Plains All American Pipeline, L.P. (PAA) Q3 2014 Earnings Report, Transcript and Summary

Ladies and gentlemen, we'd like to thank you for standing by, and welcome to the PAA and PAGP third quarter results teleconference call. [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.plainsallamerican.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 selective financial information of Plains GP Holdings, or PAGP. As a controlled 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 a condensed consolidated balance sheet. Today's call will be chaired by Greg Armstrong, Chairman and CEO. Also participating on 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 3 segments, combined with certain timing shifts between the third and the fourth quarter periods resulted in an 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's fee-based Transportation and Facilities segments, primarily due to increased production expansion projects across our asset footprint, generally, and the Permian Basin and Eagle Ford areas, in particular. Adjusted EBITDA was up 14% in PAA's 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'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 stand-alone basis was 102% and is expected to be approximately 111% for the year. PAA has now increased its distribution in 40 out 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 distribution of $19.075 per share represents a 28% increase over the initial quarterly distribution included in PAGP's October 2013 IPO prospectus and a 4% increase over the distribution paid last quarter. Before I address 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 include 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 a barrel to roughly $76 a barrel and Brent prices have 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 tight 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 reinforce 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 $2.425 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 Facilities 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 over 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 have 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 that 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 -- or, November 2015. Given our adjusted EBITDA range, this flexible approach will enable PAA to maintain coverage ratios that are directionally consistent with the minimum annual coverage guidelines that we discussed in previous calls. At the 8.5% midpoint of this range, PAGP's corresponding 2015 distribution growth will 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 at that level would represent a 55% increase over the initial quarterly distribution included in its October 2013 IPO prospectus. I want to point out that these guidance ranges do not incorporate the benefits of any pending or future acquisitions. This morning, we announced that PAA's entered into a definitive agreement 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 and 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 descriptions of the pipeline as well as its operations and a summary of the overall contract levels, and I will discuss our financing plans for the acquisition. As set forth on Slide 7, a condition to closing the transaction is the completion of an equity offering for a portion of Oxy's PAGP ownership. To accommodate meeting that condition, PAGP's board has agreed to waive the remaining term of the 15-month lockup that was put in place at the time of the IPO for the 4 largest owners of the GP, which includes Oxy. The remaining 3 large owners, Kayne Anderson, The Energy Minerals Group and PAA management, have all agreed to waive their rights to participate in the Oxy 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 on 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 Oxy and PAGP as it facilitates Oxy's sale of the portion of its investment in PAGP and reduces the market overhang and also provides additional liquidity and incremental tax yield for PAGP's shareholders. The BridgeTex Pipeline effectively 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 filings does not include the benefit of this pending transaction. We anticipate PAA's share of annualized EBITDA from BridgeTex LLC will range between $100 million and $105 million. And at that 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 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 declining crude oil prices with incremental debt or issue an equity at depressed price levels. Alternatively, they can elect to decrease the pace of drilling and complete -- completion activity or they can bring in third-party financial capital, but the latter of that really -- generally takes time to negotiate and to 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 6 months and as long as 18 to 24 months. Longer term, we remain optimistic about the outlook for continued U.S. and Canadian volume growth and the positive ramifications for such growth for 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 lengthy introduction, I'll turn the call over to Harry.

