Plains GP Holdings LP (PAGP) 2016 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the PAA and PAGP first-quarter 2016 results.

(Operator Instructions)

As reminder, this conference is being recorded.

I would now like to turn the conference over to Ryan Smith, Director of Investor Relations. Please go ahead.

Thanks, Linda.

Good morning and welcome to Plains All American Pipeline's first-quarter 2016 earnings conference call. The slide presentation for today's call can be found within the investor relations and news and events section of our website at www.plainsallamerican.com. During today's call we will provide forward-looking comments on PAA's outlook. Important factors which could cause actual results to differ materially are included in our latest filings with the SEC.

Today's presentation will also include references to non-GAAP financial measures such as adjusted EBITDA. A reconciliation of these non-GAAP financial measures to the most comparable GAAP financial measures can be found under the investor relations and financial information section of our website.

Today's presentation will also include selected financial information for Plains GP Holdings or PAGP. We do not intend to cover PAGP's results separately from PAA's. Instead we have included schedules in the appendix to the slide presentation for today's call that contain PAGP's specific information.

Today's call will be chaired by Greg Armstrong, Chairman and CEO. Also participating in the call are Harry Pefanis, President; Willie Chiang, Chief Operating Officer, US; and Al Swanson, Chief Financial Officer. In addition to these gentlemen and myself, we have several other members of our senior management team present and available for the Q&A portion of today's call.

With that, I'll turn the call over to Greg.

Thanks, Ryan. Good morning and thank you all for joining today's call.

Yesterday evening, PAA reported adjusted EBITDA of $621 million, which was approximately $50 million, or 9%, above the midpoint of our first-quarter guidance. Harry will provide additional details later in the call, but as shown on slide 3, our first-quarter results reflect the combination of performance above expectations, the inclusion of the deficiency amounts for ship-or-pay obligations that have been billed or collected, and some timing related items expected to reverse later in the year. Excluding the timing-related items and the ship-or-pay deficiencies, PAA's adjusted results came in roughly $16 million, or 3%, over the midpoint of our guidance.

As noted in yesterday's press release and guidance 8-K, we also lowered the full-year 2016 midpoint of our adjusted EBITDA guidance by approximately 4% to $2.175 billion, due to the lower-than-anticipated producer activity levels and the resulting impact on our oil production forecast for the lower 48 onshore volumes over the balance of 2016, as well as related impacts of ongoing competition for the marginal barrel. PAA's guidance assumptions regarding producer activity levels and associated production forecasts were generated in the fourth quarter of 2015 when oil averaged $42.50 per barrel and producers were generally discussing 2016 budgets at plus or minus 30% below 2015 actual expenditures. You may recall PAA's 2016 crude oil price assumptions called for an average of $35 a barrel and $45 a barrel in the first and second quarters, respectively, and an average price of around $57 a barrel for the second half of 2016.

Using that price forecast and back-solving for activity levels and capital expenditures in balance with E&P companies' cash flow, this equated to a crude oil rig count of approximately 500 rigs, which was approximately 36% below 2015's average rig count. We are now one-third of the way through 2016 and thus far PAA's oil price assumptions have been directionally in line with actual prices. First-quarter prices fluctuated significantly, ranging from $42 a barrel to $26 a barrel, but averaged approximately $34 a barrel, which is pretty close to our assumption of $35. Oil prices for the second quarter to date have averaged approximately $42 per barrel and closed yesterday around $44 a barrel as compared to our assumption of $45.

Importantly, however, the critical driver for PAA's operating and financial performance is lower 48 onshore crude oil production volumes, which are driven by producer's drilling and completion activities. Unfortunately onshore crude oil drilling activity is lagging meaningfully below our 2016 forecast assumptions and we anticipate that completions and production volumes will fall off in the latter half of 2016.

With that observation in mind, I wanted to share some important details that provide context for our 2016 guidance adjustment. First is illustrated on slide 4. Based on PAA's fundamental analysis of wells in each of the oil basins, we estimate that approximately 55% of US onshore lower 48 production at year end 2015 was derived from wells completed during 2014 and 2015. Decline rates vary by basin, but the average annual decline for the majority of horizontal oil wells treated with high-volume hydraulic fracturing in shale resource plays generally ranges from 65% to 80% in the first year following initial production, and 30% to 40% in the second year. As a result, these significant production declines require high activity levels to maintain or increase production in these regions.

Following the steep drop in oil prices and gas prices in late January, early February, and the increased burden of high leverage, many key onshore oil producers further reduced their 2016 spending plans to roughly 40% to 50% of 2015 levels. As a result of these various pressures, for the first quarter of 2016, the lower 48 rig count averaged approximately 440 rigs as compared to our assumption of 500 rigs, a 12% variance. Importantly, however the average oil rig count was the result of a steady decline throughout the quarter, averaging 526 rigs in January, 426 rigs in February and 363 rigs in March. The average oil rig count for April so far is about 331, which is about 34% below the level upon which we based our 2016 forecast.

In certain regions it is clear that drilling times and recoveries are improving, but not sufficient to offset a 34% decrease in rig count relative to forecast. For reference, the average rig count in the fourth quarter of 2015 was approximately 600 rigs. So although our assumptions on oil prices and oil volumes were in line with actuals through March 31, more recently we are beginning to see more aggressive production declines than we included in our initial 2016 guidance.

Additionally, as we factor in the current oil rig count of approximately 330 rigs, and recent commentary from some of the leading oil-field services companies regarding their expectations for activity levels in the second quarter, we now expect aggregate lower 48 onshore production decline for the 12 months of 2016 of approximately 700,000 barrels a day as compared to our previous estimate of roughly 325,000 barrels a day, which was associated with the average rig count of 500 rigs.

We intend to provide similar information on a region-by-region basis in about three weeks, when PAA holds its annual Investor Day. At that event will also share our thoughts on inventory levels, supply and demand balances, as well as the challenges and opportunities that we see over the next several years as we transition from the down cycle to the next expansion phase. To be clear, PAA has one of, if not the best, crude oil asset platforms and business models with meaningful upsides to a recovery in US production growth, and we remain very constructive on the intermediate to long term for our US and Canadian crude oil business. Ryan will provide additional details on our Investor Day at the end of today's call.

I have just a couple more items before I turn the call over to Harry. In early April, PAA announced a quarterly distribution of $0.70 per limited partner unit, which is $2.80 on an annualized basis and PAGP announced a quarterly cash distribution of $0.231 per class A share, which is $0.924 per class A share on an annualized basis. Both PAA's and PAGP's cash distributions are unchanged from the quarterly distribution paid in February 2016.

