. Adjusted EBITDA was up 14% in the PAA Supply & Logistics segment due to the favorable crude oil market conditions, partially offset by a 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 a distribution represents a 10% increase over PAA's distribution paid in the same quarter last year and a 2.3% increase over PAA's 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 40 of the past 42 quarters and consecutively in each of the last 21 quarters. PAA's compound annual distribution growth rate averaged 8.5% over the last 10.5 years and 9.9% for the last 3 years alone. Additionally, PAGP's quarterly distributions of $0.19075 cents per share represents a 28% increase over the initial quarterly distribution included in PAGP's October 2013 IPO prospectus and a 4% over the distribution paid last quarter.

Before I address that PAA's guidance for the balance of 2014 and our preliminary shadow guidance for 2015, to provide some context, I would like to discuss some key market developments. Many of which we discussed as potential market scenarios at our June 2014 Analyst Day meeting, as well as various subsequent meetings and presentations. These included an expectation of excess global crude oil supply relative to demand, downward pressure on crude oil prices, and significant regional volatility.

In the last 45 days alone, WTI oil prices have fallen from around $95 per barrel to roughly $76 a barrel, and Brent prices has fallen from $99 a barrel to as low as $82 per barrel. Additionally, certain key differentials have tightened meaningfully and equity valuations and access to capital have been adversely impacted, especially with respect to the E&P sector.

In general, the energy sector appears to be in the midst of a transitioning market for crude oil as well as capital availability and cost of capital. As discussed at our Analyst Day meeting, although we are not immune to adverse impacts from these are type of developments, PAA's strategy anticipates periodic disruptions and our asset base and business model position PAA to be able to deliver solid results in a variety of environments.

With that in mind, yesterday evening, PAA furnished financial and operating guidance for the fourth quarter and full year of 2014 that reinforced the midpoint of our previous adjusted EBITDA guidance for 2014 of $2.175 billion. Additionally, we furnished a preliminary guidance range for 2015 adjusted EBITDA of $2.35 billion to $2.5 billion. The midpoint for adjusted EBITDA of $2.4 billion to $2.5 billion represents an increase of between 11% and 12% over the 2014 guidance midpoint and is underpinned by an approximate 21% increase in our fee-based Transportation and Facility segments, which is generally associated with our ongoing capital expansion capital programs.

The guidance includes a midpoint contribution for our Supply and Logistics segment of approximately $570 million, which is down about 11% from the midpoint of the current 2014 guidance as our outlook for this segment generally anticipates less favorable crude oil differentials in certain areas. And also weaker NGL markets than we've experienced in the last few years.

Our preliminary 2015 guidance was generated in the midst of these transitioning and volatile market conditions. Accordingly, we have attempted to incorporate judgments and embrace our views of the realities of recent market changes and associated uncertainties, and we believe it presents a prudent outlook.

Additionally, though we think volatility could and should present incremental market opportunities for our Supply and Logistics segment, identifying the location, timing and magnitude of such potential opportunities at this time is impractical. Accordingly, our guidance incorporates relatively modest benefits from potential volatility.

In recognition of the uncertain environment we are currently in, we are establishing a flexible target range for PAA's 2015 distribution growth of approximately 7% to 10%, which is measured from November 2014 distribution exit rate to the comparable metric for 2015 -- November of 2015. Given our adjusted EBITDA range, this flexible approach would enable PAA to maintain coverage ratios that are directionally consistent with the minimum annual coverage guidelines that we've discussed in previous calls.

At the 8.5% midpoint of this range, PAGP's corresponding 2015 distribution growth would be approximately 21% which takes into account the structural leverage of the incentive distribution rights as well as anticipated unit issuances at PAA. For PAGP, achievement of that level would represent a 55% increase over the initial quarterly distribution included in its October 2013 IPO prospectus.

I would point out with these guidance ranges do not incorporate the benefits of any pending or future acquisitions. This morning, we announced the PAA has entered into a definitive agree to acquire Occidental Petroleum's 50% interest in BridgeTex LLC for $1.075 billion. BridgeTex LLC owns the newly constructed BridgeTex pipeline. The other 50% is owned by Magellan Midstream Partners, which also acts as operator for the system.

