Plains All American Pipeline LP (PAA) 2014 Q1 法說會逐字稿

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, Tawanda. 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, and 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 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 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 on the call are Harry Pefanis, President and COO; and Al Swanson, Executive Vice President and CFO. In addition to these gentlemen and myself, we have several other members of our Management team present and available for the question-and-answer session. With that, I'll turn the call over to Greg.

Thanks, Ryan. Good morning, and welcome to all. Yesterday after 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 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 last year's 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 costs 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 marked the 49th consecutive quarter that PAA's 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's 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 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 (technical difficulty) 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'll 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'll provide an update to our 2014 capital program.

I'm showing 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 with a capacity of leasing 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 -- or the timing of some of our integrity management projects, which will defer approximately $7 million of operating expenses 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, our crude oil rail activities, 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.

Adjusted 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 one of our guidance. Overperformance was primarily due to better-than-expected crude oil differentials, higher-than-forecasted margins related to NGL sales, but partially offset by costs to meet deliverability requirements at our gas storage facilities during the extended periods of cold weather this winter.

We believe that we've addressed the deliverability 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 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 the third parties.

The forecast also assumes approximately 20,000 barrels a day of lower volumes at our Canadian pipeline, with 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 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 policies are more heavily weighted toward the second quarter.

For our Facilities segment, we expect an average segment -- an average capacity of 122 million barrels of oil equivalent, a slight increase from first-quarter volumes, as we expect the 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 did 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 our Supply and Logistics segment, we expect volumes to average approximately at 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, 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 that the in-service dates on some of the projects in the Permian have slipped a bit, but nothing that we consider meaningful.

I'll 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 billion 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 Palo 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 at the Permian Basin by providing additional capacity to move crude oil to Crane and McCamey, where we have connections with pipeline servicing Gulf Coast markets.

In addition to debottlenecking the infrastructure in the Permian basin, we're also investing approximately $530 million in two projects to increase takeaway capacity, of which $415 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 an 80-mile, 20-inch pipeline from 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 [moving the] line 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'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 we'll convert approximately 2.2 million barrels of existing NGL storage capacity to condensate storage.

We are also increasing brine handling capacity by 2.5 million barrels so we can fully utilize our cabin 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 programs. 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 3.2 times.

Slide 10 summarizes information regarding our short-term debt, hedged inventory, and linefill 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 in adjusted EBITDA between segments in order to incorporate the project timing and volume ramp-up adjustments Harry discussed for certain of our Transportation and Facilities 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 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 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, 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, 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 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 assets 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 at our analyst meeting and on our next call in August. Tawanda, we're now ready to open the call up for questions.

(Operator Instructions)

Brian Zarahn, Barclays.

Good morning. On full-year guidance, can you elaborate a bit on your expectations for rail volumes and then the gas storage capacity? And also, how much of the headwind of the Canadian dollar impacts the segment?

Sure, I'll start with rail. We expected rail lines to be down a little bit than we originally had forecasted. The -- a number of reasons.

We're seeing some of the crude move to pipe, which is being a little [masked], because we're also expecting some seasonal decline in pipeline volumes, potentially during the flood season in Canada. So some of it's moving the pipe. And we're seeing a little bit of congestion on the rails. We've moderated our expectations for the movement.

And we're seeing a little less volume coming into the Gulf Coast, more of it trying to go to the East and West Coast. But we are a little barge-limited on the East Coast. So it's a combination of three or four different impacts. We still like the rail business, we think it's very complementary to our pipes. They offset each other.

Yes, and then on the -- I think you mentioned, Brian, the gas storage capacity. We tweaked our numbers a little bit there to reflect the fact that we ran into the headwinds in the first quarter and we've got some refill issues throughout the year. But we just really -- it's minor tweaks. It's very minor in the big picture.

And then the last issue was on FX. Again, Al's summary that it's 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. Is that about right, Al?

It is.

Does that help?

It does. And then the changing guidance for the segment. Would be more gas storage- or rail-related?

More rail-related on the segment. Gas storage was 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 facilities. So we moved -- there's a little bit of a tweak there.

So on the 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 US?

I think you have got the likelihood that you could see a little slower turnaround times on rail movements. So that's 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 railroads themselves and the integrity of the rail, and then new tank car designs. The tank car designs aren't going to be phased in. We've factored all that into our guidance going forward.

