Plains All American Pipeline, L.P. (PAA) Q4 2014 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by, and welcome to the PAA and PAGP Fourth Quarter and Full Year Results Conference Call. [Operator Instructions] And as a reminder, this conference is being recorded. I’d now like to turn the conference over to Director of Investor Relations, Ryan Smith. Please go ahead, sir.

Thanks, Gale. Good morning, and welcome to Plains All American Pipeline’s fourth quarter and full year 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 risk 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 question-and-answer session. With that, I’ll turn the call over to Greg.

Thanks, Ryan. Good morning, and welcome to all. Anticipating that there is more interest in our comments regarding the future than this past quarter’s performance, I intend to keep my opening remarks on 2014 brief and focus mostly on 2015. PAA reported fourth quarter and full year 2014 result near the upper end of the guidance range furnished on November 5, 2014. Adjusted EBITDA for the fourth quarter and full year 2014 was $594 million and $2.2 billion respectively. Slide three contains comparisons for a variety of metrics to our performance in the same quarter of last year versus our fourth quarter 2014 guidance. And slide four highlights that this is the 52nd consecutive quarter that PAA has delivered results in line with or above guidance. Given the events occurring in the crude oil market after our last earnings call, we are pleased with how PAA finished out the final quarter of 2014. As noted on slide five, we are also pleased to report that PAA accomplished each of its four goals for 2014 and PAGP exceeded its targeted distribution growth for the year as well. For this quarter, PAA declared a distribution of $0.675 per common unit, or $2.70 per unit on an annualized basis, which will be paid next week. This distribution represents an approximate 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 111% and it was also 111% for the year. PAA has now increased its distribution in 41 out of the past 43 quarters, and consecutively, in each of the last 22 quarters. Additionally, PAGP’s quarterly distribution of $0.203 per share represents a 27% increase over the non-prorated quarterly distribution paid for the same quarter of last year and a 6% increase over the distribution paid just last quarter. Turning to 2015, I want to provide some color on PAA’s 2015 guidance that we furnished yesterday and the context for the changes from the preliminary guidance we furnished on November 5, 2014. In our third quarter earnings call in early November, we provided preliminary guidance range for 2015 adjusted EBITDA of $2.35 billion to $2.5 billion with a midpoint of $2.43 billion. Prior to the call, we announced an acquisition that, at effective full utilization, we estimated would raise our run rate adjusted EBITDA by approximately $100 million per year, with a ramp up in 2015 that would result in incremental adjusted EBITDA of around $90 million and bring the midpoint of our acquisition adjusted guidance to just over $2.5 billion. As illustrated by slide six, our business model and asset base have been purposely structured to generate solid results in almost any commodity price environment and have proven their resiliency over the last 15 years in a variety of markets. While we have minimal direct exposure to commodity prices, our performance is influenced by certain differentials and overall production levels that, in turn, are impacted by major price movements and their effects on producers’ drilling activities. For example, capacity limitations on pipelines or changes in location differentials can impact the volume of Bakken production that is required to be moved or preferentially elects to move by rail, which in turn, affects our facilities segment activities. A material reduction in such volumes at the margin could impact our rail volumes and/or compress margins due to competition. Since our November earnings call, crude oil and natural gas liquids prices have decreased approximately 40% and basis differentials in a number of locations have compressed meaningfully. Natural gas prices have declined by 30% or more. These combined declines in commodity prices have collectively reduce the level of cash flow producers have available to reinvest by a meaningful amount. In response, most producers have significantly reduced their capital budgets for 2015 relative to 2014 actual levels, as well relative to their initial 2015 plans. The magnitude of such budget reduction varies among producers, but in general, it appears the average reduction is roughly in the 30% to 40% range, with respect to producers that impact North American crude oil production the most. Our preliminary 2015 guidance anticipated some further weakening in crude oil prices from roughly $80 per barrel level, with the lower end of our guidance range effectively allowing for crude oil prices to fall to approximately $65 a barrel for a relatively short period of time. The prominent WTI price so far has averaged $48 per barrel, which is around 25% below the $65 per barrel level. As I mentioned in our November earnings call, we are not immune not the adverse impacts of a major step change in commodity prices that is accompanied by a similar change in producers’ activity levels, especially during the transition. Accordingly, we have reduced the midpoint of our acquisition adjusted EBITDA guidance for 2015 by 6.5% from just over $2.5 billion to $2.35 billion. This updated midpoint is based on our updated guidance range of $2.25 billion to $2.45 billion. We have also revised our distribution growth target range for 2015. We are currently targeting distribution growth for PAA of 7% for 2015. PAGP’s correlative distribution increase would be approximately 21%. The decision to adjust our distribution growth was not without significant thought and deliberation. In establishing this new target, we considered a number of factors, including our revised guidance range for adjusted EBITDA and the developments and related uncertainties that triggered those revisions, our previous guidance for distribution growth and our sense of current market expectations, our desire to be a top quartile performer within the large cap MLP universe on a sustainable basis, the concept of positive distribution coverage serving as a rainy day reserve, the upside and downside implications of a variety of alternative courses of action regarding distribution growth in an uncertain environment, the flexibility to adjust during the year should market conditions meaningfully change, and finally, the incontrovertible fact that stuff happens. We also assessed our conviction that the current low oil prices are not fundamentally sustainable and therefore, are self correcting and we contrasted that against the John Maynard Keynes axiom that the market can stay irrational longer than you can stay solvent. We weighed these and many other factors and believe we landed on a situation-appropriate conclusion. We retained the option to adjust upwards or downwards if subsequent performance demonstrates that this was a sub-optimal position. Given recent industry developments, we believe that achieving our revised distribution objectives will reflect positively on the resiliency of PAA’s business model, the diversity of its asset base and the strength of its project portfolio. Importantly, we believe PAA continues to represent an attractive risk to reward proposition that compares very favorably to our large cap MLP peer group. Based on the midpoint of our guidance, our projected distribution coverage is essentially one-to-one for 2015, give or take a few million on the $2.3 billion adjusted EBITDA scenario. As we discussed in previous calls, we generally target minimum distribution coverage of approximately 1.05 to 1.1, based on the concept that relative to baseline performance in a normal market, that level of coverage should provide a cushion against any rainy day events. We believe the recent industry downturn falls into the category of a rainy day event. Importantly, as we looked forward to the next few years beyond 2015, we believe the expected cash flow growth associate with our ongoing expansion capital program will further strengthen PAA’s industry-leading crude oil franchise and enable PAA to continue to deliver attractive distribution growth, while also restoring distribution coverage levels to levels in line with our targeted minimum distribution coverage levels. Slide seven compares PAA’s historical performance with respect to distribution coverage with the crude oil price cycles going over the last 11 years, as well as a recap of our view regarding forward distribution growth in coverage. Moving on to our CapEx activities for 2015, we believe the investments we have planed for this period will position PAA for solid performance for the next several years. To set the stage for my comments on our 2015 capital program, as well as our outlook towards acquisitions in this environment, I want to share our views on four key industry considerations. First, the underlying supply and demand imbalance is self-correcting for a variety of reason and for a variety of reasons, we think we will see a recovery in prices and an associated pick up in drilling activity within the next 12 months to 24 months, give or take a few months. An illustration of the potential impacts on production volumes based on recovery periods starting at each end of this range is provided on slide eight. Second, the large North American resource base remains intact and will be developed. At reduced activity levels, the overall production curve will shift to the right, peak production levels will be reduced and the time period required to produce this resource base will be extended. This concept is illustrated on slide nine. Third, as a result of recent developments, barriers to entry for a number of midstream activities have increased. In a nutshell, capital is less widely available and it is certainly more expensive. Fourth, operating and commercial expertise and synergies will be more relevant and fundamentally and financially sound business builders should benefit in the resulting environment, at least for a while. In summary, although challenging in the near-term, we believe this environment is a healthy one for PAA over the long-term. We have a strong balance sheet and liquidity position and an integrated business model and asset base. It is worth noting that we are building pipeline internal assets at strategic locations that interconnect with our existing asset base and that have very long useful lives; in many cases, as much as 70 years or more. Accordingly, as long as our ultimate assessment of the resource base and the commodity price environment required to develop these resources is directionally on point, we can afford to be wider than mark regarding production volumes for the first 12 months, 18 months or even 24 months without materially impacting PAA’s long-term business or its overall economic returns on such capital investments. As a result, we are well positioned to continue developing our industry platform, develop our business platform via organic growth projects and also to pursue complementary acquisitions. With that in mind, we have targeted an expansion capital program for 2015 of $1.85 billion. Consistent with prior programs, the 2015 capital program is diverse with the single largest project representing less than 10% of the total program; thus reducing the impact of a delay, cost overrun or other issue on any given project. Additionally, we continue to target returns in the low double-digits to mid-teens for the vast majority of the projects, reflecting the benefit of adding on to existing assets in the various resource basins, as well as interconnecting with our existing assets in other regions. Aside from the carry-over projects to be finished in the first part of 2015, the bulk of the incremental financial contribution will be layered into years beyond 2015 and thus set the stage for future growth and adjusted EBITDA. We’re also continuing to develop and advance additional projects that could be introduced into the program throughout the coming year. Finally, we continue to remain very active with respect to acquisitions and believe our synergies, commercial expertise, and financial flexibility should prove to be more advantageous in this environment than we’ve experienced over the last two or three years. With that, I’ll turn the call over to Harry.

