Plains All American Pipeline, L.P. (PAA) Q1 2014 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. And welcome to the PAA and PAGP First Quarter Results Conference Call. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will be given at that time. (Operator Instructions) As a reminder, this conference is being recorded. I would now like to turn the conference over to our host Mr. Ryan Smith, Director of Investor Relations. Please go ahead, sir.

Thanks, Towanda. Good morning. My name is Ryan Smith, Director of Investor Relations. We welcome you to Plains All American Pipeline’s first 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 plainsallamerican.com. I would mention that throughout the call we would refer to Plains All American Pipeline by its New York Stock Exchange ticker symbol of PAA. In addition to reviewing the recent results, we will provide forward-looking comments on PAA’s outlook for the future. In order to avail ourselves of Safe Harbor precepts that encourage companies to provide this type of information we direct you to risks and warnings set forth in the partnership’s most recent and future filings with the Securities and Exchange Commission. Today’s presentation will also include references to certain non-GAAP financial measures such as EBITDA. The non-GAAP reconciliations section of our websites reconcile certain non-GAAP financial measures to the most directly comparable GAAP financial measures and provides a table of selected items that impact comparability of PAA’s reported financial information. References to adjusted financial metrics exclude the effect of these selected items. Also all references to net income are references to net income attributable to PAA. Today’s presentation will also include selected financial information of Plains GP Holdings which we will refer to by its New York Stock Exchange ticker symbol of PAGP. PAGP’s only assets are its economic ownership interest in PAA’s general partner and incentive distribution rights. As a controlled entity of PAA, PAGP consolidates 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 that reconciles PAGP’s distributions from PAA’s general partner with the distributions to PAGP’s shareholders as well as a summarized consolidating balance sheet. Today’s call will be chaired by Greg L. Armstrong, Chairman and CEO. Also participating in the call are Harry Pefanis, President and COO; and Al Swanson, Executive Vice President and CFO. In addition to these gentlemen and myself, we have several other members of our management team present and available for the question-and-answer session. With that, I’ll turn the call over to Greg.

Thanks, Ryan. Good morning and welcome to all. Yesterday after market closed, PAA reported first quarter adjusted EBITDA of $567 million. These results were $42 million above the midpoint of our guidance for the first quarter of 2014. Harry will provide a detailed comparison of the guidance for each of our segments later in the call. However, I would generally characterize our first quarter results as solid, especially considering some of the weather related challenges that PAA, as well as the industry faced during the first quarter. Slide 3 contains comparisons to the last year first quarter results for adjusted EBITDA, implied DCF and distribution coverage and adjusted net income per diluted unit. Each of these comparisons reflects the impact of very favorable crude oil market conditions experienced in the first quarter of 2013. Our crude oil and NGL results were very solid if not strong in all three segments but a portion of the above guidance performance from these activities was offset by weather-related issues that were just gaining momentum at the time of our last quarterly conference call. The impact of severe weather was most obvious in our Facilities segment, where we incurred unforecasted cost in our natural gas storage activities to maintain deliverability requirements and also experienced a shortfall in crude oil rail volumes. These weather related shortfalls were more than offset by solid performance from crude oil and NGL activities in our Transportation and Supply and Logistics segments. As reflected on Slide 4, this quarter’s results mark the 49th consecutive quarter that PAA has delivered results in line with or above guidance. Additionally, last month PAA declared a distribution of $0.63 per common unit, or $2.52 per unit on an annualized basis payable next week on May 15. This distribution represents a 9.6% increase over the Partnership’s distribution paid in May, 2013 and a 2.4% increase over the partnership distribution paid in February 2014. Distribution coverage for the quarter was 125%. As reflected on the bottom of Slide 4, PAA has increased its distribution in 38 of the past 40 quarters and consecutively in each of the last 19 quarters. Additionally, PAGP’s quarterly distribution of approximately $0.17 per share represents a 14.4% increase over the initial quarterly distribution included in its October 2013 IPO prospectus. PAA continues to execute well and we are on track to meet or exceed our 2014 goals and to position PAA favorably for 2015 and beyond. During the remainder of today’s call we will discuss the specifics of PAA’s segment performance relative to guidance, our expansion capital program, our financial position and the major drivers and assumptions supporting PAA’s financial and operating guidance. At the end of the call, I’ll provide a recap as well as a few comments regarding our outlook for the future. With that I will turn the call over to Harry.

