Ryan Smith - Plains All American Pipeline LP Greg L. Armstrong - Plains All American Pipeline LP Harry N. Pefanis - Plains All American Pipeline LP Willie C. W. Chiang - Plains All American Pipeline LP Alan P. Swanson - Plains All American Pipeline LP.

Kristina Kazarian - Deutsche Bank Securities, Inc. Shneur Z. Gershuni - UBS Securities LLC Jeremy B. Tonet - JPMorgan Securities LLC Brian D. Gamble - Simmons & Company International Harry Mateer - Barclays Capital, Inc. Vikram Bagri - Citigroup Global Markets, Inc.

(Broker) Becca Followill - USCA Securities LLC Ross Payne - Wells Fargo Securities LLC John Edwards - Credit Suisse Securities (USA) LLC (Broker) Danilo Juvane - BMO Capital Markets (United States) Robert Balsamo - FBR Capital Markets & Co..

Welcome to the PAA and PAGP Third Quarter 2016 Results Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session with instructions 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, Nelo. Good morning, and welcome to Plains All American Pipeline's third quarter 2016 earnings conference call. The slide presentation for today's call can be found within the Investor Relations and News & 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 within the Investor Relations and Financial Information section of our website. Today's presentation will also include selected financial information for 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-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 of 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 now turn the call over to Greg..

Thanks, Ryan. Yesterday PAA reported third quarter results and adjusted EBITDA coming in at $450 million, which is at the low-end of our guidance range.

Performance from our fee-based Transportation and Facilities segments was in line with, to ahead of the midpoint of our guidance, while the Supply and Logistics segment came in below the low-end of our guidance. Harry, will provide additional details regarding PAA's third quarter performance during his portion of today's call.

But the variance in the Supply & Logistics segment is primarily associated with the delayed recognition of EBITDA from NGL-related activities due to inventory costing and the timing of crude oil inventory sales, aggregating approximately $30 million, as well as continued margin compression and less favorable market conditions for both crude oil, lease gathering, and NGL businesses.

There were a number of smaller offsetting items during the quarter, but adjusting solely for the EBITDA deferral, overall reserves for the third quarter would have been right at the midpoint of guidance. A comparison of PAA's 2016 third quarter results, the guidance and last year's third quarter is provided on slide 3.

Looking forward, we believe it will continue to be challenging in the near team, but we are starting to see encouraging indications that the current industry cycle has reached the bottom, as well as green shoots of recovery that should bode well for PAA. I want to highlight four of these positive indicators, which are summarized on slide 4.

First, there's been a meaningful pickup in the crude oil rig count, particularly in the Permian Basin, where PAA has its largest asset concentration. The most recent lower 48 onshore rig count was around 490 rigs, up approximately 60% from the lows reached in mid to late May.

Notably, there are more rigs working in the Permian than the five largest U.S. crude oil regions combined. And, additionally, if you combine the Permian and STACK area where PAA has a large presence, the rig count in these two regions exceeds the number of rigs working in all of the remaining U.S. onshore areas combined.

Activity levels within the Permian and STACK appear to be sufficient, not only to offset production declines, but also to generate meaningful economic growth within those areas.

Other areas such as the Williston, Eagle Ford, and DJ are still declining but in the aggregate, we believe we are only 80 rigs away from activity levels sufficient, sustaining existing onshore U.S. crude oil production.

Second, producers have continued to improve their overall efficiency both in the drilling and completion phases, which has lowered the crude oil price necessary to sustain economic development programs. And producers have also been delineating and extending known-producing horizons in the aerial (4:27) extent of the resource base.

As a result, many producers are demonstrating their level of conviction by acquiring acreage within their respective core areas, especially within the Permian Basin, where some producers have paid as much as $40,000 per acre to $50,000 per acre indicating that they are serious about increasing and sustaining higher rig counts.

Importantly, these producers have been financing their purchases with large equity issuances, keeping their balance sheets in good position to support these drilling objectives. Third, U.S. crude oil inventories, which have remained stubbornly high throughout July and August, have declined in seven weeks out of the last nine weeks.

And last but not least, Saudi Arabia, the rest of OPEC and Russia have been making public comments indicating they are planning or certainly willing to consider reducing crude oil production by roughly 0.5 million barrels per day to 1 million barrels per day.