Additionally, PAA announced a prorated quarterly distribution of approximately $0.37 per series A preferred unit. We elected to pay the preferred distribution in kind, which will result in the issuance of an additional 858,000 in series A preferred unit. On a quarterly basis, cash distribution coverage was approximately 1.01 to 1. Including distributions paid in kind on the preferred units, overall distribution coverage was approximately 0.96 to 1. With that, I'll turn the call over to Harry.

Thanks, Greg.

During my portion of the call, I'll cover our first-quarter operating results compared to the mid-point of our guidance and provide a brief update on our 2016 capital program. Slide 5 illustrates a summary of our first-quarter 2016 results. As shown on slide 6, adjusted segment profit for the transportation segment was $269 million, or approximately $9 million above the high end of our guidance range.

For the quarter, volumes were approximately 4.6 million barrels per day, or 67,000 barrels per day below our guidance. Volumes in the Permian Basin were approximately 82,000 barrels per day higher than the previous quarter, but about 80,000 barrels per day below our guidance. And while an 80,000 barrel-per-day miss on guidance seems large, it's comprised of a combination of first, our gathered volumes being approximately 21,000 barrels per day lower than forecasted, and second, our actual volumes with MBC shippers being approximately 10,000 barrels per day less than forecasted, and then third, the multiplier effect of such lower gathered than MVC volumes. MVC is minimum volume commitment volumes.

By multiplier effect, I mean the fact that once we capture a barrel at the wellhead through our gathering activities, it may result in the same barrel being transported on more than one of our pipelines. This was certainly the case in the first quarter, as gathering and MVC shortfalls also impacted volumes in our Permian Basin trunk lines.

Adjusted segment profit of $0.64 per barrel was above our guidance of $0.59 per barrel, primarily due to the revenue recognition of MVC volume deficiencies in the first quarter. Excluding the MVC deficiencies, for which we received cash, but not volumes, adjusted segment profit would've been in line with our guidance of $0.59 per barrel.

Adjusted segment profit to the facility segment was $167 million, which was approximately $16 million above the high end of our guidance range. Volumes of approximately 127,000 barrels of oil equivalent per month were in line with our guidance. Adjusted segment profit of $0.44 per barrel was $0.06 per barrel above the mid-point of our guidance, and was due to several factors, including higher-than-forecasted activity in our terminals, lower-than-forecasted operating expenses and the revenue recognition of MVC volume deficiencies.

The MVC revenues related to our rail terminals, excluding the MVC deficiencies, adjusted segment profit would've been $0.42 per barrel, or $0.04 above the midpoint of our guidance. Adjusted segment profit for the supply and logistics segment was $184 million, or approximately $10 million above the midpoint of our guidance. Volumes of approximately 1.2 million barrels per day were in line with our guidance and adjusted segment profit per barrel was $1.65, or $0.08 above the midpoint of our guidance, and was primarily driven by more favorable crude oil market opportunities in Canada, inventory costing considerations that will reverse later in the year, and stronger than forecasted demand for butane in our NGL sales activities.

In general operating expenses for each of the three segments were below our guidance forecast, a portion of which are timing-related issues and will be incurred later in the year. In total, the timing benefit related to these operating expenses and the inventory costing considerations I just mentioned were about $12 million for the quarter.

Moving on to our capital program, slide 7 provides the anticipated in-service dates for PAA's significant projects. I'll note that the permit delays have pushed out a portion of the capital spend in our Diamond and Red River pipelines and weather-related issues have extending the timing of our Caddo pipeline. These delays will not impact 2016 financial results, but may push back the in-service dates of these projects by a month or two. The impact of these delays on our 2016 capital program is offset by the addition of recently approved expansion projects totaling 2.5 million barrels at our Cushing, St. James and Patoka terminals. All these projects are supported by long-term contracts.

Before I turn the call over to Willie, I want to mention that we have recently executed a couple of long-term gas storage contracts at our Pine Prairie facility, which start in 2018. These contracts total 12 Bcf of gas storage and are expected to facilitate the movement of natural gas to LNG export facilities in the Gulf Coast.

With that, I'll turn the call over to Willie.

Thanks, Harry. Good morning.

During my part of the call, I will address our acquisition and divestiture activities, our operating and financial guidance for the second quarter and full year 2016, and I also want to touch on our initiatives to optimize PAA's assets and reduce our costs. In January of this year, we announced our plans to sell $200 million to $400 million in assets as part of an asset review process. As a result of that review and the anticipated acquisition of the complementary Canadian NGL business that was announced on April 4, we increased our target for 2016 asset sales to a range of $500 million to $600 million.

As summarized on slide 8, we have completed four transactions for approximately $350 million since the beginning of the year. The assets sold include the BOA pipeline in our Louisiana Gulf of Mexico pipeline assets, crude oil storage tanks located at the Holly Frontier refinery in Tulsa, Oklahoma, four refined product terminals located on the East Coast and a Gulf Coast gas processing facility. We are currently working on several additional transactions totaling approximately $150 million that are either under contract or in advanced stages of negotiation and are expected to close in the second quarter 2016.

We are also evaluating a few additional non-core assets that we may take to market later this year, as well as potential projects where taking on a strategic partner adds alignment of interests and value. A good example of this type of project is our Diamond Pipeline JV with Valero, where they are both an equity owner and an anchor shipper.

Overall, we have been very pleased with the transactions we have completed and with the values we expect to realize on the remaining assets. We believe the assets sold are a better fit with the buyers and will allow them to capture incremental synergies and generate an attractive return while fairly compensating PAA for the historical and prospective cash flows.

Equally important, proceeds from the sales allow us to redeploy capital to our core assets, generating stronger returns. A great example of this is our pending purchase of the Canadian NGL business owned by Spectra -- a unit of Spectra Energy for CAD280 million, or approximately $150 million, which is summarized on slide 9. This acquisition is a very complementary fit with our Canadian NGL business platform and will provide us with synergies for solid cash flow base and meaningful upside potential.

As Greg highlighted earlier and summarized on slide 10, largely in response to significantly lowered drilling activity than we assumed at the beginning of the year, we've reduced our 2016 adjusted EBITDA guidance by $100 million. The lower production expectations primarily impact our transportation and our supply and logistics segments. Increased competition for the marginal barrel compresses lease margins, which you will see in our supply and logistics segments, and it reduces our volumes in the transportation segment, which is partially offset by the benefits of our and MVCs.

In the facilities segment, we anticipate incremental earnings from our Canadian NGL assets, primarily related to our pending acquisition and increased US storage facility utilization, partially offset by reduced rail activity. I will touch on this more in a moment, but it is important to note that our updated guidance reflects lower expected growth in our transportation segment, but it's still represents positive growth for us year on year, despite our expectations of production declines in many of the major onshore producing basins.