Thanks, Greg. During my section of the call I will review our first quarter operating results compared to the midpoint of our guidance, the operational assumptions used to generate our second quarter guidance, and I will provide an update to our 2014 capital program. As shown on Slide 5, adjusted segment profit for the Transportation segment was $213 million, which was approximately $9 million above the midpoint of our guidance. Volumes of 3.84 million barrels per day were slightly below our guidance. However, I note that the volume shortfall was largely attributable to pipelines where the capacity is leased to third parties, and variance in these volumes did not impact our performance. Adjusted segment profit per barrel was $0.62 or $0.03 above the midpoint of our guidance. The higher than anticipated segment profit was primarily due to some of our integrity management projects - with the timing of some of our integrity management projects, which has deferred approximately $7 million of operating expenses to the second quarter of this year. Adjusted segment profit for the Facilities segment was $159 million or approximately $7 million below the midpoint of our guidance. Volumes of 121 million barrels of oil equivalent per month were 3 million barrels below the midpoint of our guidance and adjusted segment profit per barrel was $0.44 or about $0.01 below the midpoint of our guidance. Volumes were lower primarily due to weather impacts on our crude oil rail activities and slightly lower third party volumes. Also as Greg mentioned previously, we incurred unanticipated costs to manage delivery of the requirements for our natural gas storage business. Adjusted segment profit for Supply and Logistics segment was $194 million or approximately $39 million higher than the midpoint of our guidance. Volumes of approximately 1.17 million barrels per day were slightly below our guidance primarily due to weather related reduction in lease gathering volumes. Adjusted segment profit per barrel was $1.85 or $0.40 above the midpoint of our guidance. Overall performance was primarily due to better than expected crude oil differentials, higher than forecasted margins related to NGL sales but partially offset by cost to meet delivery requirements at our gas storage facilities during the extended period of cold weather this winter. We believe that we’ve addressed the deliverability issues going forward by purchasing additional base gas and although this had a negative impact on our results for the quarter, we believe that [other] [ph] facilities experienced deliverability issues and in general this should bode well for natural gas storage rates going forward. Let me now move on to Slide 6 and review the operational assumptions used to generate our second quarter 2014 guidance furnished yesterday. For our Transportation segment, we expect volumes to average approximately 3.95 million barrels per day; compared to the first quarter the volume increase is primarily attributable to production increases in the Eagle Ford and Mid-Continent areas plus a return to historical volume levels on pipelines leased to third parties. The forecast also assumes approximately 20,000 barrels a day of lower volumes on our Canadian pipelines in the expectation that we could have some curtailments during the flood season. I’ll note that going forward we have moved several assets in Canada from Facilities to Transportation so compared to the first quarter there are slight benefits to Transportation offset by a slight decrease to facilities. We expect adjusted segment profit for barrels of $0.57 which is lower than the first quarter primarily due to the fact that our integrity management costs are more heavily weighted towards the second quarter. For our facilities segment, we expect an average capacity of 122 million barrels of oil equivalent, a slight increase from first quarter volumes as we expect to recover from the weather related impacts of our rail volumes. I’ll note that we continue to expect [probably lower] [ph] third party volumes that have been originally forecasted. Adjusted segment profit is expected to be $0.37 per barrel which is lower than the first quarter results as our maintenance and integrity management cost are typically higher in the second quarter. In addition revenue from our NGL facilities is expected to be lower during the second quarter as we do not expect to produce the same level of component gains as we saw in the higher throughput winter months plus the impact of inter-segment transfers I previously mentioned. First our Supply and Logistics segment, we expect volumes to averages approximately 1.07 million barrels per day compared to first quarter results; lease gathering volumes are expected to increase by 47,000 barrels per day, but NGL volumes are expected to decline seasonally by 143,000 barrels per day. Adjusted segment profit is expected to be $1.17 per barrel. Although we expect to benefit from crude oil differentials in the second quarter, NGL revenues will be seasonally lower and account for most of the difference when compared to the first quarter segment profit per barrel. Let me now move on to our capital program. As shown on Slide 7, we have increased our 2014 expansion capital by $150 million to a revised target of approximately $1.85 billion. The increase includes the purchase of base gas at our natural gas storage facilities, and the advancement of some of our projects in the Permian Basin. The expected in-service timing of larger projects in our capital program is included in slide 8. And I’ll note in service dates on some of the projects in the Permian slipped a bit, but nothing that we’d consider meaningful. I will provide a status update on a few of these projects now. We continue to add projects in our most active area, the Permian Basin. Including the cactus pipeline we expect to invest approximately $1.1 billion in the Permian with approximately $800 million expected for 2014. We are investing approximately $475 million to debottleneck the Delaware Basin and the southern portion of the Midland Basin. We expect to incur approximately $310 million of this amount in 2014. The debottlenecking will occur in phases and should be completed by the end of the first quarter or early in the second quarter of 2015. These projects will increase pipeline capacities in Southeastern Mexico and the far western regions of the Delaware Basin by approximately 350,000 barrels per day and increase capacity in the southern portion of the Midland Basin by over 200,000 barrels per day. We also will improve the flexibility of our gathering system in the Permian Basin by providing additional capacity to move crude oil to Crane and McCamey where we have connections with pipeline [focusing] [ph] the Gulf Coast market. In addition to debottlenecking the infrastructure in the Permian Basin, we are also investing approximately $530 million in two projects to increase takeaway capacity of which $450 million is expected to be incurred in 2014. The projects include our Cactus pipeline which is a $440 million project to build a 310 mile 20 inch pipeline from McCamey to Gardendale, and a $90 million investment to build 80-mile, 20-inch pipeline from Midland to Colorado City. In the Eagle Ford we recently agreed to lift the entire segment of our joint venture pipeline from Gardendale to Three Rivers; this is approximately $75 million investment net to our 50% interest and will expand capacity [on this line] [ph] to 470,000 barrels per day primarily to accommodate increased receipts from our Cactus pipeline. We expect to incur approximately $60 million of the cost in 2014 and the project is scheduled to be in service in mid 2015. In Canada we are advancing plans for a significant expansion of our facilities at Fort Sask. Phase I of the project will increase propane and butane storage capacity by 700,000 barrels and will convert approximately 2.2 million barrels of existing NGL storage capacity to condensate storage. We’re also increasing [inaudible] capacity by 2.5 million barrels, so we can fully utilize our cavern capacity. We are currently in the permitting stages of this project and are also advancing additional expansion opportunities in this area. Finally, maintenance capital expenditures for the quarter were $46 million; we expect maintenance capital expenditures for 2014 to range between $185 million and $205 million. With that I will turn it over to Al.

Thanks, Harry. During my portion of the call, I will review our financing activities, capitalizations, and liquidity as well as our guidance for the second quarter and full year of 2014. Our financing activities this quarter were limited to our continuous equity offering program. PAA sold approximately 2.8 million units in the first quarter raising net proceeds of approximately $150 million. Additionally in April, we completed $700 million offering 4.7% 30-year senior unsecured notes. With the completion of this offering we have termed out the majority of the debt funding requirements of our 2014 capital program. As illustrated on Slide 9, PAA ended the first quarter with strong capitalization, credit metrics that are favorable to our targets and $2 billion of committed liquidity. At March 31, PAA had long-term debt to capitalization ratio of 47%, a long-term debt to EBITDA, adjusted EBITDA ratio of 3.2 times. Slide 10 summarizes information regarding our short-term debt, hedged inventory and line fill at quarter end. I would also point out that in April both rating agencies affirmed PAA’s credit ratings at Baa2 and BBB, and also changed PAA’s outlook from stable to positive. Moving on to PAA’s guidance as summarized on slide 11, we are forecasting midpoint adjusted EBITDA of $455 million and $2.15 billion for the second quarter and full year of 2014 respectively. Consistent with past practice our guidance for the second quarter only takes into account favorable market conditions to the extent that we are highly confident that our current activities will capitalize on those conditions, with an assumed return to near baseline type market conditions for supply and logistics segment for the balance of the year. Accordingly we continue to expect negative quarter-over-quarter and year-over-year Supply and Logistics segment profit comparison in 2014 as market conditions during the first half of 2013 were extremely favorable for our assets and business model. We did not increase our 2014 adjusted EBITDA guidance from the $2.15 billion provided in February, even though we outperformed guidance in the first quarter. A major part of the reason is the weaker Canadian dollar. We revised the FX rate in our updated guidance to be 1.1 exchange rate versus our prior forecast of 1.05 which negatively impacts adjusted EBITDA by approximately $30 million for the year. The FX rate is more of a reporting matter than an economic issue as our 2014 Canadian cash flow will be used to fund our Canadian investments for 2014. However, it does impact reported EBITDA, BCF, and distribution coverage. Additionally as Harry mentioned, some operating expenses were deferred from the first quarter to the later part of the year due to both weather and scheduling issues. Our updated 2014 guidance forecast, also reflects some shifting and adjusted EBITDA between segments in order to incorporate the project timing and volume ramp up adjustments Harry discussed for certain of our transportation and facility capital projects. In certain cases delay in commencing operations on capital projects results in higher margins in our Supply and Logistics activities. We remain confident that the $1.6 billion of investments that we made in our Transportation and Facilities segment businesses in 2013 combined with our expected $1.85 billion 2014 capital program will continue to provide meaningful growth in these segments into 2015 and beyond. Furthermore the cumulative effect of these capital investments provides us with good visibility for continued multi-year distribution growth. For more detailed information on our 2014 guidance please refer to the Form 8-K furnished yesterday. As represented on Slide 12, 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 approximately 110% in line with our targeted coverage of approximately 105% to 110%. This will enable PAA to retain approximately $137 million of excess DCF or equity capital. Given our strong capitalization at quarter-end, our projection for retained DCF for the balance of the year and our continuous equity offering program, we are also well positioned to finance our 2014 expansion capital program and moderately size acquisitions. As a result absent significant acquisition activity, we do not expect to execute in overnight or marketed equity offering during 2014. With that, I'll turn the call back over to Greg.