Yes, Brian, I might just comment in general. There's nothing on the regulatory side that they have 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 the 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 rails become unacceptable, that we'd probably just go see a little bit of a shift back to that through our pipelines, which is different than if you just had rail or just had pipe in any given area.

Yes. Thanks for the color.

Thank you, Brian.

Stephen Sherowski, Goldman Sachs.

Hi, good morning. Just trying to drill down a little bit on the revised segment guidance. I appreciate the weaker -- or the 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 Facilities and Transportation segment results or forecasts 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, you had the natural gas deliverability issues in the first quarter, that impacted it. We've 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 -- the liquids aren't quite as rich as we had seen earlier in the year.

And part of that is just the dynamics of what is going on with the natural gas business in total. I think that's the primary drivers.

Steve, I'd say there's nothing individually significant. It's more fine tuning. As Harry mentioned, I think the gas quality issue is probably $7 million to $10 million of --

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 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, some of the delays, although minor, 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 it a little bit of that, and we've pointed to this in the past, is we bring on new facilities -- and others, by the way, bring on 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.

What happens is, there's a natural hedge 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 of us owning more of the value chain.

Okay, no. I appreciate that. And switching gears, some of the local newspapers have been reporting a Diamond Pipeline JV. I was just wondering if you could comment at all on that, and where you are in that project?

Well, we've taken a position in the past -- we've got a lot of projects that we're working on that aren't in our quote -- approved category. And if we started down the line of responding to comments from -- whether it's 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 in going forward, and the one you mentioned is not one in that list.

Okay. No, I can appreciate that. And on a final question, we've been hearing a lot from the refiners about increasingly light barrels coming out of the Permian and the 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 lightening. A lot of the new production is a lot lighter, and honestly, some of the way the WTI and WTS differential prices. WTS used to get blended into -- some WTS used to get blended into WTI's stream, and that doesn't occur, so that contributes to the lightening of the stream.

Probably 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 opportunities.

We think Cactus is probably going to likely lose some of the lighter crudes down to the Gulf Coast through the Cactus Pipeline and some the infrastructure going to Midland and East. We think we're going to participate in our fair share of the opportunities resulting from improved qualities.

Steve, if you go back and you look at not only last year's presentation at our Analyst Meeting, but the one before that, we've been forecasting that aggregate volumes in the US and Canada are going to go up. But we've probably been more loud about it than anybody else that there's a significant portion of that, almost over 60% of it, is going to be light, and in some cases, very light. 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 differing qualities and varieties. To the extent there's arbitrage opportunities embedded in there to help blend a cocktail crude for a refiner at their request, or to segregate it to make sure that you don't reduce the quality of a heavier stream that the refiner likes, we've got that ability to handle that.

Okay, that's it for me. Thank you.

Darren Horowitz.

Good morning, guys. Greg, I want to pick up on that where you just left off on that previous question with regard to blending arbitrage opportunities. And within the context of trying to get a feel for what the S&L segment upside potential could possibly be 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 XL 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, Mobile, 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, WTS differentials used to average about $4.50. Now they've kind of kind 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 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, 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 that heavier sour barrel more, because they're being inundated with light sweet barrels. When you unblend, 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.

I think you've got your finger on it. What we've seen so far already with the movements -- just here 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, it was selling for less in the Gulf Coast than it had been valued in Cushing.

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 it, they're going to be recurring. 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 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.

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 is no fog or bad weather.

I think PAA's well-positioned to capture the upside. We just don't feel comfortable trying to forecast it, let's say, 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's a pretty attractive answer.

Yes. I appreciate that. 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 LLS was under WTI?

Yes.

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 Mid-Continent. But honestly, we probably think that there is some premium in the Gulf Coast over the Mid-Continent, just because all the light crude is being produced in the Mid-Continent.

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, produce or net backs and 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 [Tild] and Three Rivers and then south, it would seem that 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.

Am I thinking about that the right way, Greg?

Yes, we think so. We've got an expansion of our dock facility. Corpus Christi, we're pulling 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 looking at loading capacity at 300,000 barrels a day, a storage capacity of just over 4 million barrels a day, it would seem like both of those two are going to get superseded pretty quick.

I think that's a pretty good assessment, yes. Trying to say how big is big. Right now, pipeline capacity in that area is in pretty good shape. The connectivity's not the best in terms of aggregate bulk volume.

Clearly, we're bringing in more barrels. We'll be bringing in Cactus. And as Harry mentioned, we're expanding our existing system there to accommodate it. We're expanding the docks.