Slide 11 shows that while Permian Basin forecasted production is expected to be relatively flat in 2016 versus year-over-year average production levels, our Permian Basin pipeline volume forecasts are expected to grow approximately 19% over that same period. As Harry noted in his comments, we also want to remember that because of our interconnected system, a single barrel of production can have multiple impacts on our reported volumes, in some cases equating to 2, 3, or even 4 times of transportation volume on the barrels of transportation volume.

Slide 12 summarizes the operational assumptions used to generate our guidance for the second quarter 2016, which we furnished yesterday. For our transportation segment, we expect volumes to average slightly below 4.8 million barrels per day for the second quarter, or an increase of 162,000 barrels a day over the first-quarter 2016, but generally lower than the levels included in our beginning of our year guidance. Most of the volume growth in the second quarter is related to anticipated increase in Permian volumes to be transported on our PAA systems. Offsetting these benefits and impacting segment profit are timing impacts around the recognition of MVCs and integrity and maintenance expense costs, as well as the sale of our BOA and Louisiana Gulf of Mexico pipeline assets.

We expect adjusted segment profit to be $0.58 a barrel, and while lower than the first quarter, it is in line with our original guidance. We expect MVC-related volumes to be slightly lower for the first -- than the first quarter and a portion of the contribution from these agreements, I want to note, will not be recognized in the quarter due to timing and billing intervals.

For our facilities segment, we expect an average capacity of 129,000 million barrels of oil equivalent per month, which is slightly above first-quarter volumes. The volume increase is a result of 1.75 million barrels of new tankage at our Cushing and St. James terminals, partially offset by reductions associated with our East Coast terminal sale. Adjusted segment profit per barrel is expected to be $0.38, which is $0.06 lower than the first quarter. The decrease in segment profit per barrel is attributed to higher operating costs primarily due to timing and MVC impacts, which impact our per-unit margins.

For our supply and logistics segment, we expect volumes to average 1.07 million barrels per day, or 158,000 barrels lower than the volume in the first quarter. Adjusted segment profit per barrel is expected to be $0.42, or $1.23 per barrel, lower than the first quarter. The lower volume and segment profit per barrel is primarily due to weather-driven seasonality associated with our NGL sales activities. It also includes our expectations of slightly lower lease gathering volumes and margins due to continuing competitive crude oil market conditions.

Finally we are focusing -- very focused on optimizing our assets and managing and reducing costs. PAA has a very integrated value chain and a unique business model that allows us to optimize our margins across the entire system. Slide 13 shows how we participate in that full value chain, from the lease gathering where we purchase approximately 900,000 barrels a day of crude to multiple transportation segments, storage facility in key terminals, and access to multiple markets.

Our strategy is to utilize our lease gathering business to capture the first purchaser barrel, and as a result of our system, capture the multiple opportunities within the system. This combination allows us to be more competitive and to continue to grow our volumes profitably, even in a declining production environment.

We are also increasing our focus on costs without sacrificing safety compliance or operating excellent. Our increased efforts are primarily in three areas, prudently managing our headcount and reducing contractor usage, as well as negotiating aggressively but fairly with our suppliers. We have been successful in offsetting a portion of our natural workforce attrition by re-allocating personnel from areas that activity has slowed, such as rail operations and from some of our asset sales to fill other needs across the organization. Collectively, our total employee headcount is running approximately 4% below levels projected at the beginning of the year. We have been pleased with our progress and along with cost savings from reduced contractor usage and supplier services, we expect to see additional efficiencies and savings, which are included in our updated 2016 guidance numbers.

With that, I'll turn the call over to Al.

Thanks, Willie.

During my portion of the call I will review our capitalization and liquidity, review our treatment of deferred revenue from MVC contracts for adjusted EBITDA and DCF purposes, as well as provide an update on the equity credit percentage assigned to our recent preferred equity security.

PAA's overall financial position improved during the first quarter of 2016, which is highlighted on slide 14. At March 31, we had long-term debt to capitalization ratio of 49%, a long-term debt to adjusted EBITDA ratio of 4.2 times and $3.8 billion of committed liquidity. This improvement is associated with both the $1.6 billion preferred equity transaction and asset sales completed during the quarter. Proceeds from the preferred equity transaction and our targeted asset sales are more than adequate to fund our 2016 capital program, the recently announced Canadian NGL acquisition, and our distribution shortfall such that we expect to exit 2016 with lower long-term debt than we entered the year.

High level sources and uses of cash is summarized on slide 15. While our long-term debt to adjusted EBITDA ratio remains elevated relative to historical levels and our targeted range, given the current phase of the crude oil cycle, we remain committed to our targeted credited metrics and expect our leverage will improve and return to within our targeted range as we realize the benefits of new projects coming online, coupled with an industry recovery. Naturally, we will closely monitor development in the near term, and we have a number of additional levers available to us to mitigate adverse impacts and/or improve our financial position if necessary.

As Harry mentioned during his portion of the call, we had favorable financial performance compared to our guidance. Approximately half of the over performance relative to the midpoint of our first-quarter guidance was associated with the inclusion of the MVC contract deficiency billed or collected in adjusted results. As we have discussed in prior conference calls, we have certain agreements that require counter parties to deliver, transport or through put a minimum volume over agreed-upon periods. Some of these agreements include makeup rights if the minimum volume is not met.

If a counter party has a makeup right associated with a deficiency, GAAP requires that as we invoice and collect the cash, we defer the revenue attributable to the counter party makeup right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, or when the counter party's makeup right wither expires or is determined to be impractical or remote. Beginning this quarter, we included in our selected items impacting comparability, deferred revenues associated with MVC deficiencies. Since these billings vary by contract and for the most part are not billed on a quarterly basis, there will be a fluctuating impact on quarterly results during the year. In future periods, when the revenue is subsequently recognized for GAAP purposes we will reverse the MVC deficiency adjustment.

Before I turn the call over to Greg, I want to provide an update to the comments I made on the February call around the equity credit percentage assigned by Moody's to our $1.6 billion preferred equity transaction that closed during the first quarter. On our February 9 earnings call, I mentioned that we had requested that Moody's reconsider the 25% equity credit they assigned to the securities.

Moody's did in fact reconsider and determined that the preferred security will receive 50% equity credit. We are appreciative of their follow-through and pleased with the outcome.

With that, I'll turn the call back over to Greg.

Thanks, Al.