Thanks, Al. As highlighted throughout the call today, the first quarter was another solid quarter of performance for PAA. Furthermore, looking forward, we believe PAA is well positioned for continued growth in our fundamental business activities and distributions. The three primary factors underpinning that outlook include the fact that number one we have a proven business model, strategically located and flexible asset base and experienced management team that have demonstrated the ability to deliver solid results in almost any market conditions. Second, a sizable portfolio of organic growth projects that build on the existing footprint provide attractive economic returns and will drive fundamental growth for the foreseeable future. And third and finally as Al just mentioned a very solid capitalization, substantial liquidity and significant financial flexibility that not only enables us to comfortably execute our ongoing capital program but also to capitalize on attractive acquisition opportunities almost irrespective of capital market conditions at the time such acquisitions are available. In closing we remain on track to achieve our goals for 2014, which include delivering on our annual operating and financial guidance and increasing PAA’s and PAGP’s distribution in 2014 by 10% and approximately 25% respectively. Prior to opening our call up for questions I do want to mention that we will be holding a joint PAA and PAGP Analyst Meeting on June 5 in Houston. At this meeting, we will share our views on the industry environment for the next several years, discuss our positioning with respect to this environment, and provide a deeper dive into our activities than is possible during our quarterly conference calls or investor conferences. If you have not received an invitation but would like to attend, please e-mail our investor relations team at investorrelations@paalp.com. Thank you for participating in today’s call and for your investment in PAA and PAGP. We are excited about our prospects for the future and we look forward to updating you on our activities in our Analyst Meeting and in our next call in August. Towanda, we’re now ready to open the call up for questions.

(Operator Instructions) First question comes from the line of Brian Zarahn with Barclays. Please go ahead, sir. Brian Zarahn – Barclays Capital, Inc.: Good morning.

Good morning, Brian. Brian Zarahn – Barclays Capital, Inc.: On full-year guidance, can you elaborate a bit on your expectations for rail volumes and then gas storage capacity, and then also how much is the headwind of the Canadian dollar impacts to segment?

Sure, I’ll start with rail. And so we expect the rail volumes to be down a little bit than we originally had forecasted, the number of reasons, we’re seeing some crude moved to pipe which is being a little massed because we’re also expecting some seasonal decline in pipeline volumes potentially for during the flood season in Canada. But so some of it’s moving to pipe and we’re seeing a little bit of congestion on the rails. We have sort of moderated our expectations for the movement and we’re seeing a little less volume coming into the Gulf Coast, more are trying to go to the East and West Coast, but we are a little barge limited on the East Coast. So it’s kind of a combination of three or four different impacts. We still like the rail business, it is very complementary to our pipes and they sort of offset each other.

Yes, and then on the – I think you mentioned Brian that the gas storage capacity, we tweaked our numbers a little bit there to reflect the fact that we will be – we ran into the headwinds in the first quarter. We’ve got some refill issues throughout the year, but we just really - it’s minor tweaks. So I think it’s very minor in the big picture. And then the last issue was on FX. Again I think Al's summary that it is about $30 million impact on the full year. Obviously, if the Canadian dollar gets stronger throughout the rest of the year, it could have an impact, but I think it’s about for every five basis points movement it’s probably for the balance of the year, it’s probably call it $20 million impact. Does that help? Brian Zarahn – Barclays Capital, Inc.: It does. And then I guess of the change in guidance for the segment, would that be more gas storage or rail related piece?

More rail related on the segment… Brian Zarahn – Barclays Capital, Inc.: Okay.

Gas storage is really a first quarter issue, not a balance of year. Brian Zarahn – Barclays Capital, Inc.: Okay.

And on the Facilities segment, we did move a few assets – some assets between Facilities and Transportation going forward, as Harry mentioned.

Yes, some of the storage capacity in Canada actually operates more in conjunction with the pipes than the independent storage facility so we’ve moved; there is a little bit of a tweak there. Brian Zarahn – Barclays Capital, Inc.: Okay. And then some topic of rail, any general comments on crude by rail environment given the price differentials and all the –the new safety regulations out of Canada and the pending regulations in the U.S.?

I think you have got the likelihood that you could see a little slower turnaround times on rail movements, so that’s sort of part of the moderation for our second half of the year. We think new rail regs are coming. It's going to be a combination of regulations [and packing] [ph] the railroads themselves and the integrity of the rail, and then new tank car designs. I think the tank car designs are going to be phased in; I think we’ve factored all that into our guidance going forward.

Brian I might just comment in general, there is nothing that on the regulatory side that they’ve imposed that’s going to cause PAA any issues different from the rest of the industries. I would say in fact to some extent it may as these differentials fluctuate one of the positives about PAA is we’ve got both pipe and rail in many of these areas. So to the extent that the differentials tighten up and/or lead times on the rail become unacceptable then we probably are just going to see a little bit of a shift back to our pipelines which is different than if you just had rail or just had pipe in any given area. Brian Zarahn – Barclays Capital, Inc.: Thanks for the color.

Thank you, Brian.

Your next question comes from the line of Steven Sherowski with Goldman Sachs. Please go ahead, sir. Steve C. Sherowski – Goldman Sachs & Co.: Hi, good morning just trying to drill down a little bit on the revised segment guidance. I appreciate that we heard the Canadian exchange rate and also some asset shifting within the segments, but even if you take into account the $30 million of EBITDA loss from the Canadian exchange rate it still looks like the combined the facilities in transportation segment results forecast are a little bit lower than what you’d expected at the beginning of the year, is that really all just rail related or is there anything else going on there?

For the rest of the year or for the year in total? Steve C. Sherowski – Goldman Sachs & Co.: For the total year. For the full year.

Yes, so the natural gas deliverability issues in the first quarter did impacted it. We got a little bit in our processing segment where the gas stream coming from the Gulf Coast - from the East Coast down to some of our Gulf Coast processing facilities, the gas stream - these liquids are a little – aren’t quite as rich as we had seen earlier in the year and part of that’s just the dynamics of what’s going on with natural gas business in total. I think that’s the primary driver.

Steve, I’d say there is nothing individually significant as more fine-tuning as Harry mentioned I think the gas quality issues probably $7 million to $10 million - gas was being transported south on a line that we were then processing the gas because of the issue that happened in the Northeast on one of the company’s lines they had to change their gas flows around. So we lost some of the rich gas and picked up some of the not so rich gas. And then overall I think some of the delays although minor if we were counting on a pipeline, let’s say coming on in September it only comes on in November you’re losing half of what the increment was in that segment. What’s offsetting a little bit of that and we’ve kind of pointed to this in the past as we bring on new facilities and others by the way bring on the new facilities it takes away from the Supply and Logistics margin per barrel that we were making, because you obviously you got a more efficient way on its own. So what happens is there is a natural hedge in a lot of the - between our segments to the extent it takes longer to get a top-liner or a facility project, it pushes margin back on the Supply and Logistics, which is a benefit that’s only more of the value chain. Steve C. Sherowski – Goldman Sachs & Co.: Okay, I appreciate that. And switching gears some of the local newspapers have been reporting Diamond pipeline JV. I was just wondering if you could comment at all on that and where you are in that project.