Thanks, Greg. During my portion of the call, I’ll review our fourth quarter operating results compared to the midpoint of our guidance, the operational assumptions used to generate our 2015 guidance and provide an update to our 2015 capital program. As shown on slide 10, adjusted segment profit for the transportation segment was $270 million, which was approximately $9 million above the midpoint of our guidance, and volumes of 4.3 million barrels per day were in line with our guidance. Adjusted segment profit per barrel was $0.68 or $0.02 above the midpoint of our guidance. The acquisition of a 50% interest in the BridgeTex pipeline in mid-November was the primary contributor to our financial over performance in the quarter. Adjusted segment profit for the facilities segment was $151 million, which was approximately $4 million above the midpoint of our guidance. Volumes of 122 million barrels were in line with the midpoint of our guidance, while adjusted segment profit per barrel was slightly above guidance at $0.41 per barrel. Although volumes were in line with guidance, adjusted segment profit was higher than anticipated primarily due to higher throughput on our Cushing terminal and lower than expected operating expenses, partially offset by a slight delay in the start up of our Bakersfiled crude oil rail terminal. Adjusted segment profit for the supply and logistics segment was $173 million or approximately $12 million above the midpoint of our guidance. Volumes of 1.3 million barrels per day were in line with the midpoint of our guidance. Adjusted segment profit per barrel was $1.48 or $0.09 above the midpoint of our guidance. The higher than anticipated adjusted segment profit was primarily due to crude oil differentials that were more favorable than forecasted partially offset by lower than forecasted profits in our NGL activities, which was largely a shift in timing into the first quarter of 2015. Let me now move to Slide 11 and review the operational assumptions used to generate our full year 2015 guidance. For transportation segment, we expect 2015 volumes to average over 4.9 million barrels per day, an increase of approximately 831,000 barrels per day or 20% of our full year 2014 volumes. We expect adjusted segment profit per barrel of $0.68 or $0.04 higher per barrels than last year. The volume increase is primarily due to forecasted increases of approximately 200,000 barrels per day on our Permian Basin-area pipelines, 137,000 barrels per day on our Sunrise pipeline, 90,000 barrels per day on our Cactus pipeline, 38,000 barrels per day on our Line 63/2000 system, 96,000 barrels per day attributable to our interest in the BridgeTex pipeline, and 83,000 barrels per day attributable to our interest in the Eagle Ford joint venture pipeline. For our facilities segment, we expect an average capacity of 128 million barrels of oil equivalent per month. Adjusted segment profit per barrel is expected to be $0.38, which is an approximate 7% decrease compared to 2014. The volume increase is attributable to a combination of minor increases in storage capacity at our Cushing, St. James, and Yorktown terminals, coupled with an increase in rail volumes, primarily attributable to our new Bakersfield facility, the expansion in our Niobrara facility, and our new Kerrobert terminal, which is expected to be in service in mid-year 2015. The decrease in segment profit per barrel is due to forecasted decreases in gas processing margins at our Gulf Coast facilities and in rail fees related to the movement of certain volumes of Bakken crude oil. For our supply and logistics segment, we expect volumes to average 1.19 million barrels per day or approximately 33,000 barrels per day higher than volumes realized in 2014. Adjusted segment profit per barrel is expected to $1.27 or $0.27 per barrel lower than last year. The volume increase in this segment is primarily due to anticipated increases in the lease gathering activities. Segment profit per barrel is estimated to be 18% lower compared to actual 2014 results, as we expect to see compressed margins in the current low price environment, partially offset by increased margins related to crude to contango storage opportunities. Let's now move on to our capital program. During 2014, we invested slightly over $2 billion in organic growth projects, which is in line with the guidance range provided last quarter. As reflected on slide 12, our expansion capital expenditures for 2015 are expected to total approximately $1.85 billion and it is typical with our capital programs. This is composed of a number of small to medium sized projects spread across most of the liquid’s rich resource plays. Consistent with past practice, we’ll adjust our expected capital investment level quarterly based on our progress on approved projects and potential approval of additional projects within our project portfolio. The expected in-service timing of the larger projects in our capital program is included on slide 13 and I'll take a few minutes to provide a status update for a few of the larger investments. Let me start with an update on our Cactus Pipeline. We expect the line to be in partial service in April 2015. Initial operations will be in the 50,000 to 100,000 barrels per day range, ramping up to a 150,000 barrels per day by August, corresponding with the completion of an expansion of our Eagle Ford join venture pipeline. The line will be capable of moving approximately 250,000 barrels per day and will be expanded to approximately 330,000 barrels per day by the first quarter of 2016, once our quarter point pumps are installed. In the Permian basin, we expect to invest approximately $365 million in 2015. We placed our Monahans to Crane Pipeline in service in January this year. That line created about a 100,000 barrels per day of additional takeaway capacity out of Delaware Basin. In March, we’ll begin construction of our 24-inch loop of the Basin Pipeline system from Wink to McKamey, which will ultimately add approximately 300,000 barrels per day of takeaway capacity from the Delaware Basin. The line is expected to be in service in August of this year with full utilization expected in 2016. In addition, we have four projects in the Delaware Basin, a 16-inch pipeline from the Brea Dry Area to Wink, a 12-inch pipeline extension to our Blacktip pipeline to connect with Chevron’s Cimarex Triple Crown station in Culberson County, our 16-inch Stateline pipeline extending towards [indiscernible] are in New Mexico and our 20-inch pipeline loop from Blacktip to Wink. In the Eagle Ford we expect invest $120 million in 2015. We remain on pace to complete the expansion of our joint venture pipeline from Gardendale to Three Rivers in April 2015 coordinating with the expected partial in-service date of the Cactus pipeline. The joint venture is also looping the segment from Three Rivers to Corpus Christi, in conjunction with the gathering system, the joint venture is building from the Karnes and Live Oak County production areas to the Three Rivers terminal. The joint venture is also developing a marine terminal in Corpus Christi and this facility is expected to be in service in late 2016 and will have the ability to service ocean-going vessels. In the Rockies, we expected to invest approximately $50 million in 2015 to build a pipeline from Cheyenne, Wyoming to our Colorado railroading terminal facilitating the movement in Niobrara crude on rail. In Canada, we have approximately $520 million of expansion projects at our Fort Sask facility, including two new 350,000 barrels spec product caverns, two new ethane caverns with the combined capacity of 1.6 million barrels, approximately 5 million barrels of additional brine capacity, a truck rack and a rail loading facility. These projects are all progressing on schedule. We also have a couple of rail projects in progress. The rail loading facility in Kerrobert and the expansion of our unloading facility at St. James are the two most significant projects. Our Kerrobert terminal is expected to be in service in mid-2015 and the St. James project which will enhance our ability to receive heavy crude oil is expected to be in service by the third quarter of 2015. Shifting to maintenance capital, expenditures for the fourth quarter totaled $73 million resulting in total 2014 expenditures of $224 million, about $19 million higher than top of our guidance, as we were able to make more progress on our maintenance project than anticipated. For 2015, we expect our maintenance capital to range between $205 million and $225 million. Before, I turn the over to Al. I want to mention a couple of other matters. First, during the fourth quarter, we received conformation from the BIS that condensate processed at our Gardendale facility meets definition of a product that can be exported. Today, we have not exported any process condensate, however we believe we are well positioned to segregate the process condensate and export the product when market conditions warrant. Second, we’ve had a couple of lawsuits that have been received some publicity. The first relates to our Diamond pipeline. The suite challenges our status as a common carrier. We believe we are a common carrier and we’ll defend our position but I’ve been advised not to discuss about it on the call. Also in California, a group of plaintiffs' filed suite seeking to have the court void the Air District’s approval of our oily water sewer system permit at our Bakersfield rail terminal. Again, we believe we have valid permits and will defend our position but we’ve been advised not to discuss the matter on the call. So with that, I’ll turn the call over to Al.