The BridgeTex pipeline is complementary to PAA's West Texas operations as it originates at Colorado City where it will be connected with PAA's Sunrise pipeline, as well as our basin in Mesa pipeline systems. The BridgeTex pipeline transports crude oil to various refining markets along the eastern portion of the Texas Gulf Coast and later in the call, Harry will provide a more detailed description of the pipeline, as well as its operations and a summary of the overall contract levels, and Al will discuss our financing plans for the acquisition.

As set forth on slide 7, a condition when closing the transaction is the completion of an equity offering for a portion of Occi's PAGP ownership. To accommodate meeting that condition, PAGP's Board has agreed to waive the remaining term of that 15 month lockup that was put in place at the time of the IPO for the four largest owners of the GP, which includes Occi. The remaining three large owners, Kayne Anderson, the Energy Minerals group and PAA management have all agreed to waive their rights to participate in the Occi offering.

Additionally, in connection with the closing of the transaction, Magellan will purchase the Texas City leg of the pipeline from BridgeTex LLC. And Magellan has agreed to enter into a long-term capacity lease with BridgeTex, pursuant to which the BridgeTex shippers will continue to have access to capacity owned in the Texas City leg. The Hart-Scott-Rodino filing was made in early October based on a letter of intent, and the requisite waiting period has expired. Subject to the combination -- consummation of the secondary offering, we would expect to close the transaction before year end.

I would characterize this as an attractive, strategic and complementary long-term investment that adds flexibility to PAA's exciting existing asset footprint and expands PAA's access to Gulf Coast markets. The transaction also provides mutual benefits to both Occi and PAGP as it facilitates Occi's sale of a portion of its investment in PAGP and reduces the market overhang and also provides additional liquidity and incremental tax shield for PAGP shareholders. The BridgeTex pipeline affectively commenced initial operations in late September and is currently in the ramp-up phase which is likely to continue through the first quarter of 2015.

As noted in my comments earlier, the guidance we furnished in yesterday's 8-K filing does not include the benefit of this pending transaction. We anticipate PAA's share of annualized EBITDA from the BridgeTex LLC will range between $100 million and $105 million. And at the level, we expect the transaction to be approximately 1.5% accretive to PAA's 2015 distribution per unit and 5% accretive to PAGP's 2015 distribution unit per share.

Establishing an attractive and flexible baseline distribution growth for 2015 with acquisitions providing potential incremental growth we believe reinforces our view of the strength of our asset base, our business model, and our balance sheet in an uncertain market while also retaining the ability to adjust to unforeseen developments in a prudent and responsible fashion.

Looking at the industry sector from a macro perspective over the short term, we believe the key question with respect to whether or not producers will maintain capital expenditure activity at recent levels is not whether the resource plays are economically attractive at plus or minus $80 oil, because many are. But whether or not the producers will elect to fill the funding gap created by the decline in crude oil prices with incremental debt or issuing equity at depressed price levels. Alternatively, they can elect to decrease the pace of drilling and completion activity, or they can bring in third-party financial capital. But the latter of that generally takes time to negotiate and put into place.

Consistent with the views we discussed at our Analyst Day meeting this past June, our current belief is that the near-term capital expenditure activity levels and expectations for linear volume growth will be curtailed with producers allocating their capital among the resource plays using a variety of criteria. We believe the combination of increased demand and slower supply growth will balance the market within a reasonable period of time which, with a little help from Saudi Arabia, can be accomplished in as little as six months in as long as 18 months to 24 months.

Longer term, we remain optimistic about the outlook for continued US and Canadian volume growth and the positive ramifications for such growth from midstream companies in general and PAA specifically. Additionally, we have high hopes that this period of depressed crude oil prices and capital markets disruptions will carry with it attractive, reasonably priced acquisition opportunities that PAA will be able to capitalize on by using its strong balance sheet, operational and commercial synergies, and extensive acquisition experience.

With that link the introduction, I'll turn the call over to Harry.

Thanks, Greg. During my portion of the call, I will 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 was 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 movement due to the receipt of a large volume of water into the system for at least one producer.

Adjusted segment profit for the facility 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 was $1.36, or $0.22 of above the midpoint of our guidance. Overperformance was primarily due to more favorable crude oil differentials, particularly the Midland to Cushing differential and differentials in our Canadian -- in Canadian grades of crude oil.