We are pleased with PAA's first-quarter performance and despite continuing industry challenges, believe we are well positioned for the balance of the year and beyond. In addition to our constant goal of running safe, compliant and environmentally responsible operation, as discussed during year-end earnings call on February 9, we have three simple goals for 2016. First is to maintain a solid balance sheet, sound credit metrics and ample liquidity. Second is to execute our capital program in order to facilitate cash flow growth underpinned by MVCs and position PAA to benefit meaningfully as US production volumes increase. Third is to optimize our assets and focus our organization to deliver the best results possible under whatever conditions we encounter in the near term.

As demonstrate by today's call and our first-quarter results, we are off to a solid start with respect to all three goals. Although 2016 will be a challenging year, we have substantial liquidity and are well positioned financially to manage through a challenging industry period. Additionally, as a result of the ongoing initiatives that Willie outlined earlier, we expect not only to manage well through the down cycle but also to position PAA to capitalize on increasing volumes and other opportunities that will be available as we progress to the expansion stage of the next up cycle. These initiatives include disposing of non-core assets, adding complimentary assets, focusing on cost inefficiencies, reinforcing customer and joint venture relationships, and further refining our integrated value chain.

Looking forward, PAA has the best, largest and most interconnected crude oil platform in the US, and a business model that has been proven through performance during a number of prior cycles. We also have the visibility for incremental cash flow contributions from project completions backed by MVCs and other contractual support, as well as significant leverage to a sustained increase in US crude oil production with no to low incremental CapEx. For those reasons, we believe PAA and PAGP represent inexpensive low risk long-dated calls on US crude oil production growth.

I want to touch on one more matter before I turn the call back over to Ryan. As discussed in our last conference call, we are in the process of evaluating potential simplification alternatives between PAA and its general partner, and are in frequent contact regarding a potential simplification with the three largest owners of our general partner and the PAA and PAGP Boards. This process involves evaluating PAA's future performance, needs and opportunities under various industry scenarios, as well as exploring a wide range of alternative structures to attempt to identify a win-win transaction that would better position PAA to perform and prosper in such scenarios.

As many of you on this call are aware, there are a number of potential variations to a simplification, and it is important that we are not only -- it is important that we not only do the right thing, but that we follow a process that demonstrates thoughtful, prudent and balanced governance practices. Some of these processes take longer than any of us would like, but done correctly can still be accomplished within a reasonable time period. The evaluation process is ongoing, and no decision on any particular alternative has been reached, nor can we provide any assurance that any particular alternative will be pursued or effected.

As we continue to work through this process, we will be monitoring industry developments and market conditions, but we do not intend to disclose further developments with respect to this evaluation process except to the extent that a specific course of action is approved, the process is concluded, or we believe the situation warrants an interim update. With those thoughts in mind, I respectfully request that you refrain from asking questions with respect to the topic process or timing, as these comments that I've just shared summarize all the information we are able to provide at this time.

With that, I'll turn the call back over to Ryan.

Thanks, Greg.

Before we open the call up to questions, I just wanted to remind everyone that we will be holding our 2016 PAA and PAGP Investor Day on May 25 here in Houston. There is still space available and we encourage anyone who wishes to attend, but is not already registered, to do so as soon as possible. If you have not received an invitation but would like to attend, please contact investor relations at 866-809-1291.

Once again, thank you for your investment in PAA and PAGP and for joining us on today's call. We look forward to updating you on our activities at our Investor Day in May and on our second-quarter earnings call in August. Linda, we are now ready to open the call up for questions.

(Operator Instructions)

Kristina Kazarian, Deutsche Bank.

Greg, maybe you can help me out with this one.

I get a lot of questions on if when I'm thinking for 2016 you need to cut your distribution. My general comments have been that I don't think so, but could you just provide your current thoughts on the topic, and why you don't think this is something that is going to happen in the near term?

Kristina, we were pretty specific at the beginning of the year that based upon our outlook for 2016 and what we extrapolated into 2017, that we did not feel like we needed to because although we knew we were going to run negative coverage in 2016, we saw the light at the end of the tunnel with all of our projects coming on in 2017. We have not updated that comment since then at this point in time and to some extent, my earlier comments about the concept of discussion of simplification wrap around that very issue. So other than what we have said with respect to the simplification, we can't really comment anymore at this point in time.

Perfect. A follow-on to that, you said that coverage improved during in the quarter and we climbed up closer to that 1 times number and we got the incremental credit from Moody's up to 50% now. Can you give me more high level of comments around how conversations with the rating agencies are going?

Yes. As you would expect, we have an ongoing dialogue with the agencies. Again, we are very pleased with Moody's and their reconsidering the preferred. Both agencies have had fairly recent published material on us, and I would point you back to reading that. Clearly, they understand that we are running above our historical leverage target. We also have a long track record of keeping and returning back to those levels over time. So I think we have a pretty credible track record with them, but I would point you to more what they have published on specific comments.

I imagine when I'm looking at slide 7 they're giving you credit for a lot of the cash flow that is coming from major projects coming online. Is that right?

Yes. Again I would point to how they -- we have provided them a lot of details around project cash flows, MVCs, contributions to those. We know that they at least consider that in how they evaluate a credit.

Perfect. Thanks.

Shneur Gershuni, UBS.

Just a quick follow-up to the last round of questions on the agencies. Did you preview the guidance cut with the agencies? And are they cool with it, or should we expect another update from them?

We did and arguably I think a lot of our comments on the February call spoke to the activity levels then. We don't expect that the revision here, the 4% reductions, would be a surprise to either agency or to probably most of the analysts on this call.

Shneur, this is Greg. I would just make the comment that if there is a more transparent company out there with the public, I would be surprised, and you should assume that, that level of transparency carries over to our dialogue with the agencies, as well.

No. I agree the guidance was in line. I just wanted to see if it was previewed.

I have an interesting question about your guidance. I was listening to your prepared remarks and going through the slide. Basically, we have a scenario where pricing is going up because volumes are going down and your guidance effectively reflects that. When I think about the exit rate for 2016, and especially how you laid it out in slide 4, that there would need to be a lot of activity to bring volume back. How should we think about your existing business volume run rate in 2017? Can the CapEx that you highlighted offset all of the decline? Can it actually produce growth? How should we be thinking about that as we think about your run rate for 2017, before we get to 2018, where you would expect volumes to be up?

If I could frame this in a way that embraces what we've said prior in that it really has not changed and that is, with the projects that we have coming on in stages, not only at the end of this year but the beginning and throughout, really, 2017, we expect EBITDA to grow even if we stay in a down cycle into 2017. Some of that EBITDA, it may turn out if we are wrong on volumes as we exit this year, if it is supported by MVCs from highly rated entities, which most of our projects are, we are going to get the cash. And as Al identified earlier and we had discussed on prior calls, we were trying to figure out how do we address the situation where we have cash, we're going to collect it, and yet, for GAAP purposes we don't necessarily get to recognize it as revenue. We chose to make that adjustment. On an adjusted basis, we would expect EBITDA to continue to grow throughout the second half of 2016 and into 2017.