Thanks, Harry. During my portion of the call, I will provide comments on a few year-end accounting items and a general overview of our financing activities, capitalization and liquidity as well as our guidance for the first quarter and full year of 2015. As a result of significant price decreases during the fourth quarter, we had mark-to-market derivative gains, net of operating inventory valuation adjustments of $166 million which are associated with operating activities in 2015 and beyond. Additionally, we recorded a non-cash impairment totaling $85 million on our long-term inventory. As a reminder, our long-term inventory is comprised of minimum inventory in third-party assets and other working inventory that is needed for our commercial operations and is required for the foreseeable future. From a business perspective, we consider long-term inventory to be similar to linefill and do not hedge it, as doing so will create price risk not eliminate it. However under GAAP accounting rules, our long-term inventory is subject to impairment testing which resulted in the non-cash impairment. Linefill is not subject to this type of impairment testing. As is our standard practice, both of these non-cash items were treated as selected items impacting comparability and therefore are not included in our adjusted results. Moving on to finance related items, in the fourth quarter, PAA issued approximately 3.6 million units raising $197 million in equity capital through our continuous equity offering program. As illustrated on slide 14, for the full year of 2014, we issued 15.4 million units through this program raising $866 million in equity capital. Since first implementing the program in 2012, we have raised approximately $1.9 billion. In the debt capital markets, PAA has raised $1.15 billion through the sale of $500 million of five year senior notes and $650 million of 30-year senior notes with interest rates of 2.6% and 4.9% respectively. As illustrated on slide 15, PAA ended 2014 with strong capitalization, credit metric and liquidity. In January, we entered into a new $1 billion, 364 day credit facility. This credit facility increased our committed liquidity from approximately $2.6 billion to $3.6 billion. At December 31, 2014 PAA had a long-term debt to capitalization ratio of 52% and a long-term debt to adjusted EBITDA ratio of 3.7 times. Slide 16 summarizes information regarding our short-term debt, hedged inventory and linefill at quarter-end. Moving on to PAA’s guidance for the first quarter and full year of 2015 as summarized on slide 17, we are forecasting midpoint adjusted EBTIDA for the first quarter of $580 million and $2.35 billion for the full year. This guidance assumes that 2015, oil prices are plus or minus $50 per barrel and that producer drilling activities are materially reduce relative to 2014. As Greg noted earlier, while we have minimal direct commodity exposure, we will be impacted by the anticipated reduction in oil production growth and are also impacted by tighter differentials. Accordingly, although we could benefit from potential volatility during the coming year, our 2015 guidance assumes the near baseline type of environment for supply and logistics with compressed margins in its low price environment, partially offset by some contango storage opportunities. As reflected on slide 18, our guidance for 2015 forecast strong growth in our transportation segment relative to 2014. This 27% growth is primarily the result of our organic capital investments in the BridgeTex acquisition. The facilities segment is forecast to be essentially inline with 2014. Collectively, adjusted EBITDA from the fee-based transportation and facilities segments are forecast to increase $253 million or 16% from 2014 and are expected to represent 77% of our total adjusted EBITDA. We expect this fee based percentage to migrate to 80% or more over the next several years relative to our baseline activity. As Greg mentioned, our 2015 organic capital investment program is $1.85 billion. The majority of this capital will be invested in our fee-based transportation facility segment and will have minimal contribution to 2015 results but will provide growth for 2016 and beyond. This level of investment combined with the $3.1 billion of capital investments we made in 2014 provide us with good visibility for continued multi-year growth given the time lag associated with achieving full run rate cash flows. I would also like to point out some additional considerations regarding our 2015 guidance. First our NGL business within our Supply and Logistics segment has inherent seasonality. NGL volumes and margins are typically the highest in the first and fourth quarters of each year due to weather driven demand in the winter months. Slide 19 directionally illustrates our forecasted 2015 quarterly supply and logistics adjusted EBITDA as illustrated in the green portions of the bars. The seasonal impacts will likely result in higher distribution coverage in the first and fourth quarters with lower coverage during the second and third quarters. Secondly, as illustrated on slide 19 we expect our fee based transportation facility segment to generate favorable aggregated quarterly comparisons in 2015 relative to the corresponding quarters of 2014. However in our Supply and Logistics segments, our guidance assumption for near baseline market condition throughout 2015 results in negative quarter-over-quarter Supply and Logistics segment comparisons for the second and third quarters of 2015 relative to corresponding quarters of 2014. For more detailed information on our 2015 guidance, please refer to the Form 8-K that we furnished yesterday. With that, I will turn the call back over to Greg.