Yes. We have taken a position in the past, we’ve got a lot of projects that we are working on that aren’t in our “approved” category and if we started down the line of responding to comments from whether the industry, or the papers on any one of those, we probably be on this call for quite a bit of time. So we’ve taken a position that we’re really only going to comment on projects that we have announced and approved and going forward and the one you mentioned is not one in that list. Steve C. Sherowski – Goldman Sachs & Co.: Okay, I appreciate that. And I guess a final question, we’ve been hearing a lot from the refineries about increasingly light barrels coming out of the Permian and potential need for additional condensate specific infrastructure. I was just wondering if you could provide any insight into that, and if you think there is any meaningful opportunities for plans on that front.

We do see the stream lightening, a lot of the new production is a lot lighter and honestly some of the way that WTI and WTS differential prices; WTI is used to get blended into - some WTS used to get blended into the WTI stream and that doesn’t occur. So that contributes to the lightening of the stream, so I think the – probably the beneficial - benefit to us we probably have a network of capacity in the Permian Basin and that’s not matched by anybody. So we think we all have opportunity, we think Cactus is probably going to likely move some of the lighter crudes down to the Gulf Coast through Cactus pipeline and some of the infrastructure going to Midland in East. So we think we are going to participate in our fair share of the opportunities resulting from the crude qualities.

Steve, if you go back and you look at not only last year’s presentation or Analyst meeting, but the one before that, we’ve been kind of forecasting that aggregate volumes in the U.S. and Canada are going to go up, but we’ve probably been more loud about anybody else that there is a significant portion of that, almost over 60% of it is going to be light, and in some cases very light. And so, I don’t think there is anything that’s a surprise to us as it is happening. We’re certainly well positioned to the extent that there is approval to export some of those real-life products either out of our Gulf Coast facilities or out of our East Coast facility, and we have -- because as Harry mentioned, we’ve got probably more of the value chain and we handle close to 4 million barrels a day in different qualities and varieties, so to the extent there is arbitrage opportunities embedded in there to help blend a cocktail crude for a refinery at their request or to segregate it to make sure that you don’t reduce the quality of the heavier stream that the refiner likes. We’ve got that ability to handle that. Steve C. Sherowski – Goldman Sachs & Co.: Okay, that’s it from me. Thank you.

Thank you, Steven.

Your next question comes from the line of Darren Horowitz. Please go ahead sir. Darren C. Horowitz – Raymond James & Associates, Inc.: Good morning guys.

Good morning Darren. Darren C. Horowitz – Raymond James & Associates, Inc.: Greg, I want to pick up on that where you just left off on the previous question with regard to kind of blending arbitrage opportunities, and within the context of trying to get a feel for what the S&L segment upside potential could possibly be in the back half of this year. As you guys see all those big Permian and Eagle Ford pipes ramping volumes into the Gulf Coast market, theoretically at the same time, the Seaway Twin and the Gulf Coast leg of Xcel volumes continue to build. It seems to be that there could be a lot more pronounced crude quality grade dislocations coming into play, and I’m wondering with the footprint that you have at St. James Mobil, how do you better leverage that connectivity? Could we see an R blow out between St. James and Patoka, or how do you think about logistical movements specifically in that area?

I’d probably respond in general as opposed to give you any real detailed specifics, but we’ve been pointing out for a while that the entire infrastructure is pretty taut, and it doesn’t take much in the way of an interruption in any one point to cause something to significantly move out. As Harry mentioned, WTI and WTS differentials used to average about 450. Now, they have kind of gotten to flat, if not flipped around, where WTS is more valuable from time and time than WTI. And then, you got the differentials on just a geographic basis between Midland and Cushing, WTI barrel, same quality barrel, and yet what used to be a $0.70 differential goes out now to $7 or $8. And again, part of that’s infrastructure related, part of it’s quality related, and some of it gets combined, so as Harry mentioned, we used to – the industry used to blend quite a bit of WTS with the lighter ends of the WTI to provide what the refiners used to want and value most, and now they value the heavier sour barrel more, because they're being inundated with light sweet barrels, and so when you un-blend so to speak, the WTS barrel to segregate it, you actually create more light sweet barrels in the whole process than the market used to have. So, I think you have got your finger on it. I think what we’ve seen so far already with the movements -- just here the other day, we were looking at light sweet barrel move from the Cushing to the Gulf Coast, net of the tariff they paid to get it there, it was selling for less in the Gulf Coast than it had been valued in Cushing. So all those things are going to happen from time to time, they're not predictable in terms of timing. We do think, and I think you’ve got your finger on in, and they are going to be recurring, and so we have taken the approach. We’re going to forecast what we know we think we can deliver on a baseline basis, and we’re certainly as well positioned, if not better, than almost anybody else in the industry to capture on those. If you look at -- if you’re trying to put a quantification of how big could big be, we’ve used $525 million to $550 million as kind of our baseline for supply and logistics as an aggregate, and yet over the last couple of years, we’ve been running closer to $800 million or slightly higher. And so, I think the order of magnitude on an annual basis is that we could probably or could potentially outperform in any given period by as much as $300 million over a year period, but it’s really a function of the details of which logistics debottleneck, which oversupply of light sweet crude or which refinery ran into a difficulty that nobody expected, I tis just hard for us looking forward to believe that everything works exactly the way it’s supposed to do and not to introduce a pun too much that the trains run on time and that there are no – there is no fog or bad weather, so I think PAA is well positioned to capture the upside. We just don’t feel comfortable trying to forecast, it looks like for the second quarter, and then if something doesn’t happen, we miss our numbers and the reality is we’ve got upside beyond our base level and our base level is a pretty attractive answer. Darren C. Horowitz – Raymond James & Associates, Inc.: Yes, I appreciate that. Do you think we get to a point and it could be a very, very short point in time when the Louisiana light sweet actually disconnects south of WTI?

That LNS was under WTI. Darren C. Horowitz – Raymond James & Associates, Inc.: Yes.

Yes, I mean, there is always a possibility. A lot of it has to do with, if something happens on the Gulf Coast, it doesn’t impact the Mid-Continent, but honestly we would probably think that there is some premium in the Gulf Coast over the Mid-Continent just because all the crude – all the light crude is being produced in the Mid-Continent. Darren C. Horowitz – Raymond James & Associates, Inc.: Right, right, last question either for you Harry or for Greg. I’m just thinking putting everything that we just discussed together and the difference that it could stand to alter or produce your net backs in the associated economics of bringing on those incremental barrels, how much of emphasis do you think that that puts on the Corpus Christi market? Because if I look at that market obviously what you are doing with Cactus into (inaudible) and Three Rivers and then the South. It would seem like you need not only more volumetric capacity, but more dock capacity, more ability to load barges, ships, whatever else. It would seem like that market is going to be so increasingly important that it could consume a significant amount of CapEx and possibly could create so much more opportunities to move product across the Gulf Coast. So am I thinking about that the right way Greg or --?