I think, again, you're 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.

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. But historically, our competitors haven't listened to us.

Okay. We'll leave it there, Greg. I appreciate it. Thank you.

Jeremy Tonet, JPMorgan.

Good morning. Just want to go back to the nat gas storage side for a minute, if we could. I 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. 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 the duration, really, of the cold weather, combined with what I'd 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 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 transitioned, or this winter showed us that we're right at the hinge point of transitioning into a period of pure oversupply in production. And perhaps, oversupply in 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 petrochemical plants we'll be building there.

We've taken a more conservative approach with respect to how we're going to manage the base gas. That's both reflected in the first-quarter operations, but also in, as Harry mentioned, our capital program. 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. You just can never perfectly correlate or match your delivery contracts, commitments, with the physical capacities of the facility. So there's always a little bit of 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 of the customers showed up in concert and said, we want as much gas as we can get, as fast as we can.

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-in to 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, very cold weather.

What do you think that does for the value of nat gas storage going forward, especially with the low supply levels we have overall? Are you guys seeing favorable trends on that side?

I would say in general, we've been calling for it to be challenging, or at least last year, we were saying it was going to be challenging for another two or three years. 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 becomes very competitive. Then all of a sudden you have an event, and everybody readjusts rates, and says, by God, there's risk in here that we didn't anticipate.

I think that's what this winter did, was it sent a shot across the bow of all storage operators that -- look, there's probably more challenges associated with the service you're providing. You need to charge higher. So I 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 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.

That builds -- and this is a bit of a commercial on PAA -- I don't think there's anybody that's as well-positioned to add storage at cheap rates at its facilities than we are at Pine Prairie. We're about 50% of new build rates, based upon what we've already got staged there. Because we built it like we did Cushing, designed to be added to.

I think your question's 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.

That's very helpful. Thank you.

Brad Olsen, TPH.

Hey, good morning, guys. I was hoping that you could walk us a little bit through some of the regulatory dynamics that you're seeing around crude by rail on the West Coast.

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 the crude by rail unloading footprint on the West Coast and move some heavier Canadian crudes into that area.

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 to tough from a regulatory standpoint?

I think Bakersfield is probably the best place to build a 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's going to be a struggle to develop rail in other locations.

We like Bakersfield. We're setting it up so it will have the ability to move light and heavy crude.

Our initial rate's going to be 70,000 barrels a day.

Yes.

And we've designed it, Brad, to be able to do larger volumes than that with regulatory permits. We just think it'll 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 into LA and then some connectivity into San Francisco. We would like to expand and put back into use one of our pipelines that we have out there.

There, you do run into regulatory delays of just a normal nature in California. Nothing, though, that I think is unusual in that regard. We just think ultimately, as Harry said, that it's probably going to be more appealing to see railcars come into Bakersfield than it would be to LA or San Francisco.

Got it. Great. I appreciate that color.

Jumping back to Jeremy's line of questioning on the storage side. We're sitting here after probably the biggest withdrawal we've seen in the last few decades, if not ever. And now you've 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 under-supplied, or least tightly supplied, situation like the one we saw this last winter.

Yet, at the same time, you're seeing Contango structure, which remains relatively subdued. If you could 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 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 two years for that to show up. I think it's possible we may see it as much as this winter.

There's some differences of opinion on as to how much storage can be refilled. We're still fine-tuning our estimates. 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 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.

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. In some cases, we're 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 into storage still using it to heat houses. We were in Calgary yesterday. For what it's worth, it was 28 degrees up there, so no worries. We weren't as well equipped with our coats as we needed to be.

That's great color, and, yes, I think we echo your comments 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, 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 link up in Canada around your processing facilities. And those assets, obviously, have had a pretty good winter, as well. If you wouldn't mind breaking out the out-performance broadly between differential capture and NGL link?

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 US, but into Canada, as you mentioned.

What we did want to comment on, I think we basically said a 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.

The benefit of what happens is, no matter what happens, where the disruptions are, anywhere in the US and Canada, PAA is generally well-positioned to, at a minimum, benefit to some extent. We've historically never tried to break that down into any kind of pattern so that our peers could figure out what they need to do to catch up us, and we'd just as soon keep it that way.

I'll mention some general comments. If you look at first quarter of 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 were last year.

I'd also point out that probably a large difference this year was the LLS differential was not nearly as wide as it had been historically. One of the areas where first quarter of last year benefited 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.

Great. That's great color, guys. Thanks a lot.