Let me now move to slide 9 and read the operational assumptions used to generate our fourth-quarter 2014 guidance furnished yesterday. For our Transportation segment, we expect fourth-quarter volumes to average just under 4.3 million barrels per day, or about 54,000 barrels per day higher than that of the third quarter. Most of the volume increase relates to our Sunrise pipeline which will go into service in December.

We expect fourth quarter adjusted segment profit to be $0.66 per barrel, up from the third quarter which was adversely impacted by the Rainbow pipeline disruption. For our Facility segment, we expect an average capacity of 122 million barrels of oil equivalent per month, adjusted segment profit per barrel is expected to be $0.40, which is essentially in line with the third quarter segment profit per barrel. The slight increase in volumes as compared to third quarter is primarily due to our Bakersfield rail terminal which license services in November.

For our Supply & Logistics segment, we expect volumes to average just under 1.3 million barrels per day, or about 136,000 barrels per day higher than volumes realized in the third quarter. Adjusted segment profit per barrel is expected to be $1.39, or $0.03 per barrel higher than last quarter. The increase from the third quarter is primarily due to seasonal NGL sales volumes forecasted for the fourth quarter, partially offset by less favorable crude oil differentials.

With respect to our acquisition announcement and as Greg mentioned, we acquired an interest in the segment of the BridgeTex pipeline system that extends from the origination station at Colorado City to Magellan's East Houston terminal. This is a 400-mile 20-inch pipeline that has approximately 300,000 barrels per day of capacity. As illustrated on slide 10, this segment of the pipe was placed into service in October, and crude oil is being delivered into the Magellan Houston terminal.

I'll note that the portion of this segment -- I'm sorry -- while I'll note that the portion of the system that Magellan will acquire will be incorporated into its Houston distribution system. At closing, BridgeTex will enter into a long-term lease with Magellan that will provide BridgeTex with 300,000 barrels per day of capacity on the Houston distribution system.

The pipeline system is supported by shipper contracts ranging from 7 years to 10 years in length with options to extend. I'll also note the contractually committed volumes account for approximately 80% of the system's current capacity. About 10%, or half of the remaining capacity, was required to be reserved for walkup customers.

Let's now move to our capital program which is detailed on slide 11. As indicated by the level of our capital included in our 2014 plan and our expectation of a similar level for 2015, we have been at expect to be very active in several of the resource plays and demand centers of North America.

For 2014, we've made an upward adjustment of $100 million to our estimated expansion capital plan which resulted in our revised target of approximately $2.05 billion. This increase is not attributable to any single project and similar to last quarter, remains spread across a number of smaller opportunities. The expected in-service timing of the larger projects in our capital program is included on slide 12, and I'll provide a status update for a few of those investments.

In August, we announced plans to construct the Diamond pipeline, which is a 440-mile 20-inch line that will have up to 200,000 barrels per day of our capacity from our Cushing terminal to Valero's Memphis refinery. This is a $900 million project underpinned by a long-term shipping agreement with Valero and related contract for storage and terminating services at our Cushing terminal. The project is expected to be completed late 2016, and Valero holds an option until January 2016 to purchase a 50% nonoperating interest in the pipeline.

Last night we announced a new pipeline project to build a 16 inch pipeline from Duncan, Oklahoma to Longview, Texas. The pipeline has potential capacity of up to 150,000 barrels per day and will sort barrels off the basin pipeline as supported by long-term shipper commitments. The pipeline will have the ability to provide crude oil to local refineries and will also be connected to our Longview terminal which is connected to pipelines that have access to Gulf Coast markets.

The Permian Basin has been and will for the next few years the our most active area with respect to organic growth opportunities. As reflected on slide 13, let me start by saying that we have recently updated our production forecast at the Permian Basin by approximately 500,000 barrels per day as we expect production to reach 2.5 million barrels per day by the end of 2018 if drilling activities are not curtailed.

The resource base and in this area is well established and the drilling and completion technologies improved -- is proven. As a result, if lower prices persist, our production forecast for this time period will be moderated. But we do believe the resource is there and will be developed.

We have a couple projects in the Permian Basin that'll go into service in the fourth quarter, and we think we will begin to de-bottleneck portions of the Permian Basin. Our Monahans to Crane pipeline is expected to go into service later this month which will add 100,000 barrels of takeaway capacity out of the Delaware Basin. We also expect to place our Sunrise pipeline into service in December which when fully operational early next year, will add 200,000 barrels a day of takeaway capacity out of Midland.