Thanks, Al. We are pleased with our PAA’s overall performance for 2014. With respect to 2015 guidance, our planning case incorporates oil prices hovering around the $50 per barrel level for the entire year and producer activity levels calibrated to that outlook. Based on our understanding of the public information put forward so far by a number of producers, our approach appears to be on the more conservative side, as it appears many are forecasting a pick up in prices during the second half of the year, which supports a higher activity level than incorporated into our outlook. As we proceed through the year, actual prices and developments will likely require all of us, recalibrate to some extent. We believe our approach of honoring a continuation of current prices for the entire year is a reasonable and prudent course of action that hopefully errs on the conservative side and positions us to benefit from an improvement in prices and activity levels, while minimizing our downside during an uncertain environment. We feel good about the guidance range we provided for 2015 operating and financial performance, as well as our distribution growth targets, and believe our expansion capital program will further strengthen our business platform for many years to come. With this outlook in mind, let me now review our 2015 goals which are highlighted on slide 20. During 2015, we intend to deliver operating and financial performance in line with or above guidance. We intend to successfully execute our 2015 capital program and set the stage for continued growth in 2016 and beyond. Increase our November 2015 annualized distribution by 7% over our November 2014 distribution levels, and finally selectively pursue strategic and accretive acquisitions. PAGP’s goal is also highlighted in the bottom of this slide, which is to increase PAGP’s November 2015 annualized distribution by 21% over the November 2014 distribution level. We are off to a good start with respect to our distribution goals and we look forward to updating you on our progress throughout the year. Prior to opening the call for questions, I would like to mention that Ben Figlock was recently appointed by Occidental Petroleum Corporation to serve on its behalf as a member of our Board of Directors of PAA and PAGP replacing Vicky Sutil. Ben currently serves as Vice President and treasure at Occidental. We are pleased to welcome Ben and look forward to working with him over the coming years. We also want to thank Vicky for her dedicated service to PAA and PAGP Boards. Additionally, I want to mention that we will be holding our PAA and PAGP 2015 Investor Day on June 4 in New York. If you have not received an invitation, but like to attend, please contact our Investor Relations team at 866-890-1291. That’s 866-890-1291. Once again, thank you for participating in today’s call and for you investment in PAA and PAGP. We look forward to updating you on our activities in our first quarter earnings call in May. Gale at this time, we would open the call up for questions.

[Operator Instruction] We’ll go to Brian Zarahn with Barclays, please go ahead.

Good morning.

Good morning, Brain.

Greg, during the oil price slide, you’ve been able to get commitments for new projects, including today’s Permian announcement, but given your new oil price assumptions, how do you view the organic opportunity set going forward?

Brian, I would tell you that we take a fundamental approach and so ours is kind of a grassroots ground up assessment of the resource base and well by well, county by county analysis. So we’re picking the spots that we choose to build projects and to work on building future projects. I don’t think the overall project portfolio has really changed in the aggregate size. Certainly I think there is – versus maybe a view of what we would have assumed those projects would have been developed on let’s say six months ago is probably pushed out into the right a little bit, but for the near term, I really don’t think we’re going to see much different in what we undertake over the next 12 to 24 months than what we might have otherwise. It’s really going to affect years three, four and five and you kind of get that – you see that impact Brain in that one slide where we showed the $80 case and the $50 case and the two recovery cases, it’s basically just pushing everything out into the right, but it’s really not changing from our perspective, the projects we were going after. I think it can affect the marginal projects that others might have been chasing to try and knock the top off of the peak production curve, but that hopefully means there is probably less competition as we go forward but our project portfolio really hasn’t changed materially, wouldn’t you say Harry.

Yeah, I would agree.

So more of a timing issue, I guess, I’m looking at one of your projects. Can you give a little update on Capline? Has the timing of that potentially changed and now it’s a little further out and then how should we think if that project does move ahead, what’s the opportunity potentially to bring West Texas barrels over to St. James potentially increasing the Diamond’s capacity, how should we think about your just overall asset footprint to get more barrels to the Louisiana Gulf Coast?

I’ll let Harry comment on some of the details. But I would just say, if you stand back and look at it from 15,000 feet or 20,000 feet, and you look at the interconnectivity, the extension of the Diamond Pipeline from Cushing to Memphis where we’ll cross over and be able to touch the Capline system, and as you mentioned, the interconnectivity then, we already have barrels coming from West Texas, barrels coming from the Rockies into Cushing and then more Canadian crude coming in, it really puts PAA in the [indiscernible] with respect to being able to service many, many markets. Really can’t add much in the way of information regarding the status of Capline than what’s been put in the press so far, which is that we -- the owners are conducting a study. I think a call earlier this week, Marathon, which was the operator acknowledged that they thought that they would be bringing the study to conclusion with respect that are --finishing the analysis in the first quarter. And then, obviously, there is a lot of discussion that has to happen with the operators. But when you think about it, I mean, Diamond really adds a lot of additional optionality to the potential to optimize Capline. Yes.

So, it’s a longer-term project. Diamond won’t be in service until 2017. Any potential reversal of Capline would have to be after Diamond’s in service. It’s going to be largely supported by Canadian crude supplemented by the ability to the source crude off of Diamond as well. So – but it’s hard to tell lot more than Greg had already mentioned other than probably you think of it as a longer-term project.

And I would view it as an upside option because it really is not contributing significantly to cash flow today. I think the current cash flow that we receive all from Capline is probably in the $10 million a year less. So limited downside, very significant upside if you start running any kind of meaningful volumes through there on a reset tariff.

I’ve taken on that, last one from me, on potential M&A if oil prices are expected to recover the next 12 months, does that imply a rather small window to do acquisitions and also just what’s your view of the competitive environment to do accretive deals given there are so many potential acquirers?