Okay. One thought question. Rail in general, not just for your partnerships, but it basically seems to be quite challenged, especially with some pipelines coming on, volumes coming down and so forth and they're being more competitive. How do you think about being able to re-purpose the assets? Did something that -- Mexico is an emerging trend. Is crude by rail or refined products by rail to Mexico kind of an option? How should we think about this, or these assets that are going to, as leases roll off, age out, basically?

Well, first off, I think it is important to note that in our guidance we reflected the challenging environment that you just, I think very well, outlined for rail. The other one is as I think Willie addressed in his comments, we're looking to optimize our assets. I think if you look historical at Plains, we have had a history of being able to repurpose assets, especially on the pipeline side and certainly the concepts should apply as well, as you suggest, to the rail side. On our pipeline side, I think we have got some pipelines that have moved north and then south and then north again, and in some cases have actually been changed out of one product service into another one. The same type of flexibility has the potential to exist for certain rail assets.

We are in the benefit of having both loading and unloading so that we are not married to just one part of the business. I really couldn't comment more beyond, as far as what we might be doing with anything with Mexico or anything else at this time.

I will add to what Greg mentioned, that if you look at our rail facilities, a lot of them are tied to either pipelines or terminals, so we have embedded a lot of flexibility in the rail assets, so if you get market dislocations or disruptions, the rail still provides an alternative. But we have very few facilities that are isolated rail facilities on a standalone basis. We've got rail facilities in Bakersfield tied to pipeline, St. James terminal, Yorktown terminal, et cetera.

Okay, great. Thank you very much. Thanks for the color.

Thank you.

Faisel Khan, Citigroup.

Thanks. Good morning.

Good morning, Faisel.

Just looking at the guidance for the Permian Basin volumes for 2016, down about 170 a day or so. I just want to understand, is that just a base production volume change, or is there a multiplier change too, meaning that do you expect the volumes to be less on some of the pipelines, but the production to continue to ramp up? I just want to make sure I understand that reduction in volumes?

It is definitely a multiplier.

Faisel, what number are you looking at again to make sure I got your question?

2016 crude oil pipelines volumes in the Permian Basin, 2.207 million versus 2.380 million. I just want to understand if that is a pure production decline, or is there something else across the system that is causing that number to be lower?

A lot of it is around lower expected growth than what we thought before. There is a multiplier effect. If you think about the Permian, I think Harry's numbers that he shared in his portion of the call had roughly a 2.5 to 3 times multiple on it. If you think about the initial barrel that is produced in the multiplier effect, you can probably use 2.5 to 3 across the Permian and it would be a pretty good proxy.

Faisel, just to make sure I'm clear on what you're asking, the quarterlies that we show on page 5 of the 8-K actually show grow throughout the year. You are comparing the average for the year with the prior?

Yes.

Clearly, you go back where we were at 500 rigs. I think in the Permian we had that -- of the 500 that we started off the beginning of the year, I think we were about 205 to 207 rigs, is was what the average was for the Permian. We are running right now about 135 rigs.

So what we are anticipating and built into the guidance is what you expect to see in the tail end of 2016 volumes to fall because there is a time lag between you have rigs -- and, clearly they are drilling more efficient, but the completions we are actually seeing actually expected to tail off, so yes. If you took the difference in that average and you probably divided by some multiplier, you are going to end up basically with a lower level of expected decline for the Permian, but it's still going be that amplified level of impact on Plains.

Compared to our original guidance, our gathered volumes, the barrels that we first gather and start the multiplier process are probably down -- are lower than our original forecast by plus or minus 40,000 barrels a day. The rest of the business has a multiplier effect on those barrels.

Okay. Got you.

I want to understand also the guidance around the Western segment? There is nothing in there for the reactivation of the pipeline at Santa Barbara, is there?

There is not. It is mostly tied to the revision, and the Western segment is mostly tied to the timing of the restart of the Torrance refinery.

Okay. That makes sense.

The Gulf coast, the volumes trajectory being lower, is that just asset sales? Is that what is causing that number to be lower?

Yes. A big piece of it is.

Okay. On Empress, I just want to make sure I understand. Empress has been one of these set of assets that has been feast or famine of the last decade or decade and a half. Is there something that you guys can do between what you have already in Western Canada and the system to stabilize the profitability of that asset?

I think if you recall when we announced the acquisition of the BP facility, which got us our initial foothold into the Empress area, we -- BP ran a totally different business model than we did. We tend to basically hedge and integrate those assets with our existing operations. We would intend to fold this in, in the same way. There may be, in a given year, less upside perhaps than what there had been before. But there should be a lot lower down side as well, wouldn't you say, Harry?

Yes. The asset effect is complementary to the existing footprint that we have and provides a unique set of synergies that are available to us.

Okay. Got it. Thanks for the time.

Thank you.

Gabe Moreen, Bank of America.

Good morning all. Quick question. I think the last call you did a pretty deep dive on the counter party side of things. Anything changed on that front in the last three months and is any of that incorporated in guidance?

Yes. No. We did do a deep dive last time. We felt like we did not need to walk through it again. No real material changes at all. We remain comfortable with our overall credit exposure and performance risk of our shippers and our customers. Again, we continually monitor that process as we have done for a long period of time, so no real change there, Gabe.

Thanks, Al. Greg, in the comments you mentioned that the closing in terms of swapping assets, both asset divestitures, but as well as acquisitions. In addition to Empress, any other areas you are really looking at in terms of, I would assume, doing tuck-in acquisitions that look appealing?

Yes I would say we are constantly in a state of analysis and review. I think we have had our eyes on a few for some time. This is the asset, the Empress asset, is one that was identified early post the acquisition. And so, sometimes they take time to pull together. There is not anything probably that I would want to telegraph on this call that is either eminent or that would alert any of our potential competitors as to where we are focused.

Great. Thanks, Greg. That's all I had.

Jeremy Tonet, JPMorgan.

Good morning.

Morning, Jeremy.

I was wondering if you could help me think through the Canadian wildfires. What impact do you see on the commodity side there for crude oil prices and nat gas prices, if you're comfortable sharing thoughts there and what impact that could have on Plains?

Well, the longer, if the issue exists or is going to pull down inventories. It is kind of similar situation happened last year and had a pretty meaningful impact and drove prices up close to $60 last year. I don't know if we'll see a repeat of that. We are seeing that it is impacting some of the Syncrude operations up in that part of Canada. There is no direct impact to any of our assets, but the movement of differentials could have a slight positive impact to us. But a lot of that is -- we embed that type of volatility into our guidance to start with. I would not say it is meaningful impact to our guidance. But those are the types of things that do cause dislocation, price dislocations from time to time.