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 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 in 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 1 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 operation 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 a $1.36 or $0.22 above the midpoint of our guidance. Over-performance was primarily due to more favorable crude oil differentials, particularly the Midland Cushing differential and differentials in our Canadian -- in Canadian grades of crude oil. Let me now move to Slide 9 and review 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 a 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 Facilities 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 the third quarter is primarily due to our Bakersfield rail terminal, which was place in service in November. For our Supply and 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 pipeline 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 we'll acquire will be -- I'm sorry, well, 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 to 10 years in length with options to extend. I'll also note that contractually committed volumes account for approximately 80% of the system's current capacity. About 10%, or half of the remaining capacity, is required to be reserved for walk-up 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 and expect to be very active in several resource plays and demand centers of North America. For 2014, we made an upward adjustment of $100 million to an estimated expansion capital plan which results in a revised target of approximately $2.05 billion. This increase is not attributable to any single -- similar -- 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 [ph] 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 a related contract restoring terminaling services at our Cushing terminal. The project is expected to be completed in late 2015 and Valero holds an option until January 2016 to purchase a 50% nonoperating interest in the pipeline. Last night, we announced a new pipeline -- a project to build a 16-inch pipeline from Duncan, Oklahoma to Longview, Texas. The pipeline has a potential capacity of up to 150,000 barrels per day and will source barrels off the Basin Pipeline as supported by long-term shipper commitments. The pipeline will have the ability to provide crude oil at 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, be 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 for 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 in this area is well established and the drilling and completion technology is improvement -- is proven. As a result, if lower prices persist, our production forecast for this time period will be moderated, but we do believe that resource is there and will be developed. We have a couple of projects in the Permian Basin that will 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 a day of takeaway capacity out of 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 2015, which will initially provide an incremental 200,000 barrels per day of takeaway capacity. And with pumping equipment that is being added, takeaway capacity will be increased to approximately 300,000 barrels a day in 2016. Also, in the second quarter of 2015, we expect to complete the looping of the second of the Basin Pipeline from Wink to Midland. This is 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're actively pursuing the project to extend our Sunrise Pipeline from Colorado City to Wichita Falls. This extension would, in essence, increase capacity of Cushing by approximately 200,000 barrels a day. In the Eagle Ford, we will remain on pace to complete the expansion of our joint venture pipeline from Gardendale to Three Rivers in April 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 a project to develop a segment of 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 2 20-inch pipelines from Gardendale to Corpus Christi and will have both a barge-loading and ship-loading dock in Corpus Christi. The docks in Corpus Christi will have access to production both at Eagle Ford and Permian Basin. In the Mid-Continent, we're 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 increasing our fractionation capacity, developing 2 new 750,000-barrel ethane caverns, developing 2 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 our remaining projects are supported by existing activities at our Fort Sask facility. With respect to our rail activities. Our Bakersfield rail unloading terminal expects to receive its first train this month. Our Kerrobert 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 about the same time as our Kerrobert facility. And lastly, with respect to rail, we have over 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 have conducted 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 3 owners. Until the study is completed and the owners meet, we really don't have any additional information to share with respect to the ultimate 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, Plains has a strategic location in almost all the significant crude oil resource plays is providing PAA with significant fee-based organic growth opportunity. And with that, I'll turn the call over to Al.

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 raise significant amounts of equity through the use of our continuous equity operating 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 1 line on our balance sheet titled Investment in Unconsolidated Entities and in 1 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 the 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 were 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've 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%, a long-term debt-to-adjusted EBITDA ratio of 3.5x. Slide 16 summarizes information regarding our short-term debt, hedged inventory and linefill 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 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 one of $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 Facilities segments and will have minimal contribution to 2015 results but 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, multiyear distribution growth, given 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 prospective midpoint 2015 distribution growth targets of 8.5% and 21%, this despite being in the midst of 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 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] Our first question will come from the line of Brian Zarahn of Barclays.

Greg, over the past few months and certainly the past week, you made a lot of project announcements, from Diamond to the Oklahoma-Texas, the 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 3 business segments? And also, for -- from a high level, how do you see growth opportunities from these assets being integrated into your system?

Well, the first question is kind of pretty easy. About, gosh, Brian, 99% of all capital that we spend on expansion is associated with either our terminal or facilities -- or excuse me, our Facilities and our Transportation segments. So these are all basically underpinned by fee-based arrangements. And from a standpoint of -- the returns, by the way, are -- 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 2 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 of return against -- even the 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 then most of it in '16, and the same thing for what we'll be spending next year. As far as -- there are certainly other opportunities for these investments to beget incremental opportunities. We've certainly looked at what happens if -- when we get the -- 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 in 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 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 spiderweb 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 going to help that, the viability of Cushing long term. So hopefully, that covers most of your questions. If not, I'll take another shot at it.

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

Along those lines, you're certainly making a greater push towards the water. Maybe you can 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 processed condensate and other export opportunities?

Well, if the government will get out of our 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 well, it's the fact that 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 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 the 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 in Eagle Ford in South Texas to be able to source, process, segregate, transport and export, processed crude oil and condensate, and we think PAA has the highest volume, most sophisticated, independently-owned condensate processing unit for stabilized products 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 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 say that everything we're doing is in compliance with our objective, and an objective interpretation of the various rules and regs under which you would be permitted to export products. So 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 next call, I think I'll have a short, brief answer for you.

Okay, I appreciate that. And last one for me is, obviously, given your announcements, no impact on your CapEx spending due to lower crude environment. But you maybe can 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 contracts come up for renewal? How do you sort of think about this if we're in an extended period of $75 WTI?