Yes. This is John. Let me comment back, but I’ll give you a couple comments on some things that have actually happened in the market and what we infer from them. We’ve obviously seen two material asset transactions, one up in the Williston of note. And the transaction obviously happened very quickly from a process standpoint. And the price was, I would argue, attractive from a seller standpoint, but sold to a very strategic partner, and it’s for cash. Okay? And the other inference, [indiscernible] E&P company, high quality E&P company, well-capitalized E&P company, I’m doing something strategic. I’m going to bring that up because we would expect to see more of that in the premium basins with the Williston is. A second transaction I’d bring up happened in the Permian, little bit smaller, okay? All cash, clearly a startup, it’s all profit equity comp okay. I bring it up because it was a cash transaction, again, one; in a premier basin, two, and the buyer is betting on a recovery, okay, in activities over the long term. And so -- and it’s probably analogues to what we’re going to see going forward on the asset side both from the E&P companies who are now looking at the sale as a more attractive alternative to an IPO because of timing and the amount of cash they can get upfront and the need and desire to put their capital in the ground faster. And the other – the third transaction obviously was a consolidation among the related parties and that is of note, which I’ll now segue into kind of what, from my perspective, we think is going to happen going forward. And I -- on the consolidation side, combination just feels like we’re going to see over the next 12 to 18 moths and I don’t just put the time frame in the next 12 months, okay, but we will see an increase in consolidation among the MLPs, primarily because of the demographic side we’ve gone from 20 to 120 plus MPLs, okay? Going into this, we had sold at a price to value of $750 billion plus and we’ve had a major change in the underlying fundamentals of the business, which will be the catalyst for consolidation. I do think that if A is going to be very constructive and that will be at a measured pace, okay, there is not going to be a sense of urgency, but it will be a measured pace, people seem to be going through machinations of trying to understand what the impact of the downturn is on their existing assets, their growth projects and their access and cost to capital. And they’re kind of doing that right now. Over the next three to six months, if people figure out what the best alternative for their businesses are, you should see an increase in activity. I don’t expect it to be tomorrow. I mean, it’s going to be again measured in what I would call constructive over the next 12 to 18 months. And this will be very self-serving but hopefully we’ve positioned ourselves both from an access to capital and wherewithal from a capital perspective to participate on the asset side where cash is necessary. And more importantly, on the combination side, because I think the value of the equity having a footprint – a large footprint for businesses when you’re talking about combinations will be paramount in this market. People are really going to – the deals will be there and the owners and boards will give a lot of thought to who they are merging and taking equity from. So – and I think it’ll be a constructive environment and an environment which we’ve somewhat anticipated, but planned for.

Yeah. And Brian, I would just add, I think again as John said, we are not really kind of restricting our thoughts to the next 12 months. What we think is going to be a 12-month to 24-month window, I do think that, as John alluded to, the synergies and commercial capabilities that we have had more value in this type of environment and they have had over the last three years when we were competing against broad availability of capital to everybody at very cheap levels. And the only thing I’d just leave you which is that your ergo was not to try and pick the bottom and say just wait until everything bottoms out before we make a move. We are looking for opportunities to build our business, make it stronger, make it accretive. And part of the negotiation for any transaction, especially when you’ve got a lot of synergies that it takes to make a transaction work is who gets the benefit of those synergies. Do all of them accrue to the benefit or the buyer, or do you have to share some of those with the seller to be able to get a deal done? And the answer is probably the latter. So we are not here to pick the bottom, but we are here looking for ways to -- as we look out 5 years, 10 years and 15 years how do we improve the strength of our business franchise.

Appreciate all the color, guys. Thank you.

Our next question comes from Steve Sherowski with Goldman Sachs. Please go head.

Hi, good morning. Just trying to drill down a little bit more on the guidance revision. I mean, it looks like your volumes, especially out of your transportation and facility segment, are strong. At least, expectations are for strong volume growth coming into 2015. And I’m just wondering, what was the primary revision with the guidance. Does it have anything to do with, perhaps, like lower – your expectation for lower tariffs on certain pipelines or lower spot volumes, just maybe if you could just talk a little bit about that?

Yes. Steve, if you look -- and we included this concept out there, but we have slides like this on each and every area basin. On slide eight is really an overview of what an $80 environment looks like versus a $50 environment. And as you can see, the volume growth in the red and the blue line stays pretty strong through the first three months, four months, five months of the year and then you start to see a falloff. So you are correct in the projects that we have, we got good volume growth, but at the margin, the volumes that were not included in the guidance now that we were before that may have been -- the un-contracted spot volumes we would expect to capture because of the overall just material balance that you need for takeaway capacity certainly adds a lot to margin. The second thing is, I think you saw the facilities segment was flat to down slightly, that’s a combination of volumes. Obviously, as I mentioned in my comments, at the margin – rail – or volumes competing for an exit out of the Rockies on rail, okay, are going to, number one, more competition that tried everybody fill up the railcars and still it’s going to compress margins. So, it’s a combination expecting margin compression and having to adjust fees if appropriate to capture that value. So it’s really a amalgamation of all that, but it’s all really driven by the outlet that change between the blue and the red line that you see there as it affects both pipeline and facilities.

Just on the transportation segment, it’s not tariff related, it’s volume related. It’s -- the tariffs are the heroes, we’re just – we had a forecast at low growth, some growth in 2015. And as Greg mentioned, it’s flat to up, slightly declining in the year, perhaps second half of the year.

Yes. And hopefully – I mean, we are running a $50 case with that. And we are certainly aware that others may be running expectation for – offered $65 on average and we would just observe that in order to get to a $65 average when we’ve already averaged under $50 for the first 33-days of the year, prices would have to go tomorrow because $67 a barrel and stay there for the next 330-days. Or if you believe, we are staying at $50 a barrel for the first quarter; you’re going to have to go to $71 a barrel for the next 330-days. So, I think we’ve got a very realistic outlook about what capital is going be available to be invested, what’s going to get invested And more importantly, if you go beyond this slide A and you look at each and every one of the areas, that’s how we’ve built that up. I hope at the end of the day, they are right and we are wrong because our being wrong means we get to up our numbers. I think when somebody else is wrong, that means they’ve got to come down with their numbers. I would rather be where we are looking up than I would up there looking them.

Now that makes sense and that’s helpful. I guess moving on to John’s comments earlier, just on E&P, potential E&P midstream asset sales. Is there any way that you could quantify or scope that opportunity?

I’m not out -- actually like we prefer not to, okay.

[indiscernible]. If it’s meaningful, we would have mentioned it.

Yeah. Talking too much is about like sometime -- most of the time, I want to respond about like [indiscernible], right? Okay? And the group at the end of the day will let you know who [indiscernible] was. Anyway, so it’s really – and I do want to kind of restrict some of my comments. I actually think it will be fewer than most people would expect, okay, because you’re going to want to have high quality assets underlying the midstream asset, okay, and the volume. Those are by definition are going to the people who have the most wherewithal to go through the downtown. And so I think it will be fewer than most people expect today, coupled with there are a lot of people lining up on the private product equity shops, and lining up in particular they want to step in and do structured deals. So it will be active, okay, but [indiscernible] it won’t be as much as the market thinks. I actually – I’m probably think this will be the driver of the consolidation we’ve all been anticipated over the last, I don’t know, decade and within the industry. But it will take 12 months to 18-plus months to unfold. And again, it’s going to be constructive and I mean that in a positive way. It’s not disruptive consolidation. Okay?