Our Cactus pipeline should be in service in April of 2015, which will initially provide an incremental 200,000 barrels per day of takeaway capacity. And with the pumping equipment that is being added, takeaway capacity will be increased approximately 300,000 barrels a day in 2016.

Also in the second quarter of 2015, we expect to complete the looping of the segment of the Basin pipeline from Wink to Midland. This was a 24-inch pipeline that, coupled with other pipeline expansions currently under construction from Wink to the Delaware Basin, will add approximately 500,000 barrels of takeaway capacity from the Delaware Basin.

Lastly, we are actively pursuing the project to extend our Sunrise pipeline from Colorado City to Wichita Falls. This extension would, in essence, increase capacity to Cushing by approximately 200,000 barrels a day.

In the Eagle Ford, we remain on pace to complete the expansion of our joint venture pipeline from Gardendale to Three Rivers in April of 2015, matching the timing of the completion of the Cactus pipeline. In addition, earlier this week we announced a new gathering project in our Eagle Ford joint venture with Enterprise, along with the project to develop the segment of the JV line from Three Rivers to Corpus Christi and to include in the joint venture the new Corpus Christi dock and terminal facility under development. When completed, the JV system will include two 20-inch pipelines from Gardendale to Corpus Christi and will add both a barge loading and ship loading dock in Corpus Christi. The docks in Corpus Christi will have access to production in both the Eagle Ford and Permian Basin.

In the Mid-Continent, we are nearing completion of our facility at Lindsay, Oklahoma. The facility will allow production from the scoop play to be delivered into the basin pipeline for delivery to Cushing. We expect to start delivering crude oil into this facility in December.

In Canada, we have a number of expansion projects underway at our Fort Sask facility. These projects total approximately $600 million and include increased serve fractionation capacity, developing two new 750,000 barrel ethane caverns, developing two new 350,000 barrel propane caverns, increasing our brine handling capacity and developing a propane rail loading facility. The expansion of our fractionator and our new ethane caverns are supported by long-term commitments and remaining projects are supported by our existing activities at our Fort Sask facility.

With respect to our rail activities, our Bakersfield rail and loading terminal expects to receive its first train this month. Our [Carraba] terminal is on track to be in service in mid 2015, and we recently approved plans to enhance our St. James facility to be able to receive heavy crude oil. The St. James enhancements are expected to be completed at about the same time as our Carraba facility. And lastly with respect to rail, we have ever 1,600 new railcars on order with delivery expected to begin in mid 2015.

Before I finish, I also want to mention that last week, the Capline owners announced that we would conduct a study to evaluate alternatives for Capline given the decreasing demand for south and north movements in North America. The study is expected to be completed in early 2015, but any change in service of Capline requires the approval of all three owners. Until those studies are completed and the owners meet, we really don't have any additional information to share with respect to the alternate service of Capline. And lastly, as for maintenance capital expenditures, the third quarter totaled $56 million, and we expect maintenance capital expenditures for 2014 to range between $185 million and $205 million.

As you can see, going to strategic location and almost all the significant crude oil resource plays is providing PAA with significant fee-based organic growth opportunities. And with that, I'll turn the call over to Al.

Thanks, Gary. 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 raise 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 will account for this investment under the equity method of accounting. It will be reported in one line on our balance sheet titled Investment and Unconsolidated Entities and 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 Occi's PAPG 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 shield for PAGP.

Returning to third-quarter items, we completed several financing transactions during the quarter. First, we remained active from an equity financing perspective through 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 million.

Since first implementing our program in 2012, we have raised total proceeds of approximately $1.7 billion. On the debt side, in September we completed a $750 million offering of 3.6% 10 year senior unsecured notes.

As illustrated on slide 15, PAA ended the quarter with strong capitalization credit metrics that are favorable to our targets and $2.5 billion of committed liquidity. At September 30, 2014, PAA had a long-term debt to capitalization ratio of 48%, long-term debt to adjusted EBITDA ratio of 3.5 times. Slide 16 summarizes information regarding our short-term debt, hedged inventory and line fill at quarter end.

Moving onto PAA's guidance as summarized on slide 17, we are forecasting midpoint adjusted EBITDA of $569 million and $2.175 billion for the fourth quarter and full year of 2014 respectively. Despite third quarter performance exceeding the midpoint of our third-quarter guidance, we maintained our full-year 2014 guidance from that which we've provided -- previously provided. This is primarily the result of timing issues, including a shift in integrity and maintenance expenses from the third quarter to the fourth quarter. And the impact of lower NGL prices on our average cost of inventory which we forecast will shift margin from the fourth quarter to the first half of 2015.

