Plains GP Holdings, L.P. (PAGP) 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. [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, Twanda. 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 will refer to Plains All American Pipeline by its New York Stock Exchange ticker symbol of PAA. 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 safe harbor precepts that encourage companies to provide this type of information, we direct you to the 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 reconciliation section of our website reconciles certain non-GAAP financial measures to the most directly comparable GAAP financial measures and provides a table of selected items that impact the 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 the control 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 distribution 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, at the market close, 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 to 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 last year's first quarter results for adjusted EBITDA, implied DCF and distribution coverage and adjusted net income for 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 3 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 costs on 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 marked 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 partnerships 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 the Slide 4, PAA has increased its distribution in 38 out 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 assumption 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'll review our first quarter operating results compared to midpoint of our guidance, the operational assumptions used to generate our second quarter guidance, and I'll 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 guidance. However, I'll note that the volume shortfall was largely attributable to pipelines where the capacity is leased to third parties and variances 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 will defer approximately $7 million of operating expenses for the second quarter of this year. Adjusted segment profit for our -- 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 activity and slightly lower third-party volumes. Also, as Greg mentioned previously, we incurred unanticipated costs to manage deliverability requirements for our natural gas storage business. Adjustment segment profit for the 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 reductions in our lease gathering volumes. Adjusted segment profit per barrel was $1.85 or $0.40 above the midpoint of our guidance. Over performance was primarily due to better-than-expected crude oil differentials, higher-than-forecasted margins related to NGL sales, partially offset by cost to meet deliverability requirements at our gas storage facilities during extended periods of cold weather this winter. We believe that we have addressed the availability issues going forward by purchasing additional base gas. And although this has negative impact on our results for the quarter, we believe that there were other facilities that experienced deliverability issues, and in general, this should bode well for natural gas storage rates going forward. Let me now move onto 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 Midcontinent 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 in our Canadian pipeline 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 is a slight benefit to Transportation offset by a slight decrease in Facilities. We expect adjusted segment profit per barrel 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 segment -- average capacity of 122 million barrels of oil equivalent, a slight increase from first quarter volumes as we expect a recovery from the weather-related impacts of our rail volumes. I'll note that we continue to expect slightly lower third-party volumes than 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 costs 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. For the Supply and Logistics segment, we expect volumes to average 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 lines 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 a 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 on Slide 8. And I'll note that the in-service date of some of the projects in the Permian have slipped a bit but nothing that we consider meaningful. I'll provide a status update on few of these projects now. We continue to add projects in our most active areas, 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 capacity from Southeast New 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 pipelines servicing Gulf Coast markets. In addition to debottlenecking the infrastructure in the Permian basin, we are also investing approximately $530 million in 2 projects to increase takeaway capacity, of which $415 million is expected to be incurred in 2014. The projects include our Cactus Pipeline, which is the $440 million project to build a 310-mile, 20-inch pipeline from McCamey to Gardendale, and a $90 million investment to build on 80-mile, 20-inch pipeline for Midland to Colorado City. In the Eagle Ford, we recently agreed to loop the entire segment of our joint venture pipeline from Gardendale to Three Rivers. This is approximately a $75 million investment net to our 50% interest and will expand capacity on this segment of the line to 470,000 barrels per day primarily to accommodate increase 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 mid2015. In Canada, we're advancing plans for a significant expansion of our facilities at Fort Sask. Phase 1 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 compensate storage. We are also increasing brine handling 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'll turn it over to Al.

Thanks, Harry. During my portion of the call, I will review our financing activities, capitalization 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 a $700 million offering of 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 3.2x. 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 comparisons in 2014 as market conditions during the first half of 2013 were extremely favorable for our assets and business models. 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, DCF and distribution coverage. Additionally, as Harry mentioned, some operating expenses were deferred from the first quarter to the latter 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 our -- 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, multiyear 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 sized acquisitions. As a result, absent significant acquisition activity, we do not expect to execute an 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 performance for PAA. Furthermore, looking forward, we believe PAA is well positioned for continued growth in our fundamental business activities and distributions. The 3 primary factors underpinning that outlook include the fact -- number one, we have a proven business model strategically located in flexible asset base and experienced management team that have demonstrated the ability to deliver solid results in almost any market conditions. Second, the 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 mention 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're excited about our prospects for the future, and we look forward to updating you on our activities at our analyst meeting and on our next call in August. Twanda, we're now ready to open the call up for questions.