Yes. No, that’s helpful. If I could just have a quick follow-up question, in the past, you’ve mentioned that your supply and logistics business has occasionally act almost as a private equity shop filling demand, back stopping volumes, if you can get those committed volumes from third-parties. Do you see any potential opportunities for that type of transaction or just sort of deal playing out over the next 12 months to 18 months given the weaker commodity price environment?

Well, I may have not understood the comment, I don’t think we ever view ourselves like a private equity shop, period. I think what we have -- are able to do is we’re able because we have a very active gathering and marketing effort and we basically purchase at the wellhead, roughly 1.1 million barrels a day, we have a better feel for the market that many – and we’re able to when we purchase those barrels to determine how we are going to get those to the best market, whether that we’re going to move it by pipelines, on our pipelines or by rail or on third-party pipelines or in the case where we think there is – looks like two competing new pipeline projects necessary where at least one is necessary move product away from the market, we certainly have the ability to make a commitment from our SNL group to – the transportation group, because we again have under contract those barrels and we get to select which market they go to. So I wouldn’t characterize it as a private equity approach at all where I think they’re just monetizing credit rating more than they are moving barrels on. But that’s what the self help is, that’s why during these down cycles that you saw on one of the slides that I talked about, we’re able to make sure that the barrels go -- the charity begins at home, we’re going to send it with our pipelines.

That’s helpful. That’s it for me. Thank you.

Our next question comes from Jeremy Tonet with JPMorgan. Please go head.

Hi, good morning.

Hey, Jeremy.

I was just wondering if you could comment a little bit more on the market structure for contango out there. It seems like it is pretty stable right now and I know generally Plains only bakes in with near term invisibles as far as guidance concerned. And I was just wondering what potential upside could we see if a stable contango environment persist through the balance of the year.

Certainly, we haven’t put to bed all the contango opportunities that are out there right now. There is a lot of considerations that go into those. There are certainly some potential for outside and as you say, we do factor into our near term guidance the – capturing that which is obviously available, it makes sense to lock in. I would tell you at this point in time, well, again, it’s -- there is upside to our numbers, there is other things going on out there. I mean, if we go back to $44 or $40 price level, you might see, yeah, we capture more contango, but we may see producers producing less volumes that we forecasted. So, I go back to my comments in the conference call that we are comfortable with – we feel good about the guidance. We feel good about the distribution growth and we certainly feel good about the long term. But I would hate to try to take one aspect of what’s going on in the market and say that will be added to but nothing else changed because I think personally you are going to hear changes throughout the year. And I think some producers they think they can get by with only cutting their budget 20% and our numbers assumes that they are going to have to cut 40%. I think you are going to see some of those changes ripple through there. So -- and it could be difficult. I mean, there might be more opportunities to capitalize on contango and then what you currently see for the next 12 months is market are dynamic, but there will be all setting aspect to it as well. So I would want you just to hang your head on that one very positive node that, yes, we were aware of it, we are following and we are participating. But I just have to tell you, there is a heck of a lot going on in the industry right now. We are in the state of transition and I think some are in a state of denial and what we’ve tried to do is give you a very realistic approach that says if you think about it, if I gave you a forecast and said, here is our numbers and they are right back where they were, let’s say, before we did revise it down. And we say, we are counting on $65 oil, that means production, I mean volumes – excuse me, price would have to go up 40% from the current level. I mean, it just doesn’t make sense. I mean, you wouldn’t want me to tell you at $100 oil, [indiscernible] and so I think we are not in control of the mechanisms that are driving prices, we are on top of the issues that are driving volumes and that’s what we’ve reflected in our guidance.

That’s makes sense, thanks for that. And I was wondering if you comment a bit on rail and how rail fits into this new environment where basis differentials are a bit tighter. Do you a see bunch of change in your outlook there?

Yeah, I think we forecasted that into – we included into our forecast for 2015 that we expect for part of the year real differentials to be tighter than the normal. Seems like a lot of volumes are going to Cushing because there is sort of storage full there and once storage gets full at Cushing, you should see the differentials normalize again, where rail would go to natural market. Cushing is selling up at a pretty high rate and in two months it will be full.

Yeah. I think we have seen this before where differentials can get upside down from what you thought historical relationships are. There is a really good chance we are going to see some of that happen here, but I would tell you, in general, rail whether it’s the – the railroad companies, whether it’s those that furnish cars or those that furnish load and unload fees are just like service and supply guys coming under pressure to the producers. That part of the market is going to come under pressure because there is a lot of excess capacity out there, if volumes aren’t filling up everything and its going to be margin depression. So as Harry said, we’ve tried to factor that into our guidance. Hope we’re wrong, we’ll get to revise our numbers up, but it would have been foolish on our part to assume that we are going to do the same volume at the same price for the marginal barrel when we know that there is an excess of loading and unloading capacity certainly, and then as you went out differential should come in. We’ve seen already in the last probably 45-days Brent trade inside of WTI, and today I think it’s $6 outside of WTI. That doesn’t sound to me like it’s a steady state planning model.

Okay, great. So, at this point, would it be fair to say that you haven’t deferred any of your growth CapEx plans on the rail car?

No, I think the one we had in Progress, we were confident. We’ve put in service the Bakersfield facility, we’ve got a few tweaks backed by commitments on a few other facilities and then we are preparing for some additional optionality in some of our unloading facilities.

Yeah. And then, we got project up in Canada [indiscernible] heavier Canadian crude.

Okay, great. Thanks. And then I suppose I’ll leave with the obligatory M&A question at this point. And I was just wondering, I mean, you guys have a tremendous crude oil platform and I am wondering a lot of the crude oil assets, I don’t think we have seen as much pain at this point or prices necessarily come down, where we are seeing more pain in the midstream market's more outside of crude, maybe towards natural gas, NGLs, gathering and processing, and potentially cheaper assets to be picked up there. And I’m just wondering, is that an area that would be of interest to you guys to diversify it further into or is that something outside of what you are looking for?

We obviously have a substantial NGL business and we have continuously looked at the NGL assets that have been on the market over the last several years. And we will continue to look at them. They've probably been impacted by the commodity downturn as anybody in the 'midstream space', just because of the processing contracts, nature of some of the processing contracts and how close they are to the wellhead. And so we’re trying to really kind of digest what the cash flow generating capacity of those assets, those types of assets and businesses are. And so I think that’s the first thing you’re going to have to do.

Yeah, I think, kind of to add on to that, Jeremy, I think number one, we’re looking for good deals. We don’t really have diversification as a strategy. We like the businesses that we’re in and we’d certainly like to be bigger in the businesses that we are in. I think where we have the most competitive advantages in an even playing field is in which the absence of widely available cheap capital kind of levels the playing field a little bit; is where we have synergies and we have most of those in the crude oil NGL area. So we’re not against good deals in other parts of the business where we already have a footprint, but we’re not looking to 'diversify for the sake of diversification'. We are looking for good deals and we think the good deals are mostly going to come in the areas where we have the synergy, which would be the crude oil NGLs.