Ethan Bellamy, Baird.

Hello guys. Good morning. Greg, really same question I had last quarter, which is with the 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 of the crude oil market?

I'm trying to remember exactly how I answered it last time. (laughter)

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 is going to be the part that struggles the most.

Did that make sense? I don't know the whole complex comes down because of it, but certainly there could be some -- I said earlier, some quality differentials that exist for the lighter end of the crude stream.

And to be fair, you're seeing some of that already in either the postings or 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.

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. Producers are trying to do what they can to blend as much in the field is as they can to try and make sure that they mitigate that.

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. You are seeing continued discussions.

And I think the EIA just recently said they're embarking upon an information-gathering effort now to try and get their arms around issues that -- the industry will help them. They can 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 a wall there where you're going to have to distinguish between the really high-quality crude that the refiners want, and what used to be thought of as high-quality crude that the refiners currently don't want.

And 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 on our forecast. I think some of the numbers you're hearing are probably out to 2020.

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 US 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'm sorry. So it's 1.3 or 1.4 million barrels a day of supply over against the -- in the US and Canada, over a 1.2 million barrel-a-day projection for world petroleum demand growth.

So does Saudi Arabia cut, does Iran not come back on, et cetera? It's a complex answer. We've tried to -- the message we'd 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 my last question, speaking of the balance sheet, it looks pristine. The way the bonds are trading, it doesn't look like there 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 got some notes that will mature next year. 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 has 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. It was just hard to turn down 30-year money at 4.7%, and your reference to a home mortgage is probably not a bad answer.

All right. Thank you, gentlemen. Appreciate it.

Mark Reichman, Simmons and Company.

This is for 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'd 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?

Hey, Mark. This is Harry. I think in the short term -- I think everyone's peddling as fast as they can to get the infrastructure just to move crude out of the Permian to get it to points where you can move it out of the Permian Basin.

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 there's going to be a dedicated pipeline for it. You can batch a condensate with a WTI stream in the same pipe, so you might see some stream segregations that don't exist today.

We 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 would be a pretty elegant solution for some of the lighter ends.

Yes, I would also point out, Mark, yes, I think it depends. The industry's done this historically is -- we tend to build, and then at some point in time, we catch up with everything and we overbuild. And if production ever starts to turn, then you see a rationalization of pipelines.

For example, 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's some gaps in 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 from now -- 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 right now, I think as an industry, everybody's right now just trying to keep up with the volumetric aggregate and letting the differentials fall out where they may. And then at some point in time, there'll be a fine-tuning effort that comes into that.

That's helpful. Then another question on the quarter's rail volumes. 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.

I was just wondering, you'd mentioned that some of those volumes are finding their way onto your pipeline. 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?

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

We are pursuing a facility in Canada. And that's a 2015 in-service date.

Bakersfield, still looking at fourth-quarter in-service date. We'd actually earlier had hoped that it might be a little sooner. But it'll be fourth quarter. And at St. James, we're looking at --

For example, Carr, Colorado, I think you were 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's coming out. It's this year. I couldn't tell you exactly when.

Bakersfield. I had down second half 2014 for Carr, Colorado and that was 35,000 barrels per day. And then, of course, the Bakersfield, the second half. And I was just wondering if there was any update in terms of narrowing the time frame?

Fourth quarter for Bakersfield.

Okay.

I'll tell you, just a second. Carr, Colorado -- September?

I guess that was in it really an incremental 20,000 barrels per day.

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

Okay. So that's fourth quarter. Then also, just on the differences in the rail volumes.

Yes. What we're seeing is, some of it's going to our pipes in North Dakota. And some of it is, not necessarily -- if we see lower volumes coming into St. James, we're seeing more volumes go onto 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 onto pipe, if that makes sense.

For example, for this quarter, the expectation was 315,000 barrels per day, and it came in at 229,000. So how much of that difference was -- how much of that volume found its way onto the pipes?

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

Full-year guidance says 280,000 versus the previous 330,000. Some of that's going to be accounted for by the difference in the first quarter. What you're saying is for the last three quarters, most of that is just you moving on the pipe?

Yes. I think it is about 35,000 a day for the back nine months.

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

Right. I really appreciate that. That's helpful.

Elvira Scotto, RBC Capital Markets.

Hi. Good morning. I just wanted to follow up on the condensate question.