Although, the prospects for such a reduction seem to change at almost daily basis, the shift in conversation is directionally significant to some level of production catch or even restrained in combination with ongoing demand growth, would facilitate the normalization of inventory levels, which we believe is a critical component of a sustainable recovery.

We believe all of these developments are positive for PAA in the intermediate-to-long term. That said, within the midstream sector, there is a time lag associated with the tangible benefits of certain of these activities in development. The positive impacts on U.S.

production and marginal barrel competition within the midstream sector will likely take time to manifest themselves.

As a result, we anticipate that ongoing challenges associated with production declines, patent competition and margin compression will continue for the next nine months or so, and we have incorporated these conditions into our guidance for the balance of 2016 and our preliminary guidance for 2017.

As Harry, Willie and Al will reinforce over the balance of today's call, we believe PAA is positioned to navigate challenging near-term conditions and benefit significantly from the impending interest recovery, as well as potential industry consolidation.

This belief, with respect to PAA's outlook, is underpinned by several factors, including PAA's leading position in the Permian and STACK areas and its top-tier positions in the other major crude oil-producing regions within the U.S. and Canada.

Second, PAA's improving cash flow profile associated with placing several fee-based capital projects in service that are supported by minimum volume commitments and other forms of contractual support, as well as increased utilization of existing pipeline capacity.

And, finally, PAA's financial and liquidity position, which has been and continues to be enhanced by the pending simplification of our overall capital structure, recent and pending asset sales and recent equity issuances under our continuous offering program. Overall, we are optimistic about PAA's outlook. With that, I'll turn the call over to Harry..

Thanks, Greg. During my portion of the call, I'll review our third quarter operating results compared to the midpoint of our guidance, and I'll provide an update on our 2016 capital program. As shown on slide 5, adjusted segment profit for the Transportation segment was $295 million, or approximately $5 million, above the midpoint of our guidance.

Volumes were approximately 4.6 million barrels per day and were in line with our third quarter guidance.

Transportation adjusted segment profit of $0.70 per barrel was $0.02 per barrel above the midpoint of our guidance, and this slight over performance was principally due to approximately $4 million of business interruption insurance proceeds accrued during the quarter and collected in early October.

Adjusted segment profit for the Facilities segment was $171 million, which was approximately $24 million above the midpoint of our guidance. Volumes of approximately 131 million barrels of oil equivalent per month were essentially in line with our guidance.

Adjusted segment profit of $0.43 per barrel was $0.05 per barrel above the midpoint of our guidance, primarily due to a higher than anticipated throughput at several of our facilities including our St. James terminals, our Eagle Ford condensate processing facility and our gas storage facilities.

We also experienced lower than forecasted operating expenses, which were primarily related to lower utility costs and the settlement of the property tax assessment. There were also some timing related matters and we expect those costs to incur in future period.

Supply & Logistics results came in at a loss of $17 million, which is approximately $55 million below our guidance. Volumes of approximately 1.1 million barrels per day were in line with that guidance. Segment loss per barrel was $0.16 per barrel, which was approximately $0.53 per barrel below the midpoint of our guidance.

The segment loss per barrel was due to a combination of delayed EBITDA recognition associated with NGL inventory costing and the timing of certain sales. Together, these total approximately $30 million. This amount is expected to be recognized in the fourth quarter this year and in the first quarter of next year.

In addition, the lack of volatility combined with margin compression for both our NGL and crude oil activities comprised the balance of the short fall in this segment. Moving on to our capital program, slide 6 provides a summary of our 2016 capital program including anticipated and service stage for each project.

The Platteville, Colorado to Cushing, Oklahoma segment of the Saddlehorn Pipeline was placed into service in late August. (9:49) Platteville, Colorado segment of the Saddlehorn Pipeline is expected to be completed by the end of the year.

I would also note that our Red River and Caddo Pipeline systems have slipped a couple of months due to heavy rains that we experienced earlier in the year, but both pipelines are expected to be completed and in service by the end of the fourth quarter.

Additionally, with respect to our Diamond Pipeline joint venture, we have all the necessary permits in place and we have begun construction. We expect the line to be in service in the fourth quarter of 2017.

Lastly, maintenance capital for the third quarter was $47 million, and we expect maintenance capital to be in the $175 million to $185 million range for the year. And, with that, I'll turn the call over to Willie..

Thanks, Harry. Good morning. During my portion of the call, I'll provide a brief update on our non-core asset sales and discuss our operating and financial guidance for the fourth quarter and full-year of 2016.