That makes sense. Thanks for all that color.

Our next question will come from Mark Reichman with Simmons and Company. Please go ahead.

Morning, just a few questions. With the contango and the crude market oil structure, could you just talk a little bit about the contract profile of your crude oil storage, and discuss your ability to benefit from perhaps renewing capacity at higher rates and also your plans to keep storage available for your own activities?

Well, keep in mind, we’ve got 120 million barrels plus of above-gas storage capacity. And I'd probably tell you that we’re not going to be the company that’s going to go out to our customers and say, there is a contango market and we’re going to try to jack the rates up because of that, primarily because the markets we serve are the ones that are going to use it regardless of whether it's a contango or a [indiscernible] market. So at Cushing for example, I think we’ve got over 20 million barrels and 90% of that – 95% is lease to long-term customers that use it, again regardless – I mean, they are the refiners of the gas that are operational storage and they were the ones that renewed with us when rates were low and they were at higher rates than what others were getting. I think ones that probably fall into the category that your tiering to are the ones not in the Tier 1, the preferred area of Cushing, but they are in Tier 2 and Tier 3 where they are really the only users I should have taken just for contango opportunities. And I think certainly they’re going to do just what you said if they can. As far as – we manage the portfolio of assets. We haven't disclosed exactly how much of that we use for own account, but it’s meaningful. I mean it's enough to where we can participate in the opportunities, but not so much where we've got a lot of dead assets so to speak when there is not contango opportunities. And beyond just – by the way the contango that you see out on the strip for the WTI, there has always been other opportunities on a grade basis or a location issue. And so, again, I will just recap by saying, I think we have 5% of our tankaging [ph] in Cushing is really for own account, the rest of it's for our customers account. That’s the way we want it. It’s the way an MLP with steady state P-based activities growing its distribution wants to have it. Throughout the rest of the many million barrels that we have throughout the U.S. and Canada, there are areas where we have strategically pilled off opportunities or mass of tankage for our own account and we’ll use that for these types of opportunities because as you might expect the contango doesn’t just exist in Cushing. We’re able to access it in other parts of the U.S. and Canada.

And with this challenging environment for producers, are you getting any request for discounts on say like transportation contracts and under what circumstances might you discount?

I can think of a hundred reasons why I shouldn’t answer that, not one where I should just because I mean our customers – we’re here to get the best value for the service that we provide, and so if I could respectfully decline to give our competitors or our customers a roadmap as to how to get more money out of my pocket I’ll do that.

Thank you. Fair enough. And then just lastly, with respect to the state line pipeline, what would you expect in terms of the mix between condensate and crude?

I think state line is probably going to be more of a crude-based line. And that area – the whole area is kind of variable; you get areas where – you get pockets where there is 40 gravity crude, and not too far away you get pockets where there is 50 gravity crude. So we’re set up all those systems to segregate the condensate and crude, not to batch condensate and crude into Blacktip. And then we have two platforms from Blacktip to Wink. And then, well. most of the pipelines are out of Wink, so we will be able to segregate the condensate if – if it's market demand, have it segregated.

Thank you very much.

Thanks, Mark.

Our next question will come from Cory Garcia with Raymond James. Please go ahead.

Good morning, guys. Two quick ones for you; I guess flipping back to sort of your commentary on 2015 guidance and then recognizing and appreciate actually the conservatism on that $50 price tag, but curious if there is any rule of thumb or any color you guys could provide, say, on sort of different oil price sensitivities, if we should just simply back-end to, okay, was $80, now it's $50 at the difference, or is there different price points in terms of every $5 or $10 move higher from there equates to X amount of cash flow? Is there a rule of thumb to back-end any sort of sensitivity there?

No, there is not, Cory. And the reason for that and you kind of – I'm going to get you back to slide A. To some extent we don’t have any direct exposure to the commodity price of any significance at all.

Right.

We are impacted by what producers have available to invest, and that’s tied to their cash flow. So we clearly run areas for example where – in the Permian for example, there – a project at $80 oil may have made them a 35% rate of return, and at $50 oil it only makes them a 5% rate of return. Well, that’s an area then that we would say, gosh, we don’t expect a lot of volume growth. On the other hand, we run numbers that say, in that area that only has 5% return, if the services supply cost that they are paying go down 20%, that number may go back up to 15% to 18%. And so there is so many issues that are below the surface that are going on, that are going to impact that. And so we do have perspectives in our company as to each area what we think it’s going to take to move that. But there is no way that you could put that in any kind of normal graph and say, here is the impact on PAA, because again we are not the ones directly exposed to the commodity prices, the producers. But again, there is a lot of factors that can affect their availability of capital and their willingness to drill in particular areas, and you almost have to have all the information we have to be able to come up with that. So, I do think we try to combat that, so we don’t keep you in the dark. I think we've put the most detailed guidance out there on area-by-area, pipeline-by-pipeline than anybody in the business and we will continue to do that.

I absolutely appreciate that, there are quite a few moveable pieces in this whole equation. I guess change in focus for Saskatchewan, how should we be thinking about the phase-in of cash flow from these projects, because I see a nice uptick in capital over the next two years. Should this be similar to your other projects where the cash flow gestation period's call it a year or 18 months or is there different sort of phases to look in over the next maybe 12 months or 18 months where we can actually see some of that cash flow ramp sooner.

Those are projects that take a little longer time to develop – you are developing caverns and rail facilities and brine capacity. So it’s probably more like at 18 months to 24 months.

Okay.

…time. So you probably start kicking in mid-2016.

And even there, Cory, you will end up with kind of like we had in Cactus where you are going to start off at one level and then the volumes will build up. And that’s why we talk about lot of the capital we are spending now is really not having any impact on 2015, it will start in 2016. You will probably see the full run-up in 2017 and some are going to be in the early 2018.

Okay, great. Thanks for the color I guess.

Thank you.

Our next question comes from Matthew Phillips with Clarkson. Please go ahead.

Good morning, guys.

Hey, Matthew.

To really beat a dead horse on the M&A topic, I mean in the past couple of years you all have invested a lot of capital in the Eagle Ford and the Permian Mid-Continent in general. I mean do you expect M&A opportunities to mirror that or do you see this as a chance to enter new basins, increase your footprint in Canada, things like that?

Again, I go back to, we are looking for good deals. There is a not an area that we are in right now we wouldn’t want to be bigger and better in that. So we are certainly looking in our own backyard. There is also areas that we believe that there is opportunity for volumetric growth where we don’t have as big a footprint currently as we'd like to have. But I know you want to ask me on this call to tell our competitors where we're looking, so I don’t like to worry about that. As far as – again, we are not looking for diversification for the sake of diversification; we are looking for good deals in areas where we can have synergies. I will say that there is an opportunity because of the way we have interconnected and would intend to interconnect any area that we branch out into geographically to capture incremental synergies. So you shouldn’t assume that just because we are not there currently doesn't mean we wouldn’t have synergies if we bought a footprint there. If anything, that’s the kind of the value we can bring to the table. So it’s more the same.