I think, Jeremy, obviously it is pretty early days in response to the event. Without better clarification from anybody as to what the duration or the overall magnitude of the impact is going to be on the actual operations up here, it's hard to say. I do think we are fairly well positioned.

We can certainly have parts of our business that are impacted negatively by differentials that we might've been expecting to make a profit on certain barrel movements, but as Harry mentioned, there are other parts that tend to then pick up. So from an overall supply/demand balance, if you lose -- what's the order of magnitude, I think we're talking about --

Anywhere from 0 to 500 BOE, is what I've heard.

A couple hundred thousand barrels a day right now.

That will impact, obviously, the inventory pull down, as long as we did not end up importing more on the water to replace it. There are certain parts -- . I mean, theoretically, we should see incremental movements up cap line, perhaps, to help replace those barrels, but again, that would probably be more of a foreign movement that comes in. So it would not necessarily affect overall inventory, but it would affect our movements on that pipeline.

Great. Thanks for that. Just a quick modeling question with the MVCs. Have you guys identified which pipes those are showing up on and what -- quantity there again?

Yes. Every MVC that we -- when we bill it, it's by pipe, it's by tariff rate in that contract. That is all underlying that adjustment there. Clearly, more of our recently constructed pipes are the ones that have the longer MVCs on them.

Jeremy, if I understood your question is -- I think Al just answered, do we know which pipes is going to on? Absolutely. Have we communicated that information to the public? And the answer is absolutely not. Shipper information is by law extremely sensitive, and we certainly don't want to step on that line.

I think I stated in my prepared comments the deficiencies were about 10,000 barrels a day less than -- the deficiencies were about 10,000 barrels a day more than we forecasted in our original guidance. That does have a multiplier effect, because it can affect, and does affect, more than one pipe.

Where we lose on that, if we collect on that one pipe and as Harry said, if we were counting on that 10,000 barrels to move off pipe, A, that we may have MVC payment on, but it would have normally transferred on to pipeline B that we might not have a MVC for that barrel. You can end up where we get paid for the first 10,000 barrels, but we haven't collected on the next 10,000 barrels until they move it.

I appreciate the customer sensitivity. Don't want to give anything away there. Is it possible at all maybe to just talk about regions without pushing too hard here?

I think I said in the prepared comments they're primarily related to the Permian.

Okay, great. Thank you for that.

I think previously there was talks about a soft guidance outlook for 2017 being about 10% higher and expanding on the comments you had before with the exit rate for 2016 volumes. I'm just wondering, does it still make sense, that 10% number? Is it off a lower base? I realize you probably might expand on this more on the Analyst Day, but just wondering if you could provide us any thoughts there.

Don't have really have any -- add additional comments, Jeremy, to today's discussion. Like everybody else, we are trying to deal with a dynamic situation. Clearly the visibility for 2016 is a little better.

Part of this issue is what happens as we get closer to the end of the year. It is quite possible that we could see a fairly significant response to rig activity toward the end of the year that would have no impact on 2016, but would have a fairly significant impact on 2017. I think it would be premature for us to try and add much clarity to 2017, other than the fact that we know because of the MVCs and the projects that we have that are backed by those MVCs that we have got a decent uplift in 2017. I just hate to try and calibrate something right now and then have to come back to you later on and say, with new data we had to recalibrate, when at this point in time our focus is really on the near term.

That makes sense. Thanks for all the help today.

Thank you.

John Edwards, Credit Suisse.

Yes, good morning, everybody. Thanks for taking my question.

I am just -- I will start off, in your guidance revision, how much cost savings is baked into that, if you can give us an idea on the quantification there? I'll start with that one.

Let me take that and others can add in if they'd like We have not gone out with a specific target. One of the things we are sensitive on is not trying to manage by objective, set a target and everyone goes for it. What we're trying to do here is we're working through the organization to make sure people are aware of what we're trying to do and we're getting a lot of what I will call ground-up cost savings. The way I would characterize it is, you see a lot in the -- I mentioned a lot around managing people and supplier savings and contractors. We are seeing good progress from that. I would measure that in tens of millions, not hundreds of millions, if that helps.

Yes, that helps. Okay. I'm just curious, Greg, given this steeper volume drop off that you're talking about, and how are you seeing, say, competitive conditions intensify? And that's what -- I know a lot of people are asking about the exit rate and so on for 2017. But is there anything you can comment there with regard to how we might have to look through to next year, as well?

I can't -- so much give you the look through to next year. I will say that in the balance of 2016, if there already was a lot of competition for the marginal barrel, and you have fewer marginal barrels, we have more competition for what is remaining. We've built that in to our expectations.

I hate to fall back on the old adage, but we are clearly getting -- progressing through the cycle to the point where the best cure for low oil prices is low oil prices. And, at some point in time when this thing turns, we're going end up where everybody is trying to figure out how do we move the more barrels that I think we will be coming that need to developed to respond to the gap in demand.

Again, I'd probably tell you, there is certainly competition has -- is at least as intense or if not more intense for that marginal barrel today and that is reflected in our expectations for the balance of 2016. To try and go into 2017 just yet when really don't have the passage of time there, I am not sure I can give you any high percentage comfort level that would be worth anything.

Okay. Has there been any change to your crude price assumption now? I think in the first -- or the last quarterly call, you said $47 for the full-year. Is that -- I missed and maybe you affirmed that, or maybe you have a slightly take on that? Just if you could provide us that.

Yes. Let me just -- we are not in the business of forecasting oil prices.

What we have to do sometimes is make assumptions. For example, when we are trying to figure out what can producers support out of cash flow, and that is what we did at the beginning of the year, where we had our $35, $45, I think we had $55 and $60 by quarter. As we sit here today, John, you can't associate it with anything more than just plain dumb luck, but our damn numbers have been right on top on the price. The problem is that the activity levels that that level of cash flow would support are significantly lower. I think our view is, inventory is still -- we're at a very, very high levels.

I think we're over 540 million barrels right now, which our outlook would tell you, and we will talk more about this at the Analyst Day, would that we probably don't cross under the same level of inventory that we had in 2015 until end of third quarter, late fourth quarter. So, what happens is we will be below 2015 inventory levels.

That would be a pretty significant psychological barrier to break. Having said that, when we break through that we will still be roughly 60 million barrels above what is normal. So there is still pressure. So part of the issue is, when does the market starts to front run the solution. I think we are as -- probably we were accused of being bullish after having been accused of being bearish for a long time.

