Ryan Smith - Plains GP Holdings LP Greg L. Armstrong - Plains GP Holdings LP Harry N. Pefanis - Plains GP Holdings LP Willie C. W. Chiang - Plains All American Pipeline LP Alan P. Swanson - Plains All American Pipeline LP Dean Liollio - PAA Natural Gas Storage LP.

Kristina Kazarian - Deutsche Bank Securities, Inc. Shneur Z. Gershuni - UBS Securities LLC Faisel H. Khan - Citigroup Global Markets, Inc. (Broker) Gabriel Moreen - Bank of America Merrill Lynch Jeremy B. Tonet - JPMorgan Securities LLC John Edwards - Credit Suisse Securities (USA) LLC (Broker) Brian D. Gamble - Simmons & Co. International Ltd.

Steve Sherowski - Goldman Sachs & Co. Sunil K. Sibal - Seaport Global Securities LLC Selman Akyol - Stifel, Nicolaus & Co., Inc. Charles Marshall - Capital One Securities, Inc..

Ladies and gentlemen, thank you for standing by. Welcome to the PAA and PAGP First Quarter 2016 Results. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Instructions will be given at that time. And as a reminder, this conference is being recorded.

I'd 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 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, U.S.; 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 three, our first quarter results reflect the combination of performance above expectations, the inclusion of deficiency amounts for shipper 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 shipper 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 whole 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 forecast were generated in the fourth quarter of 2015 when oil averaged $42.50 a barrel and producers were generally discussing 2016 budgets at plus or minus 30% below 2015 actual expenditures.

You may recall at PAA's 2016 crude oil price assumptions called for an average price 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 to backsolving for activity levels in 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 to average rig count.

We are now one-third of the way through 2016, and thus far, PAA's oil prices 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 producers' 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, as illustrated on slide four, based on PAA's fundamental analysis of wells at each of the key oil basins, we estimate that approximately 55% of U.S. 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 and 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's 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 countries regarding their expectations for activity levels in the second quarter, we now expect to aggregate lower 48 onshore production decline for the 12 months of 2016 to approximately 700,000 barrels a day as compared to our previous estimate of roughly 325,000 barrels a day, which was associated with that 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, we will also share our thoughts on inventory levels, supply-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 upside to recovery in U.S. production growth, and we remain very constructive on the intermediate to long term for our U.S. 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 pro-rated 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 Series A preferred units. 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..

first, our gathered volume being approximately 21,000 barrels per day lower than forecasted; and second, our actual volumes with MVC shippers being approximately 10,000 barrels per day less than forecasted; and then third, the multiplier effect of such lower gathered and MVC volumes. And MVC is a minimum volume commitment volumes (10:12).

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 the gathering and MVC shortfalls also impacted volumes in our Permian Basin trunklines.

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 for the Facilities segment was $167 million, which was approximately $16 million above the high end of our guidance range. Volumes of approximately 127 million 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 midpoint of our guidance, and was due to several factors including higher than forecasted activity rail 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.

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, was about $12 million for the quarter.

Moving on to our capital program. Slide seven 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 extended the timing of our Caddo Pipeline.

These delays will not impact 2016 financial results, but may push back the in-service days of these projects by a month or two. The impact of these delays on our 2016 capital program's 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. And 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 totaled 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..

prudently managing our head count and reducing contractor usage, as well as negotiating aggressively but fairly with our suppliers.

We've been successful in offsetting a portion of our natural workforce attrition by reallocating 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 head count is running approximately 4% below levels projected at the beginning of the year.

We've 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, Willy. During my portion of the call, I will review our capitalization and liquidity, review our treatment of deferred revenue from MVC contracts or adjusted EBITDA and DTF 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 time and $3.8 billion of committed liquidity.

This improvement is associated with both the $1.6 million preferred equity transactions and asset sales completed during the quarter.

Proceeds from the preferred equity transaction in our targeted asset sales are more than adequate to fund our 2016 capital program, the recently-announced Canadian NGL acquisition, and our distribution shortfalls such that we expect to exit 2016 with lower long-term debt than we entered the year.

A 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 overperformance relative to the midpoint of our first quarter guidance was associated with the inclusion of the MVC contract deficiencies, billed or collected in adjusted results.

As we have discussed in prior conference calls, we have certain agreements that require counterparties to deliver transport or throughput of minimum volume over an agreed-upon period. Some of these agreements include makeup rights if the minimum volume is not met.