Well, I think we've been -- and we've been guilty, as you know, of preparing for 9 out of the last 2 recessions. So we've been prepared candidly for what's happening today and actually, I talked about it extensively. And so our belief is that the duration of these depressed prices probably is -- again, it's in the short as 6 months and probably as long as 2 years. And it kind of helps to 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. 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. 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, that'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 of the big basins, Bakken, Permian, 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. So for example, to grow production, 1 million barrels a day in the U.S. 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 a day of decline from the old well. So if you decrease activity, 15%, on 2.6 million barrels a day, let's just say, it's linear, that's 400,000 barrel a day reduction against 1 million barrel a day increase, a 15% reduction activity equals to a 40% reduction in production growth. So that's why we think that the duration is not an extended period of time and in fact, if we see the U.S. acting responsibly, I think we might actually see Saudi Arabia chip in a little bit and we actually balance the market where 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 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.

Our next question will come from the line of Steve Sherowski with Goldman Sachs.

Greg, in your opening remarks, you noted that the difference between the high -- the low and high range of the 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 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?

No. What we're trying 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 to transport our fee-based activities won't have as much volume. But in many areas, I mean, 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 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 objectives, using just organic growth and still meet, as Al mentioned, our kind of minimum target coverage of 1.05% to 1.10% coverage. So we think that's rather unique quite candidly across the MLP space because we think many others are not -- weren't carrying as much coverage as they came into this. So we think we've got a pretty resilient range there. If you're asking me what oil price would we be at the higher end -- lower end of the range, and really, that's not the relevant 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 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 the $525 million kind of 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. And just a quick follow up on Capline. I'm guessing 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 I guess, what's the alternative?

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

At 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. But at a -- 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 so I think it puts pressure on all the owners to look at alternatives. 2 of the 3 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 pipelines. There are other projects to bring Bakken crude oil into that Patoka area as well. So it's a 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 with the -- 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 1/2 of 1% contribution to our EBITDA right now. So anything that we can do with that is potentially huge.

Our next question will come from the line of Mr. Mark Reichman of Simmons & Company. Mark L. Reichman - Simmons & Company International, Research Division: 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 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. I think today, we're probably running around 22 million barrels of inventory. It's been as high as well over 40 million. And we'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 to 18 months, you're going to see almost 700,000 barrels a day of light, sweet crude go -- 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 into 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, the water sprinkler that kind of goes back and forth where it kind of just ratchets across and ratchets back. We think that you'll see volumes to kind of yoyo up and down in Cushing for some time to come. It's going to be the pressure relief valve to balance the system. Mark L. Reichman - Simmons & Company International, Research Division: 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 -- I mean, the increase there, it's gone from -- just to put in perspective, 5 years ago, Permian Basin production as a whole was probably 850,000 barrels a day. It's doubled. Today, it's 1.7 million. And we're forecasting that it's 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 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 process and turning it to something exportable or blend it with something heavier and turn it to something that's digestible to the refiners.

And so 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 the -- 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 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. Mark L. Reichman - Simmons & Company International, Research Division: 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 would move to the Gulf Coast versus Cushing, it will go to the Gulf Coast, and BridgeTex will be able to handle some of the extra capacity going into the Gulf Coast.

Yes, Mark, remember now, we have -- 10% of it, but tariff structure has to remain available to walk-up shippers. So if you were 90% contractually committed, you would effectively be 100% of what you could commit. So effectively, there is -- Harry has mentioned 80% is contracted, 10% is walk-up, which is -- only at least 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.

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

This is actually Faisel from Citigroup and Vikram's with me, too. Just wanted to just understand the guidance on the transaction by 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 then 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're in a range of I think about $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% top utilization of the pipe. And the reason for that is, is you really can't run 300,000 barrels a day, 365 days a year. So there's the standard metrics that you'll use, when you assume that you're running 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 that -- so obviously, you're debt-financing initially with your loan facility or your bank facility and then you talked about how you plan to finance this with equity over time. So just -- I'm 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 that for the ATM. So 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. So we'll just either maintain or step up the CLP program or the aftermarket 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 prefunded so much of our 2015 capital program. All we have to do is let the CLP program run on autopilot, and it'll fund the balance.

We also burdened 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're talking accretion.

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

Okay, makes sense. And on BridgeTex, didn't Magellan have a ROFO on this asset just so the -- they're the operator? Then 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 ROFO?

Yes. I'd say horse trading, goat trading, and pig trading.

Okay, makes sense. Just like to make sure I wasn't missing anything. And then just on the rest of Oxy's interest, I think, clearly, coming ahead of the lock-up period here, it's a little bit of surprise to the market. What's the indication on the rest of the -- on the rest of their position? Is that also 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 the 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 3 quarters ago that their holdings in PAGP equated on an after-tax basis to a set number of Oxy buyback shares. Okay, so I don't think they're trying to buy it back all overnight. And this is first step though of what I think would be a prudent liquidation. What this transaction gives them is, as you mentioned, the acceleration. And that's -- 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 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 and 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 us. We tried to catalyze this first transaction using tools that we had available to us to get them something they couldn't get from somebody else to get an asset that we wanted.