As summarized on slide 7, we have now completed eight transactions with net sale proceeds of approximately $550 million, which is right in the middle of the $500 million to $600 million guidance range for 2016 non-core asset sales.

Since our last conference call, we completed a partial interest sale to a strategic partner with the formation of STACK Pipeline LLC, which is a strategic 50/50 joint venture pipeline with Phillips 66 Partners.

I'll also note that our Richmond and Martinez terminals are now under contract to an undisclosed buyer, and we're currently working through the necessary regulatory approvals required for closing. Now, as a reminder, this transaction would be incremental to the $550 million that we have completed.

We've been very pleased with the results from our assets sale efforts to-date, and we continue to evaluate additional transactions, both non-core assets and potential sales of partial interest to strategic partners. As Al will address in his part of the call, we have excluded the cash flows from these assets from our preliminary 2017 guidance.

We look forward to providing an update on our pending sale, as well as potential additional sales in the coming months. I'm now going to move to slide 8 and discuss the operating assumptions used to generate our guidance for fourth quarter 2016 which we furnished yesterday.

For our Transportation segment, we expect volumes to average approximately 4.65 million barrels per day, or an increase of approximately 40,000 barrels per day from the third quarter. Notably, our Permian Basin pipelines are forecasted to increase by approximately 90,000 barrels per day in the fourth quarter.

But a portion of this increase is expected to be partially offset by lower volumes on our Gulf Coast pipelines, particularly our interest in Capline. We expect adjusted segment profit per barrel to be $0.62 per barrel or $0.08 per barrel below the third quarter.

This is primarily due to anticipated fourth quarter MVC billings to be in less than third quarter due to MVC invoice timing differences and higher operating expenses which are primarily timing related.

For our Facilities segment, we expect an average capacity of 132 million barrels of oil equivalent per month, or an increase of approximately 1 million barrels per month from the third quarter.

The increase in volumes as compared to the third quarter is primarily the result of the Canadian NGL acquisition that closed in August, partially offset by lower rail volumes. We expect adjusted segment profit per barrel to be $0.41, or $0.02 per barrel lower than the third quarter.

The decrease in segment profit per barrel is attributed to higher forecasted operating expenses, again, primarily due to timing. For our Supply and Logistics segment, we expect volumes to average 1.3 million barrels a day, or an increase of approximately 170,000 barrels a day from the third quarter.

The anticipated volume increase is reflective of the seasonal impact of our NGL sale volumes. We expect adjusted segment profit per barrel to be $1.41 or $1.57 higher than the third quarter.

Although we expect continued challenging lease gathering margins in the fourth quarter, the segment profit per barrel increase is due to the anticipated seasonal uplift associated with our NGL business during the winter months and the recognition of a portion of the deferred EBITDA originally anticipated for the third quarter, which Harry discussed just earlier in the call.

As shown on slide 9, the midpoint of our fourth quarter adjusted EBITDA guidance is $594 million. This slide also provides a directional illustration that serves as a reminder that our full-year adjusted EBITDA profile is U-shaped in nature due to the inherent seasonality of our NGL business.

Moving on to slide 10, we have revised the midpoint of our 2016 adjusted EBITDA guidance downward by approximately 2% to $2.125 billion, primarily due to the lower-than-expected volume growth in our Transportation segment and lower Supply and Logistics revenues due to less favorable market conditions, general margin compression in both our crude oil and NGL businesses and the shifting of some of our NGL margin in 2017.

This is offset by stronger revenues in our Facilities segment due to more favorable storage revenues and lower operating costs. For more detailed information on our 2016 guidance, please refer to the Form 8-K that was furnished yesterday.

Now, before I hand it over to Al, I want to take a minute to address Permian takeaway capacity, which has really generated a lot of interest recently. Current takeaway capacity from the Permian is approximately 2.5 million barrels a day, including regional refining capacity.

We expect that there will be an additional 700,000 barrels to 800,000 barrels a day of nameplate capacity available. This consists of Enterprise's pipeline scheduled to be in service in 2018 with an expected initial capacity of 300,000 per day.

And beyond that, we believe there's an additional combined 400,000 barrels per day to 500,000 barrels per day of capacity on a number of Permian takeaway pipelines that could be achieved by adding pump stations, which could be done quickly and at a low cost.