[Operator Instructions] Within the line of Brian Zarahn with Barclays.

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 of the headwind of the Canadian dollar impacts the segment?

I'll start with rail. And so we expect rail volumes to be down a little bit than we have originally forecasted. The -- a number of reasons. We're seeing some of the crude move 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. So some of it is moving the pipe and we're seeing a little bit of congestion on the rails. We sort of moderated our expectation 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 3 or 4 different impacts. We still like the rail business, it's very complementary to our pipes and they sort of offset each other.

Yes. And then on the -- I think you mentioned, Brian, the gas storage capacity, we tweaked our numbers and little bit there to reflect the fact that we'll 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. 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's about $30 million impact on a 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 5 basis points movement, it's probably for the balance of the year, probably call it $20 million impact. Is that about right, Al?

Yes, it is.

Does that help?

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. Gas storage is really a first quarter issue not a balance of year.

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 independent storage facility so we moved. There's a little bit of a tweak there.

Okay. And then some topic of rail. Any general comments on the crude by rail environment given the price differentials and all the new safety regulations out of Canada and the pending regulations in the U.S.?

I mean I think you got the likelihood that you could see a little slower turnaround times on rail movement. So that 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 impacting the rail roads 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 factor that all into our guidance going forward.

Brian, I might just comment in general. There's 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 -- at least 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 that we probably just are going to see a little bit of shift back to our pipelines, which is different than if you just had rail or just had pipe in any given area.

Our next question comes from the line of Steven Sherowski with Goldman Sachs.

Just trying to drill down a little bit on the revised segment guidance. I mean I appreciate the weaker Canadian exchange rate and also some assets 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 and Transportation segment results forecast are a little bit lower than what you had 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?

For the total year. For the full year.

Yes. So you have the natural gas deliverability issues in the first quarter that 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 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's nothing individually significant its more fine-tuning. As Harry mentioned, I think the gas quality issue is probably $7 million to $10 million of -- this was -- gas was being transported south on a line that we were then processing the gas because of issues that happened in the Northeast on one of the big 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're -- if we were counting on a pipeline, let's say, coming on in September and 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 kind of pointed to this in the past, as we bring on new facilities, and others by the way bring in new facilities, it takes away from the supply and logistics margin per barrel that we were making because obviously you've got a more efficient way out of town. So what happens is there's a natural hedge in a lot of our -- between our segments to the extent it takes longer to get a pipeline or a facility project up. It pushes margin back on the supply and logistics, which is a benefit by selling more of the value chain.

Okay. And switching gears. Some of the local newspapers have been reporting a Diamond pipeline JV. I was wondering if you could comment at all on that and where you are in that project?

We've taken position in the past. We've got a lot of projects that we're working on that aren't in our "approved' category. And if we started down the line of responding to comments from whether the industry, the papers on any one of those, we'd probably be on this call for quite a bit of time. So we've taken the 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.

Okay. And I guess, a final question. We've been hearing a lot from the refiners about increasingly light barrels come 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's any meaningful opportunities for plans on that front.

We do see the stream lighting. A lot of the new production is a lot lighter and, honestly, some of the way the WTI and WTS differential prices. WTI used to get blended into -- some WTS use 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 -- the benefit to us is we probably have a network of capacity in the Permian Basin that's not matched by anybody. So we think we will have opportunity. We think Cactus is probably going to likely move some of the lighter crudes down to the Gulf Coast through the Cactus pipeline and some of the infrastructure going to Midland in East. So we think we're going to participate our fair share of the opportunities resulting from the crude qualities.

Yes. I'd say, Steve, if you go back and you look at not only last year's presentation, our analyst meeting with 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's a significant portion of that, almost over 60% of it is going to be light, in some cases, very light. And so I don't think there's anything that's a surprise to us that's happening. We're certainly well positioned to the extent that there's 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 of different quantities and varieties. So to the extent there's arbitrage opportunities embedded in there to help blend the cocktail crude for a refinery at their request or to segregate it to make sure that you don't reduce the quantity of the heavier stream that the refiner likes. We've got that ability to handle that.

Your next question comes from the line of Darren Horowitz.