Yes, we think, we think so. We’ve got an expansion of our dock facility. Corpus Christi, we’re building more tankage down there. We think it’s going to be a hub to move crude from pipe to water and to better markets. Darren C. Horowitz – Raymond James & Associates, Inc.: How big could that be though, because I mean looking at loading capacity at 300,000 barrels a day and storage capacity of just over $4 million barrels a day, which seem like both of those two are going to get superseded pretty quick.

I think that’s a pretty good assessment. Trying to say how big is big, I mean right now I mean pipeline capacity in that area is in pretty good shape. The connectivity is not the best, but in terms of the aggregate bulk volume, clearly we are bringing in more barrels when we bring in Cactus, and as Harry mentioned, we are expanding our existing system there to accommodate it, we are expanding the dock. So, I think again, you are directionally on point with us. Trying to quantify that is pretty much of a challenge and quite honestly a little bit of a competitive issue, so we would like to tell everybody that what we are building is enough to satisfy everybody’s needs, you don’t need to buy anything to compete with us, but historically our competitors haven’t listened to us. Darren C. Horowitz – Raymond James & Associates, Inc.: Okay, we’ll leave it there, Greg, I appreciate it. Thank you.

Thank you.

And our next question comes from the line of Jeremy Tonet with JPMorgan. Please go ahead, sir. Jeremy B. Tonet – JPMorgan Securities LLC: Good morning.

Good morning, Jeremy Jeremy B. Tonet – JPMorgan Securities LLC: Just want to go back to the nat gas storage side for me, if we could, and I was wondering if you could provide a little bit more incremental color on what the deliverability issues were, and any steps that you might have taken to remedy that?

Sure, in general incurring costs to balance deliverability is something that not only us, but really every gas storage operator deals with. In this particular case, the severity and duration, really the cold weather combined with what I would say is less than optimal base gas management caused the cost to be higher than historical levels. We haven’t quantified it for some competitive reasons, but it was meaningful enough that we wanted to mention it. We have taken steps within our organization to do a couple of things. We’ve certainly reassessed a little bit, what’s true working capacity and what’s base gas capacity, and then we’ve changed the way that we’re really managing the base gas capacity because we think, Jeremy, we’ve transitioned or this winter showed us that we’re right at the endpoint of transitioning into a period of pure oversupply and production, and perhaps oversupply and storage to the combination of the test that was provided by the severe winter and then the increased demands we’re going to see for natural gas movements into the Gulf Coast area to meet LNG export needs and ultimately a lot of the petrochemicals plants we’ll be building there. So, we’ve taken a more conservative approach with respect to how we’re going to manage the base gas and so that’s both reflected in the first quarter operations, but also in – as Harry mentioned in our capital program. So we don’t expect at least within PAA to be a recurring issue if we have a repeat of what we just went through.

And basically what happens is, as you get less gas in your facilities, your deliverability goes down even though the gas is in storage there, and just what happens is you can never perfectly correlate or match your delivery contracts, commitments, with the physical capacities of the facilities, so there's always a little bit of a give-and-take in there.

And we typically have a customer mix where you’ve got some combination of traders along with some combination of utility customers that tend to draw very late in the season when you had severe winter and a very long period of extreme cold weather. Basically, all the customers showed up in concert and said we want as much gasoline and get as fast as we can, and I'm proud to say that we didn’t turn anybody away. We basically honored all of it. It wasn’t without some economic pain, but long-term we think that’s what builds good customer loyalty and relationships. Jeremy B. Tonet – JPMorgan Securities LLC: That’s a great lead into my next question. I was just wondering given that situation that you described where everyone was coming in for gas at the same time and some disruptions in the market there and very cold weather, what do you think that does for the value of nat gas storage going forward, especially with the low supply – low supply levels we have overall? Are you guys seeing favorable trends on that side?

Yes, I would say, generally we’ve been calling for it to be challenging or at least last year we were saying it’s going to be challenging for another two or three years. I think -- we think it probably accelerates the recovery, because all of a sudden, people appreciate the value of storage. It’s a little bit like if I can use that analogy of insurance rates, if you don’t have a hurricane or tornado for a long period of time, insurance becomes very, very competitive, and then all of a sudden you have an event, everybody readjusts rates and says there's risk in here that we did not anticipate. And I think that’s what this winter did, is sent a shot across the bow, all storage operators that look there is probably more challenges associated with the service you’re providing need to charge higher, so we think ultimately you’re going to see a lift in the rates. We think the increased demand that was going to happen, let’s say in 2015, 2016 associated with the commencement of LNG exports also combined with now what appears to be more shipments of gas to Mexico, and then the advent of the petrochemical plants probably accelerates the recognition that storage is going to be an important of that, and that means probably higher rates. And at some point in time, Jeremy the ability to build more volume to meet the increased demand loads in that deal, and this is a bit of a commercial on PAA -- I don’t think there is anybody that is well positioned to add storage at cheap rates at its facilities than we are at Pine Prairie. And we are about 50% on new build rates based upon what we’ve already got staged there, because we built it kind of like we did Cushing, designed to be added to. So, I think your question is right on point. We think it’s going to uplift the market and probably accelerate the recovery we thought perhaps was only going to be three years off, maybe much faster. Jeremy B. Tonet – JPMorgan Securities LLC: That’s very helpful, thank you.

Thank you.

And our next question comes from Brad Olson with TPH. Please go ahead sir. Brad R. Olsen – Tudor Pickering Holt & Co. Securities, Inc.: Hi, good morning guys.

Good morning, Brad. Brad R. Olsen – Tudor Pickering Holt & Co. Securities, Inc.: I was hoping that you could maybe walk us a little bit through some of the regulatory dynamics that you’re seeing around crude by rail on the west coast, and I guess the reason I’m asking is you have two major refiners who are saying they want to get out of the West Coast more or less entirely, and the economics of those facilities are highly dependent on whether or not you believe that you can expand that crude by rail unloading footprint on the West Coast and move some heavier Canadian crudes into that area. And so, do you believe it’s an area where it’s reasonable to think that you can grow beyond the Bakersfield facility or is it just too tough from a regulatory standpoint?

Well, I think Bakersfield is probably the best place to build the rail facility in California, because it’s not sitting in San Francisco or LA, and it has access to pipes going North and South. It just seems like it is going to be a struggle to develop rail and other locations. We like Bakersfield, we are setting it up, so it will have the ability to move light and heavy crude.

Yes, so we’ve initially -- our initial rates can be 70,000 barrels today.

Yes.