If a counterparty has a makeup right associated with the deficiency, GAAP requires that as we invoice and collect the cash, we defer the revenue attributable to the counterparty makeup rights and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, or when the counterparty's makeup right are expires or is determined to be impractical or remote.

Beginning this quarter, we included in our selected items impacting comparability, deferred revenues associated with the MVC deficiencies since these billings varied by contract, and for the most part, are not built 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 adjustments.

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're 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 a safe, compliant and environmentally responsible operation, as discussed during our 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 U.S. 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.

It's demonstrated 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 upcycle.

These initiatives include disposing of non-core assets, adding complementary assets, focusing on cost and efficiencies, 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 U.S., and a business model that has been proven through performance through it 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 U.S. 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 U.S. 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 in 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's important that we not only do the right thing, but that we follow a process that demonstrates thoughtful, prudent and balanced government 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's 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've 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're now ready to open the call up for questions..

And we will begin with line of Kristina Kazarian with Deutsche Bank. Please go ahead..

Hey, guys..

Good morning..

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

I get a lot of questions on if what I'm thinking for 2016 you guys need to cut your distribution, and my general comment has 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's going to happen in the near term?.

Kristina, we're pretty specific at the beginning of the year that based upon our outlook for 2016 and what we extrapolated into 2017, that we didn't 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 come on in 2017.

We haven't updated that comment since then at this point in time. And to some extent, my earlier comments about the concept of discussion simplification kind of wrap around that very issue. So other than what we've said with respect to the simplification, I really can't really comment more at this point in time..

Perfect.

A follow-on to that, you guys said that coverage improved during the quarter and we kind of got closer to that one times number and we got these incremental credit from Moody's up to 50% now, but can you give me some more high level comments around how conversations with the rating agencies are going?.

Yeah. I mean, as you would expect, we have an ongoing dialog with the agencies. Again, we're very pleased that (32:11) they're reconsidering the preferred -- both agencies have had fairly recent published material on us, and I would point you back to kind of reading that.

Clearly, they understand that we're running above our historical leverage targets. 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've published on specific comments..

And I imagine when I'm looking at slide seven, they're giving you guys credit for a lot of the cash flow that's coming from major projects coming online.

Is that right?.

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

Perfect. Thanks, guys..

Next we go to the line of Shneur Gershuni with UBS. Please go ahead..

Hi. Good morning, guys. 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 kind of spoke to the activity levels then, so 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..

Yeah, Shneur. This is Greg. I would just make the comment that if there is a more transparent company out there with the public, I'd 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 aligned, 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. Base, (34:39) we have a scenario where pricing is going up because volumes are going down, and your guidance effectively reflects that.

So when think about the exit rate for 2016, and especially how you laid it out in slide four 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, and can the CapEx that you highlighted offset all of the decline? Can it actually produce growth? I mean, how should we sort of be thinking about that as we sort of think about your run rate for 2017 before we get to 2018 where you would expect volumes to be up?.

If I can frame this in a way that embraces what we said prior in that, it really hasn't 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're wrong on volumes as we exit this year. If it's supported by MVCs from highly rated entities, which most of our projects are, we're 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, and so 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. And 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 repurpose the assets? Did something that – Mexico is an emerging trend, is that – is crude by rail or refined products by rail to Mexico kind of an option? How should we think about this or are these assets are going to, as leases roll off, sort of age out basically?.

Well, first off, I think it's important to note that in our guidance we reflected the challenging environment that you just, I think, very well outlined for rail. And then the other one is, is I think Willie addressed in his comments, we're looking to optimize our assets.

I think if you look historically at Plains, we've had a history of being able to repurpose assets, especially on the pipeline side and certainly where the concepts should apply as well as you suggest to the rail side.

On our pipeline side, I think we've got some pipelines that have moved north and then south and then north again, and in some cases 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're in the benefit of having both loading and unloading so that we're 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..

Yeah, I'll 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've 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. And we've got rail facilities in Bakersfield tied to pipelines, St. James Terminal, Yorktown Terminal, et cetera..

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

Thank you..

Next we'll go to line of Faisel Khan with Citigroup. Please go ahead..

Thanks. Good morning, guys..

Morning, Faisel..

is that just a base sort of 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 volume..

Well, it's definitely a multiplier. Willie, you want to....

Faisel, what number are you looking at again? Make sure I got your question..