This would take the Permian Basin takeaway capacity to approximately 3.1 million barrels a day to 3.3 million barrels a day in a very reasonable timeframe as compared to current production levels of approximately 2 million barrels a day.

Timing for additional takeaway pipelines will be dependent on the pace of the Permian production growth, quality of that crude and segregation needs, as well as available markets which are driven by global crude oil demand growth. With that, I'll turn the call over to Al..

Thanks, Willie. During my portion of the call, I will review our financing activities, capitalization and liquidity, as well as discuss our preliminary 2017 guidance. As illustrated on slide 11, PAA sold 10 million units in the third quarter for net proceeds of $289 million through the use of our continuous equity offering program.

Total net proceeds since starting the program in August 2016 are $443 million. As illustrated on slide 12, at September 30, 2016, PAA had long-term debt-to-capitalization ratio of 51%, a long-term debt-to-adjusted EBITDA ratio of 4.5 times and $2.5 billion of committed liquidity.

While our long-term debt-to-adjusted EBITDA ratio remains elevated relative to historic levels and our targeted range, we are committed to reducing this leverage ratio and expect to return to the targeted range over time as we benefit from capital projects coming on line, proceeds from additional asset sales, retained cash flow as a result of the distribution reset, equity issuances under our continuous equity offering program and from meaningful cash flow growth that will come with an industry recovery.

In early September, we added a Fitch credit rating, which is an investment-grade rating of BBB flat. We chose to add the rating after considering feedback from a number of stakeholders, including fixed-income investors. For over 15 years, our financial strategy has been for PAA to be an investment-grade entity.

We remain steadfast in our commitment to investment-grade. I think it is important to note that we did not add the third rating with a view that we would let one of our existing ratings fall below investment-grade. We are committed to and intend to maintain investment-grade ratings at all three agencies.

In the guidance 8-K that we furnished yesterday, we also provided preliminary guidance for 2017.

As in past years, we will provide more detailed 2017 guidance on our next call in early February, which will incorporate updated information on OPEC actions, the crude oil market, midstream competition levels and a more informed forecast of producers' 2017 capital programs and drilling plans by region.

Based on the information currently available to us, as illustrated on slide 13, we expect 2017 adjusted EBITDA will be plus or minus $2.3 billion with implied DCF of plus or minus $1.6 billion, which generally reflects a continuation of a challenging midstream environment in 2017 with improvement lagging until later in the year.

Relative to forecast disclosed early in the year, adjusted EBITDA reflects reductions associated with the impact of incremental asset sales and assets contributed to joint ventures, which are reported under the equity method of accounting.

The impact on DCF was partially offset by associated reductions in maintenance capital and adding back distributions in excess of PAA's share of joint venture income. Additionally, we expect our 2017 organic capital program to range between $500 million and $700 million, a significant portion of which is associated with the Diamond Pipeline.

Please refer to the 8-K for additional information. As Greg mentioned earlier, there have been recent indications that the current industry cycle for crude oil markets has stabilized and upstream activity levels are increasing in certain areas, particularly the Permian and STACK regions.

Certain of these positive developments will impact the midstream sector on a delayed basis. In areas outside the Permian and STACK, we expect continued production decline through mid-2017 with meaningful production growth not resuming until 2018. On balance, we anticipate that the next nine months or more will be challenging for the midstream sector.

We see increasing competition for the marginal crude oil and NGL barrel and uncertainty on the pace of recovery across producing basins, both of which impact timing for the midstream sector recovery. Additionally, U.S.

crude oil inventories remain higher than our prior forecast and remain at approximately 30 million barrels above last year and approximately 140 million barrels above the five-year average from 2010 through 2014. We believe this inventory overhang may affect the timing of the industry recovery.

Accordingly, such factors have been incorporated into our preliminary guidance for 2017.

Additionally, as noted in our 8-K furnished yesterday, the assumptions we incorporate – used to incorporate our belief that as production growth returns in certain basins impacted by MVC over contracting, the first barrels will go to fill current MVC shortfalls on either PAA's or competitors' pipelines and, therefore, will not have a linear impact on Transportation revenues.

Accordingly, we believe the margin improvement and ultimate benefit to the midstream sector will lag production growth in certain basins and definitely vary between basins.