Greg, I want to pick up on that, where you just left off on that 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 that 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'll probably respond in general as opposed to give you any real detail 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, WTS differentials used to average about 4 50. And now they've kind of gotten to flat, if not, flipped around to where WTS is more valuable from time to time than WTI. And then you've got the differentials on just a geographic basis between Midland and Cushing, WTI barrel, same quantity barrel, and yet what used to be a $0.70 differential goes out now to $7 or $8. And again, part of that is infrastructure-related, part of it is 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 end of the WTI to provide what the refiners used to want and value the 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've got your finger on it. I think what we've seen so far already with the movements just hearing the other day, we were looking at a light sweet barrel move from Cushing to the Gulf Coast, net of the tariff they paid to get it there 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 out there going to be recurring. And so we've 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 your trying to put a quantification of how big can 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 bottleneck, which oversupply of light sweet crude or which refinery ran into a difficulty that nobody expected. It's 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, is we've got upside beyond our base level and our base is a pretty attractive answer.

Yes. Do you think we get to a point, and it could be a very, very short point in time, when Louisiana light sweet actually disconnects south of WTI?

That LNS was under WTI?

Yes.

Yes. I mean it's always a possibility. A lot of it has to do with if something happens on the Gulf Coast, it doesn't impact the Midcontinent. But honestly, we probably think that there is some premium in the Gulf Coast over the Midcontinent just because all the crude is -- all the light crude is being produce in the Midcontinent.

Right, right. Last question and -- 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 an emphasis do you think that, that puts on the Corpus Christi market? Because if I look at that market, obviously, what you're doing with Cactus into Tilton[indiscernible] and Three Rivers and then South, it would seem like you need not only more volumetric capacity but more dock capacity, more ability to load barges, ships, wherever 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?

Yes, we think so. We've got an expansion of our dock facility at 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.

How big could that be, though? Because I mean, looking at loading capacity at 300,000 barrels a day, storage capacity of just over 4 million barrels a day which seem like both of those 2 are going to get superseded pretty quick.

I think that's a pretty good assessment.

Yes.

Trying to say how big is big. I mean right now I mean, pipeline capacity that area is in pretty good shape. The connectivity is not the best in terms of just aggregate bulk volume. Clearly, we're bringing in more barrels when we bring in Cactus. As Harry mentioned, we're expanding our existing system there to accommodate it. We're expanding the dock. So I think again, you're directionally on point with us trying to quantify that is a 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're building is enough to satisfy everybody's needs. You don't need to buy anything to compete with us. So -- but that historically, our competitors haven't listened to us.

And our next question comes from the line of Jeremy Tonet with JPMorgan.

Just want to go back to the net gas storage side for a minute, if we could, and was wondering if you could provide a little bit more incremental color on what deliverability issues were and any steps that you might have taken to remedy that?

Sure. Yes, in general, incurring costs to balance deliverability is something that not only us but really every gas storage operators deals with. In this particular case, the severity and the duration really of the cold weather combined with what I say less than optimal base gas management costs, the cost to be higher than historical levels, it's -- 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 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 transition or this winter showed us that we're right at the endpoint of transitioning into a period of pure oversupply in production and perhaps oversupply and storage to the combination of the tests 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 petrochemical plants are being built in 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 operation but also in, as Harry mentioned, our capital programs. 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 you can just -- can never perfectly correlate or match your delivery contract commitments with the physical capacities of the facilities. There's always a little bit of give and take in there.

And we typically have 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 whether, basically all customers showed up in concert. And so we want as much gas that we can 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.

That's a great lead into my next question. I was just wondering given that situation that you described where everyone was coming for gas at the same time and some disruptions in the market there, very cold weather, what do you think that does for the value of net 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 was saying, Jeremy, we've been calling for it to be challenging, at least, last year we were saying it's going to be challenging for another 2 or 3 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 the analogy of insurance rates. If you don't have a hurricane or a tornado for a long period, of time insurance because very, very competitive. And then all of a sudden, you have an event, everybody readjust rates and say, by God, there's risk in here that we didn't anticipate. And I think that's what this winter did, is sent a shot across the bow, all storage operators that look, there's probably more challenges associated with the service you're providing. You need to charge higher. So we think, ultimate, you're going to see a lift in the rates. We think the increased demand that was going to happen, let's say, in '15, '16 associated with the commencement of LNG exports also combined with now what appears to be more shipments of gas to Mexico and then the event of the petrochemical plant probably accelerates the recognition that storage is going to part 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 build and this is a bit of commercial on PAA, I don't think there's anybody that's as well positioned to add storage at cheap rates at its facility than we are at Pine Prairie. I mean we're 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 design 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 3 years off, maybe much faster.

Next question coming from Brad Olsen with TPH.