Yeah, so the 2016 sort of crude oil pipeline volumes for the Permian Basin. 2.207 million I think versus 2.380 million..

I got it. Yeah..

I just want to understand if that's just a – is that a pure production decline, or is there something else across the system that's causing that number to be lower?.

Well, a lot of it is around lower expected growth than what we thought before, right? And 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 times to 3 times multiple on it.

So, if you think about the initial barrel that's produced in the multiplier effect, you could probably use to 2.5 times to 3 times across the Permian, and it would be a pretty good proxy..

And Faisel, just to make sure I'm clear on what you're asking, I mean, the quarterlies that we've shown on page five of the 8-K actually show growth throughout the year.

You're comparing the average for the year with the prior?.

Yeah..

Yes. Right. The prior guidance. Yeah..

Yeah. And so clearly, I mean – and you go back to where we were at 500 rigs, I think in the Permian we had of the 500 that we started off beginning of the year, I think we were about 205 to 207 rigs was what the average was for the Permian. We're running right now about 135.

So what we are anticipating and built into the guidance is that we expect to see in the tail end of 2016 volumes to fall because there's a time lag between you have rigs – and clearly, they're drilling more efficient, but the completions we're actually seeing are actually expect to tail off.

So yeah, if you took the difference in that average, and you probably divide it by some multiplier, you're going to end up basically with a lower level of expected decline for the Permian, but it's still going to be that amplified level of impact on Plains..

Compared to our original guidance, Faisel, our gathered volumes, the barrels that we first gather and sort of start the multiplier process are probably down – are lower than our original forecast by, say, plus or minus 40,000 barrels a day..

Okay. Okay. That makes sense..

The rest of it is just kind of a multiplier effect on those barrels..

Okay, got you.

And then I just want to understand also the guidance around the Western segment? There's nothing in there for the reactivation of the pipeline in Santa Barbara, is there?.

There is not. It's mostly tied to – the revision in the Western segment is mostly tied to the timing of the restart of the Torrance refinery..

Okay. Okay, that makes sense.

And then the Gulf Coast – the volumes' sort of trajectory being lower, is that just the asset sales? Is that what's causing that number to be lower?.

Yes. A big piece of it is..

Okay. Got it. And then just on Empress, I just want to make sure I understand. I mean, Empress has sort of been one of these set of assets that's been sort of feast or famine over the last, I don't know, decade or decade and a half.

Is there something that you guys can do between what you have already in Western Canada and this system to sort of stabilize the profitability of that asset?.

Faisel, I think, if you recall, we announced the acquisition of the BP facility, which got us our initial foothold into the Empress area. 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.

So there may be, in a given year, less upside, perhaps, than what there had been before.

But there should be a lot lower downside as well, wouldn't you say, Harry?.

Yes. And the assets are just complementary to the existing footprint that we have and provides sort of a unique set of synergies that are available to us..

Okay, got it. Thanks for the time..

Thank you..

And, next, we'll go to the line of Gabe Moreen with Bank of America. Please go ahead..

Hey, good morning, all. A quick question. I think in the last call you did a pretty deep dive on the counterparty side of things.

Anything changed on that front in the last three months and is any of that incorporated in your guidance?.

Yeah. No, we did do a deep dive. Last time we felt like we didn't 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've done for a long period of time. So no real change there, Gabe..

Thanks, Al. And then, Greg, in the comments you mentioned that the closing in terms of kind of swapping assets, both asset divestitures but as well as acquisitions.

In addition to Empress, any other areas you're really looking at in terms of, I would assume, doing sort of tuck in kind of acquisitions that look appealing?.

Yeah. I would say we're constantly in a state of analysis and review. I think we've 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 things are eminent or that would alert any of our potential competitors as where we're focused..

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

All right. And next, we'll go to the line of Jeremy Tonet with JPMorgan. Please go ahead..

Good morning..

Good morning, Jeremy..

I was wondering if you could help me think through the Canadian wildfires.

What impact do you see on the commodities side there for crude oil prices and nat gas prices, if you're comfortable sharing thoughts there and what impact that could have on Plain?.

Well, the longer the issue exists or is going to pull down inventory kind of similar situation happened last year and it had a pretty meaningful impact and drove prices up to close to $60 last year. I don't know if we'll see a repeat of that. But we're seeing that it is impacting some of the same crude operations up in that part of Canada.