With that said, while we remain cautious in the near-term, we are increasingly bullish on the outlook for significant production growth in the Permian Basin and that this production growth, when combined with certain MVC explorations that we believe will begin in late 2017 and 2018, could result in meaningful improvement to our outlook for 2018.

Before I turn the call back to Greg, I wanted to address one additional item. We have received several questions related to the 2017 preliminary guidance we furnished yesterday and the various forecasts that were included in PAGP's proxy.

The nature of the questions, which are generally focused on what has changed since our last proxy filing, suggests that there is a misconception that the forecast cases in the proxy were brought forward and updated or reaffirmed through the respective date of each proxy filing with the last filing being approximately four weeks ago.

As discussed in the detail in the background and projection sections of the proxy statement, the three initial cases were developed roughly six months to seven months ago in the March to April timeframe based on the facts and circumstances that existed at that time and through refinements and variations of PAA's then existing business plans which was, in turn, developed in late 2015 and finalized in January 2016.

In connection with our simplification discussions, a sensitivity case was developed in June. These four cases are snapshots of the forecasts that were reviewed and analyzed by the GP and LP representative and their advisers, leading up to the simplification announcement in early July.

As is indicated in the proxy, these forecasts were not updated or brought forward in any public filings.

As I noted earlier and also discussed in the 8-K furnished yesterday, our 2017 preliminary guidance is, however, based on current forecast and take into account recent developments, our current industry views and changes in PAA's asset mix, including asset sales not contemplated previously, and the forecasts were generated nearly six months ago.

As a result of certain of the asset sales activity Willie discussed earlier, as well as other factors, the preliminary 2017 adjusted EBITDA guidance of plus or minus $2.3 billion is approximately $100 million, or 4% below consensus sell-side estimates of approximately $2.4 billion.

Our preliminary 2017 DCF guidance of plus or minus $1.6 billion is in line with consensus sell-side estimates.

As we have in prior years, we intend to provide detailed 2017 guidance by segment on our call in February, which will incorporate the most current data that we have at that time, including more definitive information on producer outlook for capital budget and crude oil volume growth in each of the various regions that we service.

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

Thanks, Al. We are two years or more into the current industry downturn depending on where you pick the starting point.

In general, the impact has been more severe on PAA than we would have anticipated a few years ago, in part due to infrastructure overbuild but, more critically, the significant level of contractual over commitments that has intensified the level of competition for the marginal barrel.

We are seeing encouraging signs that we are at or near the bottom of the downturn, but we do not believe PAA or anyone else has an accurate crystal ball that can predict the term with any precision.

In response, PAA has taken a number of steps to manage and mitigate the adverse impacts of a potential extended downturn on its business and financial condition, which are summarized on slide 14.

These steps include reducing capital commitments through scope changes and project deferrals, selling core assets and entering into strategic joint ventures, which collectively have raised approximately $550 million of cash proceeds, reduced PAA's capital commitments by approximately $600 million and in the process secured complementary partners and shippers on our assets.

There was also secured $1.6 billion of non-conventional financing, and we've intensified our efforts to capture incremental gathering and transportation barrels.

And then, finally, we're lowering PAA's incremental cost of capital by executing an agreement to eliminate its incentive distribution rights and connection there with resetting the distribution from $2.80 to $2.20 per unit, which resulted in a $320 million annual reduction in cash distributions.

Although these actions have had a decided positive impact on PAA's positioning. And it appears that we have seen or approaching the bottom of the down cycle, execution challenges do remain. Importantly, we believe PAA's position to manage through the balance of the down cycle, capitalize on available opportunities and benefit significantly as U.S.

and Canadian oil production increases. More specifically, PAA has significant liquidity and a competitive cost of capital.

It's positioned to reduce leverage via increasing cash flow from project completions and step-up in fee-based contractual commitments, asset sales and prudent equity issuances, and it's leveraged to a recovery in production volumes with existing pipeline capacity that will result in significantly increased cash flow with low-to-no incremental CapEx when the inevitable recovery does take place.

Although our tone and positioning for the near-term is cautious, our tone and outlook for the intermediate and long-term is decidedly positive, especially as it relates to the Permian Basin where PAA has its largest concentration on its assets. We appreciate the participation in today's call and for the investment in PAA and PAGP.

With that, now, I will turn – open the call up for questions..

Certainly. Our first question is from Kristina Kazarian with Deutsche Bank. Please go ahead..

Good morning, guys..

Good morning, Kristina..