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

Yes, I think what you should take away from that is we've -- a lot of our projects here, 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 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 6 months ago that we thought we would at least have roughly $1.5 billion plus or minus. The takeaway 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 that 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 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 are -- generally have a 12-, 18-month gestation period where you're in the execution and you're in the ramp-up phase. So effectively, every time we announce this, it really has a 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 you. 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 sort of neat bitumen yet? Or is that a plan with some of the assets you have?

No that's -- we're making modifications so we can bring in Canadian -- heavier Canadian crude. It -- not sure it will be neat bitumen, it might be under-blended crude that would probably work better into the terminal than neat. But the facility at St. James can unload 2-unit trains a day so 130,000, 140,000 barrels a day. We're just making a modification 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 will be able to shortly?

Correct.

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

So just to follow up on the previous question on the BridgeTex Pipeline. When you said your model is based on 90% of utilization, what is the ramp-up period you have made, is it 1.5 years or it's less than that? Right now, I think it's 50% utilize or lower than that?

No, there's 2 issues there. One, volumetrically, I don't -- some of the contracts here you don't actually start until early next year.

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 volumetric ramp-up. There's some of that, but it's more value ramp-up. So probably by the time we get to it think March 1 of 2015, we should be at the full, physical and contractual run rate capacity.

Sure. And 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? I mean, 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. And I think Permian Express, too, is close 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 that 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 the extended period of time. But what happens is there's 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 any time you have a refinery, let's say that -- everybody plans for it, Abhi. And so what happens is if you've got a 200,000 barrel-a-day refinery that knows it's going to go into a 5-day turnaround, they try to create a 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 or 15 days, you're going to back the system up and all of the sudden 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 4- or 5-month basis. So we don't think the issue of the Midland Cushing differential adding volatility is going 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.

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

It's almost like those 2 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 price, Brent-based crudes into the East Coast. But we'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 guidance pointed to us, when we had $85 oil and a $10 differential, you had a $75 net wellhead price or close to the wellhead. And today, it's $78 WTI and a $2 dollar differential, you would actually -- you will be getting a higher price at the wellhead today than you might have at one point in time. So part of our enthusiasm for the Permian is that -- in relative terms, the price has come down on an index basis but at the wellhead, it's not -- hasn't come down near as much. In fact there, as you can argue, that once these things are debottlenecked, it'll actually go up slightly if the index stays at the same level.

And our next question will come from the line of Colton Bean of TPH. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: It's Brad Olsen. 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, the 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 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. 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 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'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 are in the business that are trying to get into the business. We can -- they can may be able to compete with us from 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 3 years from now. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Got it. And so when I think about BridgeTex 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 playing system in the Permian could access any number of those market outlets?

I've got a job here as a marketer for us.

And by the way, don't forget the Diamond pipeline wants to get you up from Cushing to Memphis. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Got it. Yes. And 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 to 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?

Well, Brad, first, I mentioned, in part of my comments in the script that we are expanding the segment of basin from Link 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 tentacles coming out of Link to give us a better access from the Delaware Basin into Link, and then ultimately, on to Midland where we can access a lot of 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 as 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 of the Delaware Basin. And that may get you a part of what fills the gap between $1.5 billion and $2 billion on our cap budget for next year is -- some of those, again, we don't usually announce those until we have a crystallized project as opposed to a theoretical project. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: 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 -- is there ROFR that exists between PAA and Oxy as a result of Oxy's ownership of PAGP that would've influenced the outcome here with the BridgeTex deal?

Well, there -- amongst all the owners in PAGP that are in a private entity that -- the portion that hasn't converted into the PAGP A shares, there are ROFRs in there, yes. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Got it. And then just one final one. As far as the expansion in the Eagle Ford or -- 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 multiproduct 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 we're already segregating various grades of condensate and crude. And we can already go into a barge dock, our existing barge dock into the 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 3 or 4 grades of Eagle Ford condensate there. Plus you've got Cactus crude that's also coming down into that same facility. Does that make sense? Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Yes. That's helpful. I guess the one...

Brad, I would just make -- I'd just make that 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. I mean, 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. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, great. And there's a -- 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?

Well, our -- there's a -- where our -- 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 could move vessels into and out of -- the ocean-going vessels into and out of our facility.

Okay, perfect. Yes, that's all I needed.

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

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 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.