There is no direct impact to any of our assets, but the movement in differentials could have a slight positive impact to us. But a lot of that is sort of – we embed that type volatility into our guidance to start with.

So I wouldn't say its meaningful impact to our guidance, but those are the types of things do cause product dislocations from time-to-time..

Yeah. I think, Jeremy, obviously, it's pretty early days in response to the event. So 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. But I do think we're fairly well-position.

We could certainly have parts of our business that are impacted negatively by differentials that we might've been expecting to make a profit on, on certain variable movements. But as Harry mentioned, there is 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 zero to 500 is what I've heard..

Yeah. A couple of hundred thousand barrels a day right now....

So that would impact, obviously, the inventory pull down as long as we didn't end up importing more on the water to replace it. There are certain parts, I mean, theoretically we should see incremental movements of cap line perhaps to help replace those barrels.

But again, that would probably be more of a foreign movement that comes in, so it wouldn't necessarily affect overall inventory but it would affect our movements on that pipeline..

Great. Thanks for that. And just a quick modeling question.

With the MVCs, have you guys identified which pipes those are showing up on and what the quantity there, I guess?.

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

Yeah. Jeremy, if I understood your question is – and I think Al just answered it, do we know which pipes it's 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 more than we forecasted in our original guidance. But that does have a multiplier effect because it can affect and does affect more than one pipe..

Yeah. 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 an MVC payment on, but it would've normally transferred onto pipeline B that we might not have an 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..

Got it. Appreciate the customer sensitivity, you don't want to give anything away there.

Is it possible at all maybe just talk about regions without pushing too hard here?.

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

Okay, great. Thank you for that. And I think previously there was talks about a soft guidance outlook for 2017 being about 10% higher.

And kind of 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 just kind of off a lower base? Realize you probably might spend on this more on the Analyst Day, but just wondering if you can provide us any thoughts there..

Don't really have any additional comments, Jeremy, to today's discussion. Like everybody else, we're trying to deal with kind of 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's 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.

So I think it'd 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've got a decent uplift in 2017.

I just hate to try and calibrate something right now 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..

Next we'll go to the line of John Edwards with Credit Suisse. Please go ahead..

Yeah. Good morning, everybody. Thanks for taking my question. I'm just – I guess, I'll just start off. In your guidance revision, just how much cost savings is baked into that if you can kind of give us an idea on the quantification there. I'll start with that one..

Yeah. Let me take that and others can add in if they'd like. We haven't gone out with a specific target. One of the things we're sensitive on is not trying to manage by objectives set at 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'll call ground-up cost savings. And the way I would characterize it is you see a lot in the – I mentioned a lot about managing people and supplier savings and contractors. We're seeing good progress from that. I would measure that in tens of millions, not hundreds of millions if that helps..

Yeah, that helps. Okay.

And then, 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 I guess that's what – I know a lot of people are asking about the exit rates for 2017, but is there anything you can comment there with regard to how we might have a look through to next year as well?.

I can't, so let's give you the look through the 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's remaining. So we built that in to our expectations.

I hate to fall back on the old adage, but we're clearly getting progressive through the cycle to the point where the best cure for low oil prices is low oil prices.

At some point in time, when this thing turns, we're going to end up where everybody is trying to figure out how do we move the more barrels that I think will be coming that need to be developed to respond to the gap in demand.

So again, I'd probably tell you there's certainly competition has – it's at least as intense if not more intense for that marginal barrel of the day, and that's 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 is – I'm not sure I can give you any high percentage comfort level that would be worth anything..

Okay. Okay. And then 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 it. Maybe you affirm that or maybe you have a slightly different take on that, just if you could provide us that..

Okay; that's helpful. That's it for me. Thank you..

Next we'll go the line of Brian Gamble with Simmons & Company. Please go ahead..

Good morning, everybody..

Morning..

Greg, you shouldn't sell yourself short. When you get something right like calling the crude per quarter, you should take a bow rather than (57:10) a dumb luck..

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

That's fair. That's fair. I did want to just kind follow-up on your last two answers, and you have answered it to a degree. But when you look at the level of activity, I guess, the discrepancy between your previous forecast and the current forecast, it kind of juxtaposed that against the volumes that are moving in various basins.

And I'm sure you've been keeping abreast of what the 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're drilling -- does that change any, I guess, long-term viewpoint of yours as to which asset or which region maybe 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've seen over the first four months are starting to influence your kind of long-term thought process..