We designed it, Brad to be able to do larger volumes on that with regulatory permits. We just think it will be easier to get regulatory permits to build rail facilities in Bakersfield than it would be in LA and San Francisco. We do have some challenges on a regulatory standpoint. We’ve got pipeline capacity as Harry said going to LA and then some connectivity into San Francisco. We would like to expand and put back in the U.S. one of our pipelines that we have out there, and there you do run into regulatory delays of just a normal nature in California, so nothing though that I think is unusual in that regard. We just think ultimately, as Harry said, that there is probably going to be more appealing to see railcars coming to Bakersfield that it would be to LA or San Francisco. Brad R. Olsen – Tudor Pickering Holt & Co. Securities, Inc.: Got it. Great, I appreciate that color. Maybe jumping back to Jeremy’s line of questioning on the storage side, we're sitting here after probably the biggest withdrawal we’ve maybe seen in the last few decades, if not ever. I know you started to hear some utilities and LDCs on their conference calls start to say that they don’t want to find themselves in similarly undersupplied or at least tightly supplied situation like the one we saw this last winter. At the same time, you’re seeing Contango’s structure, which remains relatively subdued, and I guess if you could maybe walk through whether you believe there is enough potential demand from utilities and LDCs for longer-term contracts in storage facilities to bring the market back somewhat or are we really going to need to wait to see Contango’s structure reenter the market before we really see a true storage recovery?

I think we are probably as much baffled as you are that the market structure doesn’t reflect the sentiment that we think the physical assets suggest need to have to support it. I don’t think we are going to have to wait two years for that to show up. I think it’s possible we may see it as much this winter. I mean, there is some differences of opinion as to how much storage can be refilled. I think we are still fine-tuning our estimates, but for example, we think it’s conceivable that you might see a refill to 3.2 BCF to 3.3 BCF or maybe even higher than that, but it’s probably all going to be located in the Northeast, a big part of it, and that we may only be at levels that were 75% of what we were last year in the Gulf Coast and the West Coast, and that’s where some of the challenges came in because the winter was so widespread. So, ultimately we think passage of time and not a whole lot of time is going to basically reflect that right now. It’s still pretty cold up in the Northeast, and so in some cases, we are not seeing refill of some of the storage up there as fast as you might expect. You’re still seeing people trying to use gas that they normally would start filling back in the storage fill using it to heat houses. So we were in Calgary yesterday for what it was worth, it was 28 degrees up there.

We were not as well equipped with our coats as we needed to be. Brad R. Olsen – Tudor Pickering Holt & Co. Securities, Inc.: That’s great color, and we echo your comment that the structure in the market is confusing to us as well. Just one last question, and this is more probably on the modeling side, but as we think about supply and logistics, maybe just qualitatively walking us through how much of that was the result of capturing Permian volumes just because we’ve seen some of your competitors with similar exposure not show the same strong results, but I realize that you do also have some NGL links up in Canada around your processing facilities, and those assets obviously have had a pretty good winter as well. So if you wouldn’t mind, maybe, breaking out the outperformance broadly between differential capture and NGL link?

We keep that locked away in vault with the KFC secret sauce and the Coca Cola recipe.

I think Brad, one of the things obviously that we have, as we have a large part of the value chain not only across the U.S., but in the Canada, as you mentioned. So, what we did want to comment on, I think, we basically said very strong performance in crude oil and NGL really throughout all three segments, so across the board offset by some of the challenges of the weather associated not only with natural gas, but also with crude oil. And so, I think the benefit of what happens is -- no matter what happens, where the disruptions are anywhere in the U.S. and Canada, PAA is generally well positioned toward a minimum benefit to some extent. So, we historically never try to break that down into any kind of pattern so that our peers could figure out what they need to do to catch up with us, and we just certainly keep it that way.

I’ll mention just some general comments. If you look at first quarter this year compared to first quarter last year, you certainly had Permian Basin differentials that were better than historical differentials from somebody that has transportation capacity to move crude out, but not as wide as the differentials for last year. I’d also point out that probably a large difference this year was the LOS differential was not nearly as wide as it has been historically. So one of the areas where first quarter last year benefitted for us and probably some others was the ability to move crude from a Mid-Continent pricing going into a Gulf Coast pricing point. With the pipelines opening up into the Gulf Coast, you just didn’t have that differential this year like you did last year. Brad R. Olsen – Tudor Pickering Holt & Co. Securities, Inc.: Great, that’s great color guys, thanks a lot.

Thank you.

Your next question comes from Ethan Bellamy with Baird. Please go ahead sir. Ethan H. Bellamy – Robert W. Baird & Co., Inc.: Hi, guys good morning, Greg, really the same question I had last quarter which is with crude export ban and Jones Act shipping limitations and significant supply increases on the Gulf Coast, is there any way we can avoid an overall price correction of the crude oil market?

I’m trying to remember exactly how I answered it last time, so one of the things we think is that the excess supply is going to be – it probably isn’t here today, but in the future as you continue to drill at these -- develop at these rates, it’s going to be the lighter end of the barrel that’s going to struggle to find a home, the 55 gravity plus. It is good to be the part that struggles the most, does that makes sense. So, I don’t know, the whole complex comes out because of it, but certainly there could be some, as I’ve said earlier some quality differentials that exist for the latter end of the crude stream.

And to be fair, I mean you’re seeing some of that already in either the postings of the contracts that are in the field, where as Harry said, some of the 55 degree gravity is already probably bearing a fairly big discount to some producers at the wellhead, and it will necessarily show up in a posting that you can follow, but it shows up ultimately in the economics of that producer’s crude, so that composition becomes pretty important. Producers are trying to do what they can to blend as much in the field as they can to try and make sure that they mitigate that, I think it was asked last time about but whether we will make a prediction about crude oil exports, and we refrained from doing that, we’d still do it. But you’re seeing continued discussions. And I think the EI just recently said they are embarking upon an information gathering effort now to try and get their arms around issues that the industry will help them, and they can get there pretty quickly. But there is just a significant amount of very light product that continues to increase month-to-month-to-month and it’s starting sliding up the entire strain of reasons we talked about earlier, but at some point in time, you’ll run into a bit of a wall there where you’re going to have to distinguish between the really high quality crude that the refiners want, and want used to be thought of as high quality crude that the refiners currently don’t want. Ethan H. Bellamy – Robert W. Baird & Co., Inc.: Would you care to weigh in on Harold Hamm’s prediction for $2 million out of the Williston? Is that feasible based on what you’re seeing?

It depends on what timeframe you are in, certainly resource wise in Permian, Williston, and Eagle Ford. Our numbers -- we only go out to 2017 on our forecast. I think some of the numbers you’re hearing are probably out to 2020.

Even further

Yes, and even further, and when we extend out our forecast Ethan, the resources there to get to those numbers whether the world dynamics are enough to support the demand for that at a price level that it would take to clear those barrels is the challenge. If you just look at what the U.S. and Canada for crude and NGLs are supposed to increase between 2013 and 2014, it exceeds the aggregate projection for world demand for petroleum

Growth in demand.