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 2 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 the 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 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 L.A. and it has access to pipes going North and South. It just seems like it's going to a struggle to develop rail and other locations. We like Bakersfield. We're setting it up so it will have the ability to move and light heavy crude.

Yes. So we've initially -- our initial rates can be 70,000 barrels a day?

Yes.

And we designed it, Brad, to be able to do larger volumes in 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 L.A. and San Francisco. We do have some challenges on the regulatory standpoint. We've got pipeline capacity, as Harry said, going into L.A. and then some connectivity into San Francisco. We would like to expand and put back into use one of our pipelines tat 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 is probably going to be more appealing to see rail cars coming into Bakersfield than it would be to L.A. or San Francisco.

Got it. Great. 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. And now you started to hear some utilities and LDCs on their conference calls start to say that they don't want to find themselves in a similarly undersupplied or at least tightly supplied situation like the 1 we saw this last winter. Yet 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's enough potential demand from utilities and LDCs for longer-term contracts and 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're 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're going to have to wait 2 years for that the show up. I think it's possible we may see it as much this winter. I mean there's some differences of opinion as to how much storage can be refilled. I think we're still fine-tuning our estimates. But for example, we think it's conceivable that you might see a refill to 3.2 or 3.3 Bcf and maybe even higher than that, but it's probably all going to be located in the Northeast a big part of it and that may only be at levels that we're 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're not seeing refill of some of the storage up there fast as you might expect. You're still seeing people trying to use gas that they normally wouldn't put -- start filling back in the storage fill still using it to heat houses. So we were in Calgary yesterday, for what it's worth, and it was 28 degrees up there. So weren't as well equipped with our coats as we needed to be so.

That's great color, and yes, I think we are -- we echo your comments that the structure in the market is confusing on 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 length 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 length?

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

I think, Brad, one of the things obviously, that we have is we have a large part of the value chain not only across the U.S. but into 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 3 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 happened is no matter what happens, where the disruptions are anywhere in the U.S. and Canada, PAA's generally well positioned to the minimum benefit to some extent. So we've, historically, never tried to break that down into any kind of patterns so that our peers could figure out what they need to do to catch up with us and we just assume to 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 some of the transportation capacity to move crude out but not as wide as differentials were 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 had been historically. So one of the areas where first quarter last year benefited for us and probably some others was the ability to move crude into -- from a Midcontinent price -- pricing point into a Gulf Coast pricing point and just with the pipeline opening up into the Gulf Coast, you just didn't have that differential this year like you did last year.

Your next question comes from Ethan Bellamy with Baird.

Really 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 a overall price correction on the crude oil market?

I'm trying to remember exactly how I answered it last time. 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 have -- struggle to find a home, 55 gravity plus is going to be the part that struggled the most, if that makes sense. So I don't know that the whole complex comes down because of it but certainly there could be some, as I said earlier, some quality differentials that exist for the lighter end of the crude stream.

And to be fair, I mean, you're seeing some of that already in either the postings of contracts that are in the field where, as Harry said, some of the 55-degree gravities already probably bearing a fairly big discount to some producers at the wellhead. And it won't 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. And 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 I was asked last time about whether we would make a prediction about crude oil exports and we refrained from doing that, we'd still do it. But you are seeing continued discussions and I think the EI just recently said they're embarking upon an information-gathering effort now to try and get their arms around issues that are -- the industry will help them make them get there pretty quickly. But there's 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 stream for reasons we talked about earlier. But at some point in time, you'll run into a bit of wall there where you're going to have to distinguish between the really high-quality crude that the refiners want and the -- what used to be thought of as high-quality crude that the refiners currently don't want.

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 time frame you're in certainly resource-wise in Permian, Williston and Eagle Ford, our numbers -- we only go out to 2017 and our forecast. I think some of the numbers you're hearing are probably out to 2020.

Even further.

And yes, 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 '13 and '14, it exceeds the aggregate projection for world demand for petroleum.

Growth in demand.

Growth in demand, I'm sorry. So I mean 1.3 million or 1.4 million barrels a day of supply in the U.S. and Canada over 1.2 million barrels 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 like to convey not on behalf of the industry but on behalf of PAA and its unit holders, is there's no company out there better prepared to react to those kind of volatile markets than PAA, both from an operational asset business model and also from a balance sheet.

Okay. And then my last question. Speaking of the 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 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?

We had, I think, from our view is we've got significant capital program. We do have 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 is actually funded a lot of capital that we're spending between now and the end of the year, the transaction we just did.