Can you guys talk a little bit about how to think about calendar year 2017 guidance versus the green shoots that you talked about seeing, particularly Permian and STACK? I guess, essentially, what I'd like would be some color on underlying assumptions, maybe rig count, production levels, commodity prices? I know I'm asking for a lot here, but how I frame up 2017 with those numbers in my mind?.

Kristina, again, with 2017, we've given kind of indications of guidance. We call this preliminary shadow guidance for reason that we're still trying to finalize those inputs. We certainly run a number of cases that get us comfortable with that range, both above and below. What we're really waiting for is more data.

With you, we're listening to many producers' phone calls, as well as having discussions with them. And what we saw last year candidly is what they thought they were going to do in November and December of the year changed dramatically in January and February by the time we got to our call and we're outlining guidance.

So, at this point in time, we're not providing that level of granular detail. What we will do, as we always have, in our February call, is we'll provide a detailed level, sharing with you as we do where we think volumes are going to come and from what areas and what the inputs are with respect to the rig count, et cetera, by area..

Okay. That makes sense. And, now, my follow-on is what I'm thinking about next year on the capital use side as well.

Can you maybe talk – you mentioned in your comments about continuing to look at asset divestitures and then also maybe touch on how I'm thinking about using the ATM going into 2017 because 4Q, I used it a lot more than I had in past quarters. So, just any on either of those two would be great..

Yeah. One thing – I just – Harry handed me a note. One thing that we are robust about on our 2017 outlook, I think we've got Permian going up about 300,000 barrels a day, which is about 15% by the end of the year.

And so, it's kind of angled up throughout there – the pace of that is something we're still playing with, trying to figure out really exactly how's it going to play out. As far as the issue on asset dispositions, obviously, Willie has updated you with respect to our West Coast assets.

What we – we've been pleased with the values that we've been seeing. We clearly found pockets where assets in our hands generate X in terms of cash flow and then the buyers' hands can generate X-plus. And, in some cases, the buyers have had a cheaper cost of capital. So, the level of accretion to them is disproportionate.

We're beginning to look at things that we consider to be not core and see if we can find more of those pockets. And so, we dialed in that outlook into our view combined with our desire, as Al said earlier, to deleverage. We'll continue to use what I would call a prudent level of the ATM. Obviously, that's price-sensitive.

It's market-sensitive and it's – if we turn around and we sell a significant amount of assets, that would change our view as to how much we would need to sell in terms of the ATM.

But with the elimination of the GP IDRs and the cost of capital is a lot less burdensome, before, we used to have to add effectively a 50% burden or almost 100% match on any incremental equity that we put out. So, we'll look at it prudently. We certainly want to protect our investment-grade, and we intend to do that..

Perfect. Thanks, guys..

Thank you. And we go now to Shneur Gershuni with UBS. Please go ahead..

Hi. Good morning, guys. I don't want to spend too much time on the cases that were presented in. I recognized the comments in the prepared remark that they're effectively stale.

Just wanted to understand so that we can compare from an apples-to-apples basis, I was just wondering if you're able to quantify how much the asset sales that closed after those cases were presented kind of impacted those numbers, if you want to look at it apples-to-apples, and how much is related to the S&L margins being difficult versus kind of your volume outlooks?.

I can't provide you the granular level of that for a couple of reasons. Obviously, we're still in a process of selling some of those assets and just competitive users would tell you, don't show all your cards and – but from a standpoint, obviously, those are the two primary items. I mean, we continue to be frustrated probably is a decent word.

The margin competition level is very intense when we do lose barrels or fail to protect margin. What we're seeing is our competition, in most cases, are buyers that have significant commitments and they're trying to fill the barrels.

And so, I think we highlighted that in a prior call or two and it's a new phenomenon, and we're still wrestling with how to accurately forecast that. Clearly, the market's been tougher than what we have seen or what we forecasted previously. So, we're still trying to calibrate that.

But as far as trying to reconcile that, the one thing I would point out is, I think Al touched on it, is there's a step-down in EBITDA versus kind of what our case would have been before.

Part of that's asset sales, part of it is margin, but then there's some offset in – we're selling some of the higher maintenance cost property, so the maintenance CapEx is actually – so the impact, I think, even though we're down on EBITDA relative to consensus, I believe our DCF is actually still right on top of the consensus DCF..