Growth in demand, I am sorry, I mean 1.3 million, 1.4 million barrels a day of supply in the US and Canada over 1.2 million barrel a day projection for world petroleum demand growth. So, the Saudi Arabia cut, does Iran not come back on, et cetera, I mean it’s a complex answer. What we’ve tried to -- the message we would like to convey not on behalf of the industry, but on behalf of PAA and its unit holders is there is no company out there better prepared to react to those kinds of volatile markets than PAA both from an operational asset business model and also from a balance sheet. Ethan H. Bellamy – Robert W. Baird & Co., Inc.: Okay. And then my last question speaking of that balance sheet, it looks pristine the way the bonds are trading. It doesn’t look like there are any obvious places to mine rates. It looks like you’ve got some debt coming up due in 2015, and the $700 million that you did in April, that’s basically a home mortgage of $700 million at 4.7%. Is there any interest rate or duration you can mine here in the near-term or should we just expect you to continue to layer on deals like we saw in April?

I think from our view is we’ve got significant capital program; we do get some notes that will mature next year, so we’ve got pretty well our fixed rate debt issued for the year, but we will be looking at opportunistically trying to make sure we protect the balance sheet and our DCF through that going forward, but this actually funded a lot of capital that we are spending between now and the end of the year, the transaction we just did.

It was just -- issuing 30 years versus 10 years, you’ve given up obviously some rate. It was just hard to turn down 30-year money at 4.7, and your reference to the home mortgage is probably not a bad answer. Ethan H. Bellamy – Robert W. Baird & Co., Inc.: All right, thank you gentlemen. I appreciate it.

And our next question comes from Mark Reichman with Simmons & Company. Please go ahead sir. Mark L. Reichman – Simmons & Co. International: Greg, do you think there is a need for a dedicated condensate line to transport condensate from the Permian to the Gulf Coast or will splitters in the Permian be the answer?. I think you’ve mentioned blending opportunities, just curious as to your views on the best solution for handling these higher API gravity crudes that are emanating from the Permian?

Hi Mark, this is Harry. I think in the short-term, I think everyone is pedaling as fast faster I can to get the infrastructure just to move crude out of the Permian to get it to the points where you can move out of the Permian basin. So in the short-term, I don’t think there is going to be a solution to segregate the condensate. Longer-term, there could be some solutions. I don’t know that there is going to be a dedicated pipeline for it. I mean you can batch a condensate with a (inaudible in the same pipe. so you might see some stream segregations that don’t exist today. We sort of think Cactus is the most logical because it brings it down to an environment where there is light crude and light handling capacity in the Gulf Coast and splitters being developed in that area. So, we think Cactus can be a pretty elegant solution for some of the lighter ends.

Yeah, I would also point out, Mark, I think it depends, in the history – the industry has done this historically is we tend to build, and then at some point of time we catch up with everything we overbuild, and if production ever starts to turn and you see a rationalization of pipelines, for example, I think in the Eagle Ford today, I think we are more than pipeline sufficient from a standpoint of the aggregate pipeline capacity versus aggregate production, and geographically, there are some gaps in there, so interconnectivity would help balance that out and at some point in time, you may see whether it’s five years or 10 years from now, you may some lands, joint ventures, whatever, where people basically segregate streams by combining pipeline operations to have parallel efforts. But as Harry mentioned right now, I think as an industry, everybody right now is just trying to keep up with the volumetric aggregate and letting the differentials that kind of fallout where they may, and then at some point of time, there will be a fine tuning effort that comes into there. Mark L. Reichman – Simmons & Co. International: That’s helpful. And then another question on the quarter’s rail volumes. I mean, when you look at the quarter, it was about an 86,000 barrel per day Delta between actual and the prior guidance, and I think the new guidance for the full year, there is about a 50,000 barrel per day Delta, and I was just wondering you mentioned that some of those volumes are finding their way on to your pipelines, and so how much of that difference would you attribute to moving to pipeline versus the other explanations like congestion? And then, if you could just provide an update on terminals under development and/or consideration?

Terminals under development? Mark L. Reichman – Simmons & Co. International: Well if you could – is there any change in service dates for Bakersfield or some of these other -- I think you had mentioned that you are considering on the last conference call, perhaps a facility in Canada. Opportunity in Canada?

We are pursuing a facility in Canada, and that is sort of 2015 in service date. Bakersfield, still looking at up fourth quarter in service date. We had actually earlier hoped that it might be a little sooner, but it will be fourth quarter, and at St. James, we are looking at… Mark L. Reichman – Simmons & Co. International: For example, Carr Colorado I think you were looking 35,000 barrels per day of loading capacity that still on track, for what month or what quarter?

I cannot remember when Carr is coming out. It's this year. I can’t tell you exactly when. Mark L. Reichman – Simmons & Co. International: Bakersfield. I had down second half ’14 for Carr Colorado, and that was 35,000 barrels per day, and then of course the Bakersfield in the second half. I was just wondering if there was any update in terms of kind of narrowing the time frame fourth quarter for Bakersfield?

I would say just like on Carr Colorado --. Mark L. Reichman – Simmons & Co. International: I guess that was really an incremental 20,000 barrels per day.

Right, because it already moves about 15,000 barrels a day, it was like fourth quarter for Carr as well. Mark L. Reichman – Simmons & Co. International: Okay, fourth quarter, and then also just on the differences in the rail volumes.

Yes, what we are seeing is some of it’s going to our pipes in North Dakota and some of it is not necessarily – like if we see lower volumes coming into St. James, we are seeing more volumes go onto our Canadian pipes. So might not exactly be the same barrel, but in total those are the same differentials that are driving crude to half of rail on the pipe, if that make sense. Mark L. Reichman – Simmons & Co. International: So like for example for this quarter, the expectation was I think 315,000 barrels per day and it came in at 229. So how much of that difference was just -- how much of that volume found its way onto the pipes.

Most of difference in the first quarter was weather-related I think if you look for the remaining part of the year, that is the part where we are looking at with the shift between pipe and… Mark L. Reichman – Simmons & Co. International: So the full year guidance is 280 versus the previous 330 some of that’s going to be accounted for about the difference in the first quarter, but what you are saying is for the last three quarters most of that is just you moving on the pipe.

Yes. So I think it’s about 35 a day for kind of the back nine months.

Yes, I haven’t Mark listen to all the EMP producers on the conference call, so my guess is you probably heard some concerns about they probably missed some production numbers they’ve had lower volumes. Granted if they have lower volumes we have lower volumes. Mark L. Reichman – Simmons & Co. International: Right, right. Okay, I really appreciate that, that’s helpful.

Thanks Mark.

And our next question comes from Elvira Scotto with RBC Capital Markets. Please go ahead. Elvira Scotto – RBC Capital Markets LLC: Hi, good morning, I just wanted to follow-up on the condensate question, so in your internal forecast for condensate production over the next several years, do you think that it’s really a matter of finding a home for those condensate moving them to where they need to go or taking them up to Canada et cetera or do you think we’re going to be in a supply glut and maybe we need to build additional splitters.

I’m going to kick it over to John Rutherford because he is the one that’s neck deep in this.