I think probably the best way to answer is we try to use all available data to do what you're suggesting. How do we best position ourselves, where do we need to maybe make sure we have additional capacity if we start to see that a particular areas heating up.

And if we were having this discussion two years ago, one of the hottest areas was the Mississippi Lime. Today it's probably one of the weakest areas. And 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 the earnings seasons is just as probably busy for us as it is for some of the analysts because we try to take the 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're tracking everything that's going on, not by area, but by county, 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 revision's up, et cetera.

There are BOE and there is a big portion of gas in there. Gas increases don't help us. If it's in an area that it's on somebody's acreage that they've dedicated under an acreage commitment to somebody else, if there's 10,000 barrels a day of have extra production, it may not help us at all.

On the other hand, if it's in an area where that's either up for grabs or on our acreage, it has a big impact. So the short answer is we use all that data.

I think as we sit here today trying to correlate press releases and people tweaking guidance, 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.

And they may be telling us privately it's 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 tried 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 our – at least our guidance right now is the best estimate that we have with 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. And just a follow-on with that, and if you don't have an answer or you don't want to answer it, fine.

But is there one data point or a couple data points so far that have surprised you in this kind of earnings go-through?.

Not really. Not really. I mean – and 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. And somebody's making up the other side of those averages. And 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's up in an area, it must be true for everybody.

In some cases, you guys are analyzing the best of the best and there's some others out there that either don't have as good a quality of acreage, their technical skills aren't quite yet up to the standards of some of the others. And so there's a reason why there is an average number. It's because somebody is above it and somebody is below it..

Thanks for those comments, Greg. Appreciate it..

Thank you, Brian..

All right. And next we'll go to line of Steve Sherowski with Goldman Sachs. Please go ahead..

Hi, 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. And 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'm just wondering how much of that 40,000 barrel revision was driven by competition versus just lower production expectations..

I don't remember the 40,000....

And then there's a – I believe you said it'd take 40,000 barrels a day, and then there's multiplier effect for....

That was on the pipeline lease – 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 15,000 to 20,000, yeah..

15,000, 20,000 barrels just for those....

Yeah, I think that was in the guidance, 15,000..

Okay. Got you.

And then – so on the 15,000 I guess then 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. So....

On the competition side, Steve, think of it as a tug-of-war. I mean, we pull barrels and somebody else pulls other barrels because, again, we're still competing in some cases against these over-commitments on the ship or pay for other pipelines. So margins have been heading down as that tug-of-war goes on.

But I think most of the change – we assume we're probably going to continue to net 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 where you can kind of correlate those two numbers..

Yeah..

Got you. And just a quick follow-up. I think it was Marathon was out recently talking about a cap line or bringing up the cap line reversal again. I guess, just any update on that and where you think crude prices would need to go -- or production, rather, whatever is the driver -- before a decision would be made..

Not much more to add to what we've said. I think what you read in the press is about all that anybody knows at this point in time. We're big fans of thinking 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's really not related to prices..

Got you. Okay. Thank you..

All right. Next we'll go to the line of Sunil Sibal with Seaport Securities. Please go ahead..

Hi. Good morning, guys. Thanks for taking my 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 assumptions there and how they're moving around.

I think you earlier talked about a $12 million-or-so OpEx, a one-time kind of a gain in the first quarter.

In addition to that, are there any other kind of big drivers of margins as we think about the remainder of 2016?.

Yeah, so the $12 million was a combination of operating expenses and inventory costing. So on the Transportation segment, it's $7 million, $8 million. 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 contract or basically a tariff on the pipelines, I presume, correct?.

Yeah, 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 the commentary where you have – a shipper can ship one month and not ship the next month if they're not committed volumes.

Most of the committed volumes are just related to the new construction..

Yeah, Sunil, the way I think about it is it's purely volumes offset by – we've got a good chunk that we get to book MVC gains on. So it's just volumes times the tariff offset by the MVC volumes that we have for the year, if that was your question..

Okay.

And the volume assumptions, of course, have MVCs in them, right?.

Yes. Yeah..

Okay, got it. And then on – thanks for clarification on the rig count. I was just kind of curious with your updated guidance that was provided today.

Yesterday, the 330 rig count in April, is that – what's kind of assumption for the remainder of the year for the rig count, if there is something?.

It's basically held in that range, Sunil. There's trade-offs in there. I mean, 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 duck completion.