In addition to the timing difference, we are forecasting slightly weaker crude oil market conditions and lower gas storage results for the fourth quarter. As represented on slide 18, based on the midpoint of our 2014 guidance for DCF and distributions to be paid throughout the year, our distribution coverage is forecast to be 111% and in line with our minimum targeted coverage ratio of 105 % to 110%. This will enable PAA to retain $149 million of excess DCF or equity capital.

In addition, our preliminary 2015 guidance incorporates expansion capital of $1.5 billion to $2 billion. The majority of this capital will be invested in our fee-based Transportation and Facility segments. And we'll have minimal contributions at 2015 results, but we will provide growth for 2016 and beyond. This level of investment, combined with the $2.05 billion of expansion capital investments in 2014, provide us with good visibility for continued multi-year distribution growth, giving the time leg associated with achieving full run rate cash flows.

For more detailed information on our 2014 guidance, as well as our preliminary 2015 guidance, please refer to the Form 8-K furnished yesterday. With that, I'll turn the call back over to Greg.

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. This 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 are 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 for questions.

(Operator Instructions)

Brian Zarahn, Barclays.

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 impacts your three business segments? And also how -- from a higher level, how do you see growth opportunities from these assets being integrated into your system?

Well, the first question is pretty easy. About, gosh, Brian, 99% of all capital that we spend on expansion is associated with either our terminal or facilities -- excuse me -- our Facility 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 are still able to maintain a high level of mutual synergies within both that asset base. We are still getting mid- to low-teens type return against even the cost of capital in today's environment that I think when we recalculate, it's about 7.2%.

We're looking at 500 basis points to 600 basis points. So, financially certainly very complementary and constructive to future growth. And as Al mentioned, what we spend in really 2014, you won't see until partially in 2015 and most of it in 2016 than the same thing for what will 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 if -- when we get our pipeline to Memphis built, what that will do for the potential to optimize Capline. 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 are really just helping to plumb and replumb activities that are going on in Cushing. I think several years ago there was a question, was Cushing going to be relevant, given everything was moving to the Gulf Coast?

And I think the conclusion almost everybody would draw today is, not only is it 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 crudes coming from different directions. And then the increased connectivity to the Gulf Coast has actually even helped that viability of Cushing long-term. Hopefully that covers most of your questions, if not, I'll take another shot at it.

I'll just add, just as real simple way to also say it is, really, if you look at it, we're expanding the integration of our footprint and predictive in the Permian, 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 to you view the long-term opportunity for process condensate and other export opportunities?

If the government will get out of our way, we'll prove that crude oil is a worldwide commodity. I think what you're seeing, 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 to markets that want light crude, and we need to continue to bring heavy crude in. And if they put in a rule in that says you can't do that, then we'll replumb the system again. So, a little clarity wouldn't hurt.

From a standpoint of question on the 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 in the Eagle Ford in South Texas to be able to source, progress, segregate, transport and export process crude oil and condensate. And we think PAA has the highest volume and most sophisticated independently owned condensate processing unit for stabilized product in the US 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.

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 requests 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 exporters. 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 is in compliance with our objective and objective interpretation of the various rules and regs under which you would be permitted to export product. I can't really give you much more comment on the export issue other than that 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 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? And how do think of this if we are in an extended period of $75 WTI?

I think we've been -- and we've been guilty, as you know, of preparing for nine out of the last two recessions. So, we've been prepared, candidly, for what's happening today and actually had talked about it extensively. And so our belief is that the duration of these depressed prices probably is -- again, it's in the shortest six months in probably as long as two years. And it 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 in on fundamental synergies, not how much money you can raise to try and buy an asset.

For PAA's perspective, we feel very well positioned. We do think that there will be a decrease in activity. If you just to the math, a $10 decrease reduces cash flow available to all E&P participants in the US of 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 majors, some of them will continue to spend through it. You still have a pretty big number.

When you think, let's say it's $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 spent on just the crude oil drilling activities in all the big basins, Bakken, Permian and Eagle Ford, was about $100 billion. So, something has to give.