It was just -- issuing 30 years versus 10 years you're giving up, obviously, some rate. Its just hard to turn down 30-year money at 4.7% and your reference to the home mortgage probably not a bad answer.

And our next question comes from Mark Reichman with Simmons & Company .

Greg, do you think there's 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 mentioned blending opportunity. Just curious as to your views on the best solution for handling these higher API gravity crudes that are emanating from the Permian?

Mark, this is Harry. I think in the short term, I think everyone's pedaling as fast as they can to get the infrastructure just to move crude out of the Permian to get to points where you can move it out of the Permian basin. So in the short term, I don't think there's going to be a solution to segregate the condensates. Longer term, there could be some solutions. I don't know that's there's going to be a dedicated pipeline for it. I mean you can batch a condensate with the guy [indiscernible] stream 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's 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.

Yes. I'll also point out, Mark, I think depends in the history -- the industry has done this historically is we tend to build and then we -- at some point in time, we catch up with everything, we overbuild and if production ever starts to turn, then you see a rationalization of pipelines. For example, I think in the Eagle Ford today, I think we're more than pipeline sufficient from a standpoint of the aggregate pipeline capacity versus the aggregate production. Now geographically, there are some gaps there, so interconnectivity would help balance that out. And at some point in time, you may see whether it's 5 years or 10 years, you may see some lines, joint ventures, whatever, where people basically segregate streams by combining pipeline operations to have parallel efforts. But as Harry mentioned, I mean, I think, as an industry, everybody's just right now just trying to keep up with the volumetric aggregate and letting the differentials that kind of fall out where they may, and then at some point in time, there will be a fine-tuning effort that comes into that.

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's about a 50,000-barrel per day delta. And I was just wondering, you mentioned that some of those volumes are finding their way onto your pipeline. 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?

Term loans under development?

Well, like if you could -- is there any change in in-service dates for Bakersfield or some of these other -- I think you had mentioned that you're considering, on the last conference call, perhaps a facility in Canada. Opportunity in Canada.

We're pursuing a facility in Canada and that's sort of a 2015 in-service date. Bakersfield, still looking at a fourth quarter in-service date. We had actually earlier hoped that it might be a little sooner, but it's -- it will be fourth quarter. And at St. James, we're looking at...

So for example, Carr, Colorado, I think you are looking at 35,000 barrels per day of loading capacity. That's still on track. What month or what quarter?

I can't remember when Carr is coming out. It's this year. I can tell you exactly when.

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'd say just like on Carr, Colorado...

I guess that was really an incremental 20,000 barrels per day, right?

Right. Because it already moves about 15,000 barrels a day, it was like fourth quarter for Carr as well.

Okay, so fourth quarter. And then also just on the differences in the rail volumes?

Yes. What we're seeing is some of it is 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're seeing more volumes go on to our Canadian pipes. So it might not exactly be the same barrel, but in total, those are the same differentials that are driving crude to -- off of rail and on to pipe, if that make sense.

So like, for example, for this quarter, the expectation was, I think, 315,000 barrels per day and it came in at 2 29. So how much of that difference was just -- how much of that volume found its way onto the pipes?

Most the difference in the first quarter was weather-related. I think if you look for the remaining part of the year, that's the part where we're looking at was a shift between pipe and...

Full year guidance is 2 80 versus the previous 3 30. Some of that is going to be accounted for by the difference in the first quarter, but what you're saying is for the last 3 quarters, most of that is just moving on the pipe.

Yes. I think it's about 35 a day for kind of the back 9 months.

Yes, I haven't, Mark, listened to all the E&P producers on their conference calls. 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.

And our next question comes from Elvira Scotto with RBC Capital Markets.

I just wanted to follow up on the condensate question. So in your internal sort of forecast for condensate production over the next several years, do you think that it's really a matter of finding a home for those condensates, 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's the one that's neck deep in this.

Yes. We actually or if you could kind of go out to the end of 2017, it feels like you still don't have a home for 4 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 in Keystone and potentially 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. So we actually do think there's a meaningful imbalance.

And the way the, Elvira, the kind of the Carr just act against that answer in direction of that answer is there's a couple of plays 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 we're the natural home for what they need diluent, they may be self-sufficient. And so that would make John's number, I think, about 100,000 barrels a day higher potentially. So the answer is right now there's not a solution that's obvious. And so whether that's more splitters or whether that's some quasi-approval of sanctioned exports or whatever, it's just -- it's going to require some solution or you're going to have to volumetrically slow things down.