Okay. And as a follow-up question, when I think back to the Analyst Day and the presentation that I believe Jeremy gave, with the scenario A, B, and C, and I think with scenario B, you gave actually quite a bit of detail about rig counts that you would expect in how many months in a cycle and so forth.

I was wondering if you – instead of trying to pull out your crystal ball for 2017, rather, if we can go back and say, how are you tracking relative to scenario A, B and C? Is it a little bit better than B? Is it worse? When I think about the rig counts that you have sort of laid out for the Permian, Eagle Ford, Wolfcamp and the DJ, it seems like the Permian is running far ahead of that.

Commentary from the producers has been really strong and the productivity seems pretty good, but Eagle Ford seems to be a little bit behind.

I was wondering if you can sort of give us a little bit of color as to which scenario do you think you're tracking closer to and how should we thinking about general volume recovery, just sort of based on that?.

Yeah. As far as – I mean, the bright spot really is the Permian, and we're seeing the rig count in that area, especially of recent scenario is above scenario B.

It's not quite as robust as scenario A was but – and then the other area kind of more microscopic would be the STACK, which is an area that we think we'll see fairly very significant volume growth that starts from a low base, but then (35:54) just on absolute terms over the next two years or three years. We're feeling unbelievably good about it.

The challenge there for a midstream entity is, unfortunately, it's so close to market. We don't get as much compensation for transporting short distances. We would from areas that are farther out such as the Eagle Ford and the Williston and the Permian.

As far as the rig counts for the areas outside of the Permian and the STACK, they're either flat to down to the B case, a major variable – anytime we make a forecast is the DUC inventory building or declining.

What we're seeing right now is if you extend it from our case A, B, C and you look at case B, clearly, in the Permian, I think we're trending at or above of that forecast because of the rig count. In the other areas, and even in cases where the rig count is about the same, we're actually trending below in terms of volumes.

I think we're – a lot of numbers. Data always lags a little bit. But the Williston and Eagle Ford, if they're not below 1 million barrels a day, they're perilously close to that whereas we would have had it slightly higher than that.

And so, what we're trying to do is figure out what the recent price rally, the inventory rally Al mentioned, seven weeks out of nine weeks, it was the draw. The problem is, this last week, we gave back eight weeks' worth of draw and we're right back where we were at September 3.

So, are we cautious in our outlook for 2017 because of those factors? Absolutely. Are we prepared to be surprised? We want to be, okay. What we want to be is give you the best read that we possibly can because we're playing a long-term game that we have to disclose short-term results on.

But the important thing is how do we perform over the next two years, three years to five years. And we think we're set up to do very well. The Permian probably gets mentioned a lot.

And if this was a drinking game on any of the phone calls, my guess is everybody would be pretty weak-legged walking down the street because Permian is the hottest area, if not in the United States, probably in the world.

And I think everybody around here, if you're doing over and under at 3 million barrels a day, our hands are going up at over 3 million barrels a day. If you do it at 4 million barrels a day, a lot of them are still going up.

The question is when is that going to happen? And, unfortunately, we're probably guilty of giving more granular guidance than perhaps many of our peers. And so, we're forced to take a view on kind of what's going to happen when.

If we're talking 2018 or 2019, again, a lot of hands are in the area and we're trying to figure out was it first half or second half. Here, we're trying to figure out which month is it going to happen in 2017. So, again, our intent is not to convey a tone of negativity.

Our intent is to say it's cautious in the near term because we can't predict when it turns, and it's extremely positive once you get beyond that. It's just a question of how long is that – is this thing V-shaped bottom or a U-shaped bottom that we're in.

And, right now, it feels like it's a U-shaped bottom in our view because of inventory and the absence of a clear agreement beyond the United States' boundaries to reduce production when demands kind of struggling to grow.

I think it's not quite totally related, but it does impact us as we need to get through some of these MVC commitments for margins to get back from more normalized levels and until that occurs, margins are going to be stressed..

Fair enough. And one final question, if I may.

What kind of capacity utilization would you like to see in the Permian, or what level would you needed to be for spreads to start to improve so that the margin performance at S&L can improve with it?.

Well, 99.9% of utilization would be an outstanding number. As a practical matter, that would be too tight for the industry. Shneur, you probably need somewhere in the neighborhood of 10% plus or minus of excess to safely operate the basin and avoid huge bottlenecks from time-to-time.