The flip side of that is if you lower activity levels, it doesn't take that much decrease in activity levels to be able to bring the market back in balance. For example, to grow production 1 million barrels a day in the US net, you have to add from new wells about 2.6 million barrels a day of production because you have to offset a normal 1.6 million barrels of day of decline from the old wells.

If you decrease activity 15% on 2.6 million barrels a day, and let's just say it's linear, that's 400,000 barrel a day reduction against 1 million barrels a day increase 15% reduction activity equals the 40% reduction in production growth. That's why we think the duration is not an extended period of time.

And in fact, if we see the US acting responsibly, I think we might be actually see Saudi Arabia chip in a little bit and we actually balance the market -- we think it comes out into the $85 to $90 price range over an extended period of time. And that's more than viable to see these projects be developed over a very extended period of time. It probably means the rate of growth is not as high, but the extended period of growth is probably longer.

Thanks for the color, Greg. Really appreciate it.

Thank you.

Steve Sherowski, Goldman Sachs.

Hi. Good morning.

Greg, in your opening remarks, you noted that the difference between the high -- excuse me, 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 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?

No, what we try to do, Steve, is first off, we are 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 to transport, our fee-based activities won't have as much volume. But in many areas, we're a critical player in connecting those markets.

And so we think we probably get the base load. In some cases, for example on Basin, we have 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 a midpoint of 8.5%, if we were to add our lower end of our EBITDA guidance, we would still be somewhere within that 7% to 10% distribution growth, able to meet the distribution growth objectives using just organic growth and still meet, as Al mentioned, our minimum target coverage of 105% to 110% coverage. We think that's rather unique, quite candidly, across the MLP space because we think many others are -- weren't caring as much coverage as they came into this. We think we've got a pretty resilient range of there.

If you're asking me what oil price we would be at the higher end, lower end range, really, that's not the relevant question. It is 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 for EBITDA contribution from Supply and Logistics. If you recall back to our Analyst Day, we said our baseline level of organic growth was in the $500 million to $550 million, and we were using a $525 million midpoint. And we said that midpoint would grow as volume grows. So, we're probably right at or right around the middle to upper part of that adjusted baseline range for that.

Yet if you look back, this year we'll do probably $620 million plus or minus in 2014. And if you look in 2013 and 2012, I think the numbers were closer to $800 million to $850 million. So, clearly, if there's the kind of volatility and the kind of markets that happen when you have that type of volatility, there's some upside opportunity for us to generate incremental cash flow while still maintaining very good distribution coverage and growth levels.

I appreciate that. Thanks. And just a quick follow-up on Capline.

I'm guessing that once Diamond comes online, that's going to siphon off a lot of Capline's current volume. Is there -- I'm just curious, is there a minimum level of volume you need on Capline to run it? And what's the alternative?

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

And about 250,000 to 300,000 barrels 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. At probably, anything around 250,000 to 300,000 barrels a day, you could walk backwards faster than that oil's moving through the pipe. Okay?

And if so I think it put pressure on all the owners to look at alternatives. Two of the three owners are already willing 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 pipeline projects to bring Bakken crude oil into that Patoka area as well. When you look at the 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 will probably have some alternatives to do something constructive with Capline. To put it in perspective, I think it's probably less than 0.5% contribution to our EBITDA right now. So, anything that we can do with that is potentially huge.

Yes. No, understood.

No, thank you. That's it for me.

Thanks, Steve.

Mark Reichman, Simmons and Company.

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 answer you 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. I think today we are probably running around 22 million barrels of inventory. It's been as high as well over 40, and you've got a shelf capacity up there that's probably 80.

And so -- 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 months to 18 months you're going to see almost 700,000 barrels a day of light sweet crude getting aimed directly toward 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, as 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 of it, a water sprinkler for that goes back and forth, where it ratchets across and ratchets back. We think that you'll see volumes that 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.

I appreciate that. And with respect to the evolution of condensate supply in the Permian, is a becoming more challenging, or is the market adjusting to the condensate production?

Right now it's price adjusting in some areas. But then the forecast, the increase there, it's gone from -- just to put it in perspective, five years ago Permian Basin production as a whole was probably 850,000 barrels a day. It's double, today it's 1.7 million, and we are forecasting that is going to increase another 50% again.

The majority of that volume coming on is really light stuff and it's -- the bottom line is the issue's 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 process it, turn it into something exportable or blend it with something heavier and turn it into something that's digestible to the refiners.