Okay, great. Thank you.

Thank you.

Our next question comes from Sunil Sibal with Global Hunter Securities. Please go ahead.

Hi, good morning guys and thanks for taking my question. So my question is related really to the facility segment and rail projects that you are bringing online in 2015. How should we be thinking about the volume commitments on those facilities? I mean, what kind of, in terms of percentages, commitments out there and are the commitments sufficient to meet your hurdle rate of mid-teens kind of returns on those projects?

Most of the project that we are bringing on in 2015 in fact are supported by commitments. I think, Cactus for example is one, and while it’s got a lot of commitments we also have some plumbing to do to be able to fully optimize the benefit of that. So, even though we may have capacity today we open that line up to do – to put 200,000 barrels a day in, we don’t necessarily have the capacity at the other end of the pipe to take 200,000 barrels day out if we move on to the systems. That’s why it’s important for us to expand the JV. But having said that we have sufficient commitments on that and several of the other projects, Eagle Ford etcetera to support the expansion of those and meet our minimum rate return. In some cases, the minimum rate of return may be 100 basis points or 200 basis points over our cost of capital, which won’t get you to the mid-teens, but then the optionality or the ability for spot barrels to fill up the remaining space gets you there, which again is the function then of kind of what the overall volume level is in the areas and what markets we serve versus others. So I think from a downside protection, we’re in very good shape; from an upside opportunity we've got room to run.

Okay and that’s helpful. And then on the M&A front, I think you previously talked about support from the GP, especially when bidding on assets in this very competitive environment, I was kind of curious if there is any updated thoughts there with regard to the support from GP or [indiscernible] concessions?

Well, we’ve been preparing them for this type of market for a while, but I’d say we have no less tools than what we had coming into this, and it seems like we probably have more desire to use the tools that we have. So, there is supported today as they ever have been and probably more so especially when we see good deals.

Okay and then just one last one from me. When you look at 2015 CapEx program in terms of the funding, you obviously did the $1 billion facility. How should we be thinking about supporting the 2015 program from a debt and equity perspective?

Go ahead.

Yeah, our plan would be to continue to finance our growth capital with equity and long term debt. The liquidity facility was designed to bolster our liquidity in a, what we think would be a fairly uncertain time. So again, the plan will be raising equity either through our continuous equity offering program or through an underwritten offering, and accessing the senior notes market at some point.

Yeah. I’d say, Sunil, the important thing is we will continue to keep a balanced funding approach. We don’t use the real low slightly higher than free short-term debt rates when we look at our analysis. So we are using basically the 10-year rate with our credit spread on top of it and then we are using the equity. So it’s about a 55%, 45% – 55% equity, 45% debt and that’s what we will continue to do. So, no change there, but again keep in mind, we kind of entered into this opportunity in the fourth quarter last year, pre-funded with the opportunity to take advantage of acquisitions than we did, and we have got additional funding this year on the capital program, but again nothing that’s going to be a significant hurdle.

Okay. Very helpful. Thanks.

Our next question comes from Lynn Shen with Hyped [ph]. Please go ahead.

Good morning. Thank you for taking my question. Can you comment a little bit more about the current contango market and how long do you think will it last? You just mentioned that Cushing is filling up very quickly, may be full in two months or so. So how will it change the contango market?

Well, part of its going to be a function of what’s happens in the other markets. Once it gets full, obviously then the differentials are going to change. To pull the barrels out of Cushing, you're going to have to have some differential that supports the movement because to get from Cushing to say the Gulf Coast is about $3 plus there. And right now the markets, Lynn, don't support that movement at the margin. So I think the answer is, depending on what happens to demand and refinery turnarounds etcetera, you are going to see a little bit of – if you are familiar with that name whack-a-mole, you are going to see certain things pop up and you are going to knock that down and something else is going to pop. So if we had the absolute roadmap of what it would looks like, we probably wouldn’t share it on this phone call just because it would be a competitive advantage. But we do think we have assets in all the right areas to be able to be a meaningful participant in that type of favorable market [indiscernible] favorable for our business model, maybe not so favorable for others.

One of the refinery talk about their contango market yesterday or the day before yesterday on their conference call that they expected their contango in the first half this year and then like less contango in second half this year or so. Do you think that makes sense?

I have to know more what their fundamental assumptions are. And again, it may be specific to their regions that they are in. So I really couldn’t comment on those without having more context.

But I think you either need more demand or less supply to change the dynamics of the contango market. It will be contango until supply and demand get balanced and you fundamentally start pulling crude out of storage.

Yeah, there is some quality issues, Lynn, that also will affect the ability to bleed the storage down so that you don’t have a continued contango market because a lot of what we are producing today that is not wanted by the market is the lighter sweet crude or lighter condensate. And to the extent that’s getting stored, you are not only going to have to have a change in market structure but you got to change in quality differentials to be able to balance that out. So I think we probably – if we had to [indiscernible] there on the side of it, once it gets in full in, in contango it could stay here longer than we think unless – obviously if Saudi Arabia comes out at July 1 and says they are going to cut production a significant amount, it might change the market almost immediately both more for perception and reality but it'd still change it. So, I would say anybody that actually says they know what the market's going to do – yeah, I'd just leave it at that. It'd be tough to really have that kind of vision.

Okay, thank you very much. Appreciate it.

And our final question will come from Selman Akyol with Stifel. Please go head.

Thank you, good morning. One quick question here just regarding the facility segment guidance. Your per barrel profit goes from $0.41 to $0.38 for 2014, and I think in some of your previous comments you mentioned that that was really due to maybe more competitive rail rates. And in the fourth quarter that you just reported facilities you really called out you referenced declining natural gas storage rates. So the question I’m asking here is, is that debated in terms of natural gas storage rates or is that sort of fairly strong headwind going into 2015 and is reflected in the declining rates there as well.

It’s included, but natural gas storage is only 4% of total EBITDA or something. It is not huge. I mean its – so point being, this is not going to be the driver for that. It’s other factors, but all that is wrapped up I would say. The natural gas storage is still facing headwinds. I think we had indicated a year ago that we thought this was probably going to stay around for three years. Hopefully, it still only has two years left, but there is no question it hasn’t abated from where it was.

That’s not really a big driver between 2014 and 2015. And gas processing in the Gulf Coast is also included in the facility segment, and those margins will be tighter in 2015 than they were in 2014.

All right. thank you very much.

Thank you, Selman.

We have no further questions.

All right. We really appreciate everybody down there and for those who are invested in Plains we appreciate your confidence in us and we look to update you on our activities in the first quarter – for the first quarter in May. Thank you.

Ladies and gentlemen, that does conclude your conference for today. Thank you for your participation and for using AT&T teleconference service. You may now disconnect.