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 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 -- if you could go out to the end of 2017, it feels like you still don't have a home for 400,000 or 500,000 barrels a day of condensates. And we define a condensate as 45 degrees or higher. Even with the splitters that we think are likely to get built, which is roughly 500,000 barrels a day inside the fence in some refineries and standalone.

We still think you have excess condensates 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 diluent up in Canada. We actually do think there is a meaningful imbalance.

And the way the cards are stacked against that answer -- in direction of that answer is, there's a couple 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 for diluent, they may be self-sufficient.

That would make John's number about 100,000 barrels a day higher, potentially. The answer is, right now, there's not a solution that's obvious. So whether that's more splitters, or whether that's some quasi-approval of sanctioned exports, or whatever, it's going to require some solution, or you're going to have to volumetrically slow things down.

(multiple speakers) When you look at the diluent demand in Canada, plant C5 material is preferential for diluent over field condensate. So all lot of the diluent demand in Canada is going to be chewed up by C5 material coming out of plants.

And then secondarily, coming out of the northern part of US. It's not just going to be Canadian C5-plus, but it's going to be effectively NGLs moving up there preferentially. Wellhead condensate coming out of the Eagle Ford, it feels like it's going to be the back of the bus, if you will. That's where the problem's going to be.

Definitely, in 2017, our material balance doesn't balance.

Right.

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

Got it. Okay. And then a condensate splitter, is that something you guys -- would you guys consider building splitters?

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

Got you. Fair enough.

And then just switching over on natural gas. It sounds like the views have improved on gas storage from Greg's comments earlier. Is this something now that you thinking potentially expanding gas storage, either organically or through M&A? And then, just as a follow-up, have you seen that M&A market for gas storage loosen up a little bit?

We really have not seen much in the way of loosening up. There's 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 the way our assets are positioned. We're really just raising the potential out there that it appears there's a bit of a sea change in attitudes about when the recovery's going to occur.

We actually were pretty adamant. We thought it might be as much as three years away, 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 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 we think it may be hard to get back to 75% of where we were last year. It would not be a fun issue to be a utility that run out of gas.

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

I think about two weeks ago.

(laughter) Okay. Great. Thanks a lot. That's all I had.

Becca Followill, US Capital Advisors.

Greg, I think you may have just answered my question, but with you've just gone through storage recontracting season, can you tell us more specifically what you saw through this season?

Dean Liollio's here, and I'll let him 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'll say you're seeing a lot more interest from logistics end-user type customers. And certainly, I think a comment was made earlier about the concern of being short supply.

What you saw in the Northeast, in particular, the wells aren't 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.

I think there is 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. And I'll leave it at that.

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

Yes. I think you're starting to see the transition between where your supply base and, let's call that Marcellus Utica, is switching, and your market's 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's building up.

In particular, Greg mentioned it a little bit, and where we're seeing a lot of interest and focus is at Pine Prairie because of where it's located, its connectivity. Particularly the lines, the pipelines that have announced reversal --Williams Transco from Station 65, goes right through Pine Prairie, aiming at that Lake Charles market. You're seeing a NiSource/Columbia with their reversals.

The good thing in where we sit, all those pipes go right through Pine Prairie. We couldn't be happier about our capabilities, not only in terms of connectivity, but in expansion capabilities. We like our position there.

The one thing we saw this winter though, is even though those reversals had started as soon as it got cold, they flip 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 solve some of those infrastructure issues. Ultimately, it's going to come down here, but got a little pipe to build an infrastructure to put in up in the Northeast.

And Becca, just in the near term, I made the 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 yet production the Gulf Coast states is down about 2.4 Bcf a day from last year.

Without access to some of those Northeast gas supplies, it's 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. 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.

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

Proportionately, we do. We think that there are some facilities, Becca -- actually, if they had that much gas put back at them, could have trouble.

Depending on when it comes, Becca. If it comes late in the year, there could be problems. If they start rateably doing it in May, you should be able to do it to get back to where you were. But the aggregate, and I think Brad also mentioned it earlier, the aggregate draw down was over 3 Tcf.

We've never had a draw down ever that big. The most we've put back in storage, I think, as a nation is probably in that 2.4, 2.5 range. By definition, we'd had trouble getting back there, assuming we didn't have these geographic dislocations. It's a bit of a challenge.

We think ultimately it does bear 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.

Great. Thank you, guys.

And there are no further questions in queue.

Thank everybody for their participation. We look forward to updating you in August, and for those that will be attending the Analyst Day in June, we will look forward to welcoming 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.