Right now, a lot -- everything goes into one common stream, and the Delaware Basin is probably, where some of the lighter production is, probably not as light as the light stuff in the Eagle Ford, but lighter than the condense stream at Midland. Probably going to end up with some segregation of the lighter grade coming out of the Delaware Basin.

And it's not inconceivable that you end up with separate systems, one to carry what you and I would refer to as crude oil and others to carry condensate if the economics make sense.

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 where you'd expect it level out under these longer-term commitments?

It does include the second open season. So, the capacity's going to be -- rest of capacity market driven to the extent the arbitrage there to move to the Gulf Coast versus Cushing, it'll go to the Gulf Coast. And BridgeTex will be able to handle some of the extra capacity going to the Gulf Coast.

Yes. But Mark, remember now, we are have -- 10% of it by tariff structure has to remain at available to walkup shippers. So, if you were 90% contractually committed, you would be effectively 100% of what you could commit. Effectively, there's -- as Harry's mentioned, 80% is contracted, 10% walkup, which only leaves 10% available for the swing there.

If we did expand it, there is the ability to expand with pumps, I think to the 60,000 barrels a day. And that would -- you would be looking at contracts or at least supportable demand to be able to support that expansion.

Great. Thank you very much. I appreciate that.

Thank you, Mark.

Vikram Bagri, Citi.

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 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 get in 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. 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 you really can't run 300,000 barrels a day 365 days a year. There's standard metrics that you'll use whether you assume that you run 22 hours 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, so 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. Just wondering, does the 1.5% include the issuance of equity, or does it include your normal ATM issuances?

It includes the issuance of equity, but we're planning on using it through the ATM. When we came up with those numbers we did, 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.

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 and it will fund the balance.

Okay.

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

Okay.

So, it's -- 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's probably in the 3.6, 3.7 range.

Okay. Makes sense And then on BridgeTex, did Magellan have a rofo on this asset, so they're the operator? And was there a horse trade that went on in the background here with the Houston leg of the asset in order to take us to extinguish that rofo?

Yes. I'd say horse trade, goat trade and pig trading (laughter).

Okay. Makes sense. I just wanted to make sure I wasn't missing anything.

And then just on the rest of Occi's interest, clearly, coming ahead of the lockup period here, it is 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 Occi 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've followed 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 Occi buyback shares.

Yes.

Okay? So, I don't think they're trying to buy it all back all overnight in one deal. This is the first step, though, 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 could offer through a rofo or otherwise, and you've 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 is their buyback plans are over a multi-year period on the stock, and I think we can be a part of that.

And certainly, they've shown faith and patience in us. We tried to catalyze this first transaction using tools that we had available to us to give them something they couldn't get from someone else to get an asset that we wanted.

Okay. Yes, make 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 driving the difference between the low end and the high end there? Just so I understand the flexibility.

Yes. I think what you should take away from that is we've -- a lot of our projects here, we don't have the multi-year, multi-billion 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 calls about what should we expect for next year, and by the way, if you go back -- 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 billion or $1.6 billion and we ended up at $2 billion.

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'd start 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 just pick that 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 2016, 2017 and 2018. Because these projects are -- generally have a 12 months to 18 months gestation period where you're in the execution and then you're in the ramp-up phase. Effectively, every time we announce this, it really has minimum impact -- in a capital program, minimum impact on the next year. And then the year after that, it's the second and third year.

Okay, got. And then last question for me, on the St. James terminal and also your terminal -- 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 we -- are you moving neat bitumen yet, or is that a plan with some of the assets you have?

No, we are making modifications so we can bring in Canadian -- heavier Canadian crude. I'm not sure it will be neat bitumen, it will 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 are just making the modifications to accommodate the heavier crude stream and a little bit of segregation in the unloading facilities.

Okay, so this is not -- it can't take heavy crude yet, but it will be able to shortly.

Correct.

Got it. Okay. Thanks, guys.

Thank you.

Abhi Sinha, Wunderlich Securities.

Yes, good morning everybody. 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 made, is it 1 year, 1.5 years 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?

Early next year. Yes.

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

Sure. And then another thing I want to ask is about the Midland Cushing differential. 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?