Yes, we actually or if you could kind of go up to end of 2017 it feels like you still don’t have a home for 400,000 or 500,000 barrels a day of condensates. Okay and we define a condensate as 45 degrees or higher even with the splitters that we think are likely to be get built which is roughly 500,000 barrels a day inside the fence and some refineries and standalone. So, we still think you have excess condensate to find a home for and delays and key stone and potentially and some of the other Canadian pipes getting permit probably exacerbates that issue, because we don’t have indigenous North American demand for the day you went up in Canada. And so we actually do think there is a meaningful imbalance.

And that the way kind of the Carr just act against that answer in direction of the answer is there is couple of place in Canada that appear to be very promising that actually is not in our forecast right now that would add additional condensate volumes where we might think where the natural home - what they need to do they maybe self sufficient. And so that would make John’s number about 100,000 barrels a day higher potentially. So the answer is right now there is not a solution that’s obvious. And so whether that’s more splitters or whether that’s some quasi-approval of sanction exports or whatever it’s just it’s going to require some solution, or you have to volumetrically slow things down. Elvira Scotto – RBC Capital Markets LLC: Guessing.

When you look at the diluent demand in Canada the plant C5 material is preferential for diluent over to the field condensate. So a lot of the diluent demand in Canada is going to be trued by C5 material coming at plants.

And then secondarily coming out of Northern part of U.S. – is not just going to be Canadian C5 plus, but it is going to be effectively NGL moving up their preferentially. Wellhead condensate coming out the Eagle Ford feels like it’s going to be back of the bus if you will. So that’s where the probs going to be

So definitely in 2017 our material balance doesn’t balance. Elvira Scotto – RBC Capital Markets LLC: Right.

It feels like it gets worse, if you delay Keystone et cetera. Feels like it gets worse if you have more NGL production. . Elvira Scotto – RBC Capital Markets LLC: Got it, okay. And then a condensate splitter is that something you guys – would you guys consider building splitters?

We are all over all parts of the value chain, but I kind of got to go back to, we really don't talk about any kind of unapproved projects that we have got out there. Elvira Scotto – RBC Capital Markets LLC: Got you. That’s fair enough. And then just switching over on natural gas. So it sounds like the views have improved on gas storage from Greg’s comments earlier. I mean is this something now that you are thinking potentially expanding gas storage either organically or through M&A and then just as a follow up. Have you seen that sort of M&A market for gas storage loosen up a little bit.

We really haven’t seen much in the way of it loosen up, there is certainly a few isolated areas out there, but they’re not the most attractive. I would say we’ve maintained all along, we have the most economic expansion potential for salt caverns in the Gulf Coast. We think of anybody just because of the way our assets are positioned we really just kind of raising the potential out there that it appears there is a bit of a sea change in attitudes about when the recovery is going to occur. We actually were pretty adamant, we thought it might be as much as three years away. And just because of the severe tests we just went through and a change in attitudes and postures about people that may have been complacent to wait until two or three years from now to start worrying about getting storage have kind of accelerated because we have a repeat next year of the winter we had this last year. And we don’t see storage in the gulf coast get back to the levels it was last year. And if we think it maybe hard to get back to 75% over last year. It would not be - issue to be utility there and run out of gas. Elvira Scotto – RBC Capital Markets LLC: Right, so at what point do you think -- when do you think rates start increasing?

Like about two weeks ago. Elvira Scotto – RBC Capital Markets LLC: Okay, great. Thanks a lot, that’s all I have.

Thank you.

Your last question comes from Becca Followill with U.S. Capital Advisors. Please go ahead. Becca Followill – USCA Securities LLC: Greg, I think you may have just answered my question. But have just gone through storage re-contracting season. Can you tell us more specifically what you saw through this season?

(indiscernible) and all I didn’t just kind of comment in general, we don’t want to get into too many specifics but in general we can tell you the attitudes…

Yes Becca, I would say the, you are seeing a lot more interest from logistics in user type customers. And certainly I think comment was made earlier about the concern of being short supply. I think which saw on Northeast in particular where the wells aren’t quite as productive when it gets as cold as it did, little bit different in Hurricane in the Gulf, but much the same affect. So I think there is a rethinking of all that and the type of customers we are seeing as well as the rates are certainly ahead of what we anticipated, I’ll leave it at that. Becca Followill – USCA Securities LLC: And just finally you don’t want to get out specific, just can you follow-up also on with all the slower vessels and all the pipelines, how that’s anticipate and how that’s affecting your outlook on a longer-term usage storage in the Gulf Coast.

Yes, I think you’re starting to see the transition between where your supplied basin let’s call it Marcellus-Utica is switching in your markets going to be the Gulf Coast given where the LNG exports all the demand you see down there including traditional power generation, all of that building up in particular. Greg mentioned a little bit and what we’re seeing a lot of interest and focuses is that Pine Prairie because of where it’s located its connectivity particularly the pipelines that have announced reversal of Williams Transco from station 65 goes right to Pine Prairie aiming at that Lake Charles market you’re seeing nice/Columbia with their reversal. The good thing and where we see all those pipes go right to Pine Prairie, so we couldn’t be happy about our capabilities not only in terms of connectivity, but in expansion capabilities. We like our position there and the one thing we saw this winter though is even though those reversal had started as soon as they got cold, they flip right back up until you debottleneck the Northeast, you’re still going to have that back in forth which is good it’s going to be very volatile I think near-term until you saw some of those infrastructure issues. Ultimately, it’s going to come down here, but you got a little pipe to build and infrastructure to put in up in the Northeast.

And back in just in the near-term I mean I made the comment early we think it maybe challenging to fill storage in the Gulf Coast area. In order to get back the same volume that we were last year, we need to inject about 40% more volume in the Gulf Coast that’s about 2.4 Bcf a day and production in the Gulf Coast state is down about 2.4 Bcf a day from last year, so with that access to some of those Northeast Gas supplies, is just really challenging, if we have a similar summer et cetera that we did last year to see how they are going to get back up. So I think it’s going to reinforce the fact that you need more volume metric storage in the Gulf Coast, and you need better connectivity to be able to fill it up. Becca Followill – USCA Securities LLC: Just one follow-up to that Greg does the storage have the capability of injecting to an incremental 2.4 Bcf a day?

Proportionately we do, we think that there are some, facilities that actually that if they had that much gas put back and could have trouble, when it comes back, it comes late in the year, there could be problems that they start ratably doing it in May – you should be able to do it, to get back to where you were, but I mean the aggregate, and I think Brad also mentioned earlier, the aggregate drill down was over 3 TCF, we never had drill down ever the big and at most we’ve ever put back in storage, I think is a nation, is probably in the 24, 25 range. So by definition we’ve trouble getting back there, assuming we didn’t have the geographic dislocations and its bit of a challenge. So we think ultimately it does very well, good for storage, we just don’t know if that’s 12 months for now or 24, but we think its sooner than the 36 we thought previously. Becca Followill – USCA Securities LLC: Right. Thank you, guys.

Thank you.

And there are no further questions in queue.

Thank you, everybody for the participation. We look forward to updating you in August and for those who will attending the Analyst Day in June, we will look forward to welcome you there. Thank you.

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