I don't think we really changed our view that this thing is going rally pretty hard. It may get worse before it gets better, just because of the inventory. We got to get through the summer. There's a lot of expectations around Doha that did not come to fruition. But there's other things that happened that offset that. And then we've got the OPEC meeting on June 2, and normally that gets a lot of press. It doesn't necessarily take a lot of substance for them to put a lot of press out there and talk about it.

At the end of the day there is band of inelasticity somewhere between $30 a barrel and $45 a barrel that when it moves up or down $5, the press always has an answer for the reasons why. We all look at each other and say, we are not sure what changed from five hours ago. Long way of telling you I don't think we would change our outlook with any significant calibration. It will be interesting to see if -- how it passes. Again, we were $35, $45, $55 and $60 by quarter, and right now, before I walked in here, the price was $45. Don't know that I know enough to change anything.

Okay, that's helpful. That's it for me, thank you.

Brian Gamble, Simmons & Company.

Greg, you shouldn't sell yourself short. When you get something right like calling the crude price for a quarter, you should take a bow rather than call it dumb luck.

Well, let's talk at the end of the year and see how we came out.

That's fair. I did want to follow up on your last three answers. You have answered to a degree. But when you look at the level of activity, the discrepancy between your previous forecast and the current forecast, I juxtapose that against the volumes that are moving in various basins. I'm sure you have been keeping abreast of what E&Ps have been reporting, but they've been reporting some pretty strong production quarters relative to expectations.

Does the extent that the industry continues to surprise to the upside on their efficiencies, and the way they are drilling, does that change any long-term viewpoint of yours, as to which asset or which region may be better positioned for Plains than others. Or change anything on your thinking in regards to what to sell and what to buy? I'm not looking for specifics. I just want to know if the trends that we have seen over the first four months are starting to influence your long-term thought process.

I think probably the best way to answer is we try to use all available data to do what you are suggesting. How do we best position ourselves? Where do we need to make sure we have additional capacity if we start to see that a particular area is heating up. If we were having this discussion two years ago, one of the hottest areas was the Mississippi Lime. Today, it is probably one of the weakest areas. So you have to be careful to make sure what you think is truly sustainable and we try to make that.

I think one of the things we're working through and earnings season is just as probably busy for us as it is for some the analysts, because we try to take public comments that are made and true it up with the data that we're seeing, realizing that in many areas, Brian, we do a well-by-well analysis, and we are tracking everything that is going on. Not by area, but by county and in some cases sub-counties, because it really matters where you put that pipe at, or where you try to free up capacity.

I will say that I think some of the BOE revisions up, et cetera, they are BOE and there is a big portion of gas in there. Gas increases don't help us. If it is in an area that it is on somebody's acreage that they have dedicated under an acreage commitment to somebody else, if there is 10,000 barrels a day of extra production it may not help us at all. On the other hand, if it's in an area where that is either up for grabs or on our acreage, it has a big impact.

The short answer is, we use all that data. I think as we sit here today trying to correlate press releases of people tweaking guidance up, the first thing is what did we already account for in our numbers that we had at the beginning of the year, because in some cases we have dialogues with these as customers and they tell us, prepare for 40,000 barrel a day increase in a given area. They may be telling us privately it is 35,000, but the public may have been expecting it to be 30,000, and now it's up to 35,000. So it sounds like it's up, but it may be down relative to what we were told at the beginning of the year. And so we have to filter all that in.

We understand the challenges that outside analysts have trying to look at that data. We have the same challenge internally trying to correlate all that into a cohesive model. What we've reflected in at least our guidance right now is the best estimate that we have of that data, based upon not only public data, but some cases non-public data of what their drilling plans they shared with us, et cetera, are.

Great answer. Just to follow on with that, and if you don't have an answer or don't want to answer, it's fine. But is there any one data point or a couple data points so far that have surprised you in this earnings go through?

Not really.

Not really. I would also say the number of operators, there's probably a handful, 15 to 20, kind of high-quality operators that are doing really good. Somebody's making up the other side of those averages. They're our customers, too.

So, I think there is a tendency to take the 10 best and say gosh, if they're saying production is up in an area, it must be true for everybody. Some cases, you are analyzing the best of the best. And there are some others out there that don't either have as good quality of acreage, their technical skills are not quite yet up to the standards of some of the others. There is a reason why there is an average number. It's because somebody's above it and somebody's below it.

Thanks for those comments, Greg. I appreciate it.

Thank you, Brian.

Steve Sherowski, Goldman Sachs.

Good morning. Thanks for taking my question.

I believe in your opening remarks you mentioned that you were taking into account a lower lease gathering volumes and margins due to competition. I think that Willie had mentioned that your gathering volume expectations were lower by roughly 40,000 barrels a day on average for the year. I am just wondering how much of that 40,000 barrel revision was driven by competition versus lower production expectations?

I don't remember the 40,000.

There's some, I believe you said there was a take 40,000 barrels a day and then there's a multiplier effect for --

That was on the pipeline volumes versus relative to our forecast earlier in the Permian Basin. I think our lease gathering volumes are probably down to 15,000 BOE to 20,000 BOE.

15,000 to 20,000 barrels just for the --

Yes, I think that was in the guidance. 15,000 BOE.

Okay. Got you. On the 15,000 BOE, how much is related to competition just versus a lower production outlook?

It's probably more geared towards lower production outlook. Certainly we gain and lose barrels all the time on the lease side.

On the competition side, Steve, think of it as a tug-of-war. We pull barrels and somebody else pulls other barrels, because again we are still competing in some cases against these over commitments on the ship-or-pay for other pipelines. Margins have been heading down as that tug-of-war goes on. But I think most of the change -- we would assume we will probably continue to vet back and forth on that throughout the rest of the year. But if you take that 15,000 barrels a day in lower volumes and then you put the pipeline multiplier effect on it, that's what you can correlate those two numbers.

Got you. And then a quick follow-up.

I think it was Marathon was out recently saying -- talking Cap Line or bringing up the Cap Line reversal again. Just any update on that and where you think crude prices would be need to go -- or production, rather, whatever is the driver before a decision would be made?

Not much more to add to what we have already said. I think what you read in the press is about all that anybody knows at this point in time. We are big fans, I think, in that it is a great asset to be reversed. The same obstacle exists today as existed before that have kept that from moving forward and it is not related to prices.

Got you. Okay. Thank you.

Sunil Sibal, Seaport Securities.

Good morning. Thanks for taking the question.

I'm just trying to get a little bit better understanding of your guidance on the transportation segment, especially with regard to the volumes and the margin [as it shows] there and how they are moving around. I think you earlier talked about $12 million or so OpEx one-time gain in the first quarter. In addition to that, are there any other big drivers of margins as we think about the remainder of 2016?