If I just, when you look at the diluent demand in Canada, plant C5 material is preferential for diluent over sort of field condensate. So a lot of the diluent demand in Canada is going to be to be chewed up by C5 material coming up at plants.

And then secondarily coming out of the northern part of U.S., it's not just going to be Canadian C5 plus, but it's going to be effectively NGLs moving up there preferentially -- I'm sorry, wellhead condensate coming out of the Eagle Ford feels like it's going to be the back of the bus, if you will. So that's where the problem is going to be.

So definitely, in 2017, our material balance doesn't balance.

It feels like it gets worse with -- if you delay Keystone, et cetera. It feels like it gets worse if you have more NGL production.

Got it. Okay. And then condensates splitter. Is that something you guys would -- would you guys consider building splitters?

We're all over all parts of the value chain, but I kind of got to go back to our earlier comment, we really don't really talk about any kind of unapproved projects that we've got out there.

Got you, got you. 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're 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 are 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're really just kind of raising the potential out there that it appears there's 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 3 years away and just because of the severe test we just went through and a change in attitudes and postures about people may have been complacent to wait until 2 or 3 years from now to start worrying about gaining storage have kind of accelerated that 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 may be hard to get back to 75% of where we were last year, it would not be fun issue to be a utility and run out of gas.

Right. So at what point do you think -- when do you think rates start increasing?

Like about 2 weeks ago.

And our last question comes from Becca Followill with U.S. Capital Advisors.

I think you may have just answered my question, but you've just gone through historic recontracting season. Can you tell us more specifically what you saw through this season?

[indiscernible] is here and I'll let him just kind of comment in general. We don't want to get in too many specifics but in general, we can tell you the attitudes.

Yes, Becca, I'll say the -- you've seen a lot more interest from logistics in user-type customers. And certainly, I think a comment was made earlier about the concern of being short supply. I think what you saw in Northeast, in particular the wells aren't as quite as productive when it gets as cold as it did. A little bit different than a hurricane in the Gulf but much the same effect. So I think there's a rethinking of all that and the type of customers we're seeing as well as the rates are certainly ahead of what we anticipated. I'll leave it at that.

And just -- I know you don't want to give out specifics, just can you follow-up also on with all the flow reversals on all the pipelines, how that's anticipate -- or how that's affecting your outlook on a longer-term usage storage in the Gulf Coast?

Yes, I think you're -- you're going to -- you're starting to see the transition between your supplied basin, let's call that Marcellus-Utica is switching and your market is going to be the Gulf Coast given where the LNG exports, all the demand you see down there, including traditional power generation. All that's building up. In particular, Greg mentioned a little bit and where we're seeing a lot of interest and focus is that Pine Prairie because of where it's located, its connectivity. Particularly the lines -- the pipelines that have announced reversal of Williams-Transco from Station 65 goes right through Pine Prairie aiming at that Lake Charles market. You're seeing nice source/Columbia with their reversals. The good thing and where we sit, all those pipes go right through Pine Prairie. So we couldn't be happier 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 reversals had started as soon as they got cold, they slip right back up until you debottleneck the Northeast. You're still going to have that back and forth, which is good. It's going to be very volatile, I think, near term until you saw some of those infrastructures issues. Ultimately it's going to come down here but you got a little pipe to build an infrastructure to put in up in the Northeast.

And Becca, just in the near term, I mean, I made a comment earlier, we think it may be challenging to fill storage in the Gulf Coast area. In order to get back to 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 without 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're going to get back up. So I think it's going to reinforce the fact that you need more volumetric storage in the Gulf Coast and you need better connectivity to be able to fill it up.

Just one follow-up to that, Greg. Do the facilities have the capability of injecting an incremental 2.4 Bcf a day?

Proportionately, we do. We think that there are some facilities that actually if they have that much gas put back at them could have trouble depending on when it comes back. If it comes late in the year, there could be problems. If 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 it earlier, the aggregate drawdown was over 3 Tcf. We never had a drawdown ever that big. And most we've ever put back in storage, I think, as a nation it's probably in the 2 4, 2 5 range. So by definition, we'd have trouble getting back there assuming we didn't have the geographic dislocations and it's just -- it's a bit of a challenge. So we think, ultimately, it does bare well good for storage. We just don't know if that's 12 months from now or 24 but we think it's sooner than the 36 we thought previously.

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 be 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.