Well, 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 the BridgeTex, we just talked about, will be fully up and running, let's say by March 1 where everything is a blind out. And then I think Permian Express 2 is supposed to come on stream late in 2015. And then as Harry mentioned, we've done a lot of it de-bottlenecking behind the scenes to be able to get crew 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 is 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, that -- everybody plans for it, Abhi. And so what happens is if you've got 200,000 barrel a day refinery that knows it is going to go into a five day turnaround, they try to create 1 million barrels of storage to be able to move their crude into it until they get a chance to pull it.

If we end up with that refinery staying in the turnaround for 10 days or 15 days, you're going to back the system up and all of a sudden, differentials are going to widen out. 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 -- we been rising, I think we started the year thinking production was going to rise at an average of 20,000 barrels per day per month. And I think we've 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. Trying to understand what rules does rail have in defining the spread between WTI and brand here. How much demand on the East Coast for light sweet, I think 600 ton, 700 ton 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. The -- it seems like 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 priced 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.

If I can steer back to the question on the WTI Midland Cushing differential. One thing that our guys pointed out to us, when we had $85 oil and a $10 differential, you had a $75 net well head price or close to the well head. And today at $78 WTI and a $2 differential, you would actually be getting a higher price at the well head today than you might have at a point in time.

Part of our enthusiasm for the Permian is that in relative terms, the price has come down on an index basis, but the well head, it hasn't come down near as much. And the fact is, you could argue that once these things are de-bottlenecked, it will actually go up slightly is the index stays at the same level.

Got it. Sure.

Thank you, that's all I have. Thank you very much, sir.

Colton Bean, TPH.

Hey, guys. It's Brad Olson.

Hey, Brad.

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 years. When I think about -- or in the next year or so.

And when I think about what each pipeline gives you in terms of market access, you are obviously pursuing 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 is as probably nobody but PAA could do all that. Because all of those, Brad, are basically extensions or -- of our existing system or connecting our existing systems in a way to improve flexibility of the producers, and that's what it's all about. 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 know is we know where the markets are and we know where the production is, and we've plumbed 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 are 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. We can -- they can maybe be able to compete from is getting from point A to point B, but we will 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.

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 a 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've got a job for you as a marketer for us. And by the way, don't forget the Diamond pipeline once you get you up from Cushing into Memphis.

Got it, that's helpful. Just trying to think about it as 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 years?

Well Brad, first I mentioned in 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 can imagine, we've got quite a few tackles coming out of Wink to give us a better access from the Delaware basin into Wink and then alternately onto Midland where you can access a lot of different markets. And then I also commented that we are 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 alluding to is that we've got a lot of other projects moving that we are thinking about extending and modifying our system as you go further west from Midland and into that area of the Delaware Basin. And that may get you a part of what fills the gap between $1.5 billion and 3 -- $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.

Great. That's great color, and I'd just to jump around a little bit, on the BridgeTex acquisition, you made some comments about a potential right of first refusal between Occi and Magellan. But I guess my question is from a little bit of a different angle. Was there a -- is there a rofo that exists between PAA and Occi as a result of Occi's ownership of PAGP that would have influenced the outcome here with the BridgeTex deal?

Amongst all of the owners in PAGP that are in the private entity that the portion that hasn't converted into the PAGP A shares, there are rofers in there, yes.

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 talked in the past about how uniquely positioned you are to handle some of the segregated condensate that has arisen from the peculiarities of our export laws. And I'm trying to understand whether that dock expansion, is that specifically focused to handle segregated condensate volumes? Or is it really a multi-product dock that really will be positioned for 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 we are already segregating various grades of condensate and crude. And we can already go into a barge dock or 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 size 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 is also coming down into that same facility. Does that make sense?

Yes. That's helpful. I guess the one --

Brad, I would just make the point that if part of the question is whether the viability of the project is underpinned by a belief about exports or not, it's not. The ability to export or optimize through exports would be just that, it would be an optimization of that. But this was going to get built regardless.

Okay, great. And there's -- 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 a obstacle to larger Suezmax type vessels coming directly into the port.

I think they're talking about raising that bridge in 2017 or 2018. Is your project designed to coincide with that development, if at all?

Well, our -- there's a -- I'm not exactly sure where our facility is located to the bridge, but I know that we've done a draft analysis so we can move vessels into and out of -- the ocean going vessels into and out of our facility.

Okay. Perfect. That's all I needed.

I think it's independent of whatever they do with the bridge.

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. 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.