The $12 million was a combination of operating expenses and inventory costing. On the transportation segment it is $7 million, $8 million was the -- probably the impact of operating expenses, which were timing related.

Okay. And then the rest of the variations are primarily basically a function of your contracts, or basically your tariffs on the pipelines, I presume. Correct?

Yes, mostly volume. Because if you think about it, all of our legacy pipes, those items are not contracted. Historically, crude oil pipelines have operated on the basis of a common carrier where you have a shipper can ship one month and not ship the next month. They're not committed volumes. Most of committed volumes are related to the new construction.

The way I think about it is, it is purely volumes offset by we have got a good chunk that we can get to book MVC gains on. It is just volumes times the tariff offset by the MVC volumes that we have for the year, if that was your question.

Okay. The volumes should, of course, have MVCs in them, right?

Yes.

Okay. Got it.

Thanks for clarification on the rig count. I was curious with our updated guidance that was provided today, yesterday the 330 rig count in April, is that -- what's kind assumption for the remainder of the year for the rig count, if there is something?

Is basically holding it in that range. There is trade-offs in there. One of the things is we calibrate what happens if rigs move up or down 50 rigs. We think there is kind of a bit of a corresponding offset that counters that with respect to the DUC completions. So we've tried to build in, for example, that while rigs have coming down we actually think some of the DUC completions are going up, especially as these prices have rallied a little bit.

I would say we are really basically saying for the rest of the year, let's just assume that it holds relatively constant. We're not ready to declare a bottom or anything, but gosh it has come down quite a bit and you have seen it fluctuate here recently, plus or minus a few rigs, whereas for week after week after week for the first three months it was just down, down, down.

Okay, got it.

I think on your CapEx program you mentioned that you are financing some of these storage additions. Is there anything specific in those contracts terms that you signed for those additions with everything and how you have contracted in the past?

No. Again we are fundamentally focused in on long-term customers, and I think if we had actually tank additions at Toca, Cushing and St. James, and I think they were all the same type of activities we have had before: good long-term customers that are good use that operational as opposed to financial-driven people at all. It is more operational people.

Okay. That's helpful. One last clarification for me on the leverage metrics that was provided, the 4.2X debt to EBITDA. And then of Q1 2016. Is that fairly representative of how your covenants are in terms of the leverage metrics or are there any big (inaudible) there that we should be aware of?

No. That metric is fairly consistent with our bank facility. There are a few adjustments to it, but that is pretty close.

Okay. Got it. Thanks.

Thank you.

Selman Akyol, Stifel Nicolas.

Just a couple quick ones for me. On the MVCs, are you seeing more shippers, or is it just the same shippers as before that are below their MVCs?

I think this is really the first quarter that we've started seeing that number climb up. We have some MVC late last year where we had maybe some that just started. But a lot of our projects are just now going into service in the last six months, probably, where it would become the issue. And that is why the dialogue that we've had the last couple quarters has been people have asked how are you going to handle that if volumes aren't there? And so we thought we finally landed on this approach we shared right now.

There's really not a lot of history to compare it to, because it is just now recently become into vogue again. As Harry mentioned, you don't really have existing MVCs on a pipeline that has been built 30 years ago. It's really only the recent ones, and we've just started putting those into service here recently.

Fair enough. Real quickly on the supply logistic. I know we've talked about $1.65 in Q1 going to $0.42 in the second quarter. Clearly larger decline than historical, and I've heard three reasons on the call really. One, weather related, two, increased competition and then not explicitly the multiplier effect, as well. I'm trying to think about that in terms of which ones are the largest give and takes on that, and then longer term thinking about supply and logistics as being a $500 million run rate business?

It is really hard to go quarter to quarter because first the four quarters are impacted so much by the NGL business. All your margins are in the first and fourth quarter, and the second, third quarter, usually there is minimal margin, because you have carrying costs, you have got storage costs, and you don't have much NGL sales. Looking from Q1 to Q2, it is really hard. If you just look at the crude oil business, it's ( multiple speakers ).

If you look on slide 11, I think you will see the -- we've shown that seasonal horseback. And that has been there in prior years so you would have always seen that margin projected to move down from first quarter to second quarter in the same direction.

One way to think about it is, in February we had a unit margin for the year of $1.13 and our updated guidance on effectively the same volume as $1.02. So an $0.11 change. That does reflect the competitive pressures we're seeing on the crude side that we discussed earlier.

There's really not a multiplier effect on the supply and logistics. The supply and logistics drives the multiplier effective on transportation.

And, Selman, I would just look at -- if you looking at slide 12, first quarter to second quarter, almost all of that is the NGL seasonal sales primarily around Canada.

All right. Thank you very much.

Thank you.

Charles Marshall, Capital One.

Good morning, everyone.

Good morning, Chuck.

It looks like natural gas storage is getting some more air time today, given some positive trends we have seen in the fundamentals. You had a pretty solid recontracting season at your Louisiana facility. We saw that subsequent contract announcement with Cheniere. Do you have any thoughts on how you see demand materializing from here and the cadence of firm contract pricing? And what potential commercial opportunities you'd consider to further optimize these assets. What would be helpful? Just any general color.

With that I'm going to introduce Dean Liollio to answer your question.

Hey, Chuck. What we are seeing to your point is a pick up commercially, particularly in the outer years, 2018 and beyond based on the announcement. I think really the driver is going to be by location. We clearly see more activity down at Pine Prairie and so our recontracting efforts are good there.

I think the biggest change, we've got a lot more contracting going out and we are really holding a lot less for ourselves. Probably less than 10%. I think the interest is more around operational customers going forward versus financial players. It is very positive, but it is location specific.

Chuck, as you probably know from your firsthand knowledge, we try to track not only what our activity is in terms of actual deliveries and storage activities, but also at other facilities. And we are pretty pleased that Pine Prairie has developed into one of if not the most active physical hub out there. And we expect that perhaps to continue to be the case, if not amplify, as we continue to see LNG exports. Because it is just sitting in the best position. Again, as you know from firsthand, we've put a lot of compression out there to be able to handle that. I don't know of anybody that in any better position than we are both geographically and then physically and operationally.

Thanks for that color. I just want to follow up. With the increased demand activity, do you see any future need to increase storage capacity or at these levels, are you comfortable?

We're watching it pretty closely.

Okay. Thanks. That is it for me.

There are no further questions.

Thanks everybody for participating in the call. We look forward to updating you in about three months.

Ladies and gentlemen, that does complete our conference for today. Thank you for your participation. You may now disconnect.