So we've tried to build in, for example, that while rigs are coming down, we actually think some of the duck completions are going up, especially if these prices have rallied a little bit. So I'd say, we're 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's come down quite a bit and you've 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. And then I think on your CapEx program, you mentioned that you sanctioned some additional storage additions.

I was just kind of curios, is there anything specific in those contract terms that you signed for those additions with the Regina deal, how you have contracted in the past?.

No. I mean, again, we're fundamentally focused in on long-term customers. And I think – and we had actually tank additions at Patoka, Cushing and St. James, and I think they were all with the same type of activities we've had before; good long-term customers that are going to use it operational as opposed to financial-driven people at all.

It's more operational people..

Okay, that's helpful. And then just one last clarification for me on the leverage metrics that was provided to 4.2x debt to EBITDA at the end of Q1 2016.

Is that fairly representative of how your covenant are in terms of the leverage metrics, or are there any big deltas there that we should be aware of?.

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

Okay, got it. Thanks guys..

Thank you..

Next we'll go to the line of Selman Akyol with Stifel. Please go ahead..

Thank you. Good morning. 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?.

Well, I think – so this is really the first quarter that we started seeing that number climb up. We used to have some MVCs late last year where we had maybe some that just started, but a lot of our projects, Selman, are really just not going into service in the last, call it, six months probably, where it would become an issue.

And that's why the dialogue that we've had over the last couple of quarters has been people had asked us how are you going to handle that if volumes aren't there, and so we finally landed on this approach that we shared right now. So there's really not a lot of history to compare to because it's just now recently become into vogue again.

As Harry mentioned, you don't really have existing MVCs on a pipeline that's been built 30 years ago. It's really only the recent ones, and we've just started putting these into service here recently..

one, weather related; two, increased competition; and then not explicitly sort of the multiplier effect as well.

So 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 Logistic as being sort of a $500 million run rate business?.

Well, you really have to – it's really hard to move quarter to quarter because first and fourth quarter are impacted so much by the NGL business.

All your margins are in the first and fourth quarter, and the second and third quarter usually there's minimal margin because you've got the carrying costs, you've storage costs, and you don't have much NGL sales. So looking from Q1 to Q2, it's really hard. You just look at the crude oil business, it's typical (1:11:57) or something like that....

Yeah. If you look on slide 11, I think you'll see the – we've shown that kind of a seasonal horseback or – and that's been there in prior years, so you would've always seen that margin projected to move down from first quarter to second quarter in the same direction..

Selman, 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 is $1.02. So it's kind of an $0.11 change. That does reflect the competitive pressures we're seeing on the crude side that we discussed earlier..

And so really not a multiplier effect on the Supply and Logistics. The Supply and Logistics drives the multiplier effect on Transportation..

Yeah. And something I'd looked at – if you're looking at slide 12, first-quarter to second quarter, almost all of that is the NGL seasonal sales primarily around Canada..

All right. Thanks very much..

Thanks..

Thank you..

All right. And next we'll go to the line of Charles Marshall with CapitalOne. Please go ahead..

Hey. Good morning, everyone..

Good morning, Chuck..

Actually, it looks like natural gas storage is getting some more air time today given some positive trends you're seeing in the fundamentals. And you guys had a pretty solid recontracting season at your Louisiana facility. We saw the 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 just what potential commercial opportunities you'd consider to further optimize these assets? It would be helpful, just any general color..

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

Hey, Chuck. What we're seeing, to your point, is a pickup 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're really holding a lot less for ourselves, probably less than 10%. So I think the interest is more around operational customers going forward versus financial players, though it is very positive, but it is location specific..

And Chuck, as you probably know from your first hand knowledge, we try to attract not only what our activity is in terms of actual deliveries and storage activities, but also at other facilities. And we're pretty pleased that Pine Prairie has developed into probably one of, if not the most active fiscal hub out there.

And we expect that perhaps to continue to be the case, if not amplify, as we continue to see LNG in exports because it's just sitting in the best position. And again, as you know kind of from first hand, we've put a lot of compression out there to be able to handle that.

And I just don't know if anybody is in any better position than we are, both geographically and then physically and operationally..

Thanks for that color.

And just one follow up, with increased demand activity, do you see any future need to increase storage capacity, or are these levels are you comfortable?.

We're watching it pretty closely..

Okay, thanks guys. That is it for me..

Thank you..

All right. And 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 conclude our conference for today. Thank you for your participation. You may now disconnect..