Willie went through the numbers with you a bit earlier, but when 400,000 barrels a day of your 2.5 million barrels a day of capacity is in a refinery, any unexpected downtime or extended turnaround, you're going to fill your tanks up and then you're going to run on in the situations not dissimilar to what we saw in 2011 and 2012.

We've got quite a bit of headroom now versus what we had back then. Keep in mind, this was a basin in a Permian that was 800,000 barrels a day at total production in 2008, 2009, and we were probably ahead at that point in time, just under 1.7 million barrels a day, 1.8 million barrels a day of takeaway capacity. So, you had a 2:1 ratio.

Now, we're tighter than that. but we still got plenty of headroom because we're below that 10% and with the ability of existing pipelines, Cactus, BridgeTex, PE2 to expand and then Enterprise's pipeline coming on, we think we'll stay healthy.

What's still hurting us a little bit right now is based on our numbers, if you take existing commitments and you add it to refining capacity, which refiners are going to buy what they need to run their refineries, you've got a ratio of about 80%, maybe 85% of the volumes spoken for in the sense that there's commitments to ship on that.

In all cases, the shippers don't have the barrels and so, they're going out and competing for that, and that's why you're seeing spreads come in. If you look at the differential between Midland and let's say Magellan's East Houston, I mean, you got $1.20 price premium at Midland East Houston, but it costs $2.25 to get it there.

That tells you that the market is abnormal and you'd run the same numbers going to almost any market that would tell you leave the barrel in Midland, don't ship it out because that's the highest-priced barrel. What that is is because people are bidding it up to fill the commitments that they don't have the barrels for.

And that's why I think Harry's comment's very appropriate is as we get through some of these contracts that expire, that, combined with production uplift, will cause margins to reclaim some of the ground. They may never go back to where they were before, but it's going to reclaim a portion of it..

Great. Thank you very much, guys. Really appreciate the color..

Thank you. Next, we go to Jeremy Tonet with JPMorgan. Please go ahead..

Good morning..

Good morning, Jeremy..

I'm trying to get a feeling here for the Supply and Logistics, trying to get a sense for where the floor of the business is. Realize it's a difficult question.

But just wondering, the $360 million to $380 million that you're guiding today for 2016, do you see that as kind of floor-ish and the majority of that is kind of your NGL business that's largely very recurring and reflects kind of a depressed spread differential or any other color that you could provide there would be helpful..

We have it in our 2017 guidance provided level of detail by segment because we do want to get a better handle on some of the various things we just talked about on some of the prior questions, and we'll have a better feel for that as we talk to producers directly and/or producers share more specific drilling programs.

We're hearing rig pickups, et cetera. But, again, we're a little bit cautious because we saw a head fake last year where what was announced in November and December got taken back in January and February. So, we're going to monitor that. As far as the Supply and Logistics, no question that where we've given up a lot of territory.

I think we were reporting Supply and Logistics as high as $920 million or $930 million in just 2013 and 2014. And, now, we're down, as you say, into the mid- to high-$300s million. A big portion of that is on the crude oil side.

Part of it, and I think, we – full disclosure along the way, we told everybody, don't count on that being sustainable because we think it's associated with problems that we're all going to solve. But we had a view that our baseline in a normal market was $500 million to $550 million.

Well, clearly, when we're reporting $900 million to $930 million, that's not a normal market and we tried to send that. We would tell you that we don't think the $360 million to $380 million, the range we're guiding to right now is the normal market. We think it's back closer to the $500 million. But how we get there, okay, is the challenge.

And so, it's back to these issues of – and we've got analysis of what we think are every existing commitment made by either refiners or intermediaries or producers, and I'm sure it's not accurate for those that are beyond our boundaries. But we've got a much better feel for that and we've tried to calibrate it.

That issue of – as the combination of production uplift if the Permian does increase 300,000 barrels a day in terms of from now until the exit of 2017, somewhere along the way, that should have a positive impact on margins.

And when you combine it with expiring MVC commitments to where people aren't scrambling to buy barrels that they've committed to ship at a price, we think there could be a reset in some of the margins on that basis. So, I can't give you any guidance that we haven't already provided in our aggregate numbers today. I would tell you stay tuned.

We always give that kind of information in February when we have more information..

And, Jeremy, I would add one comment to that. As we've discussed throughout the year here, in certain cases, we are making a conscious effort to go get barrels because – to move through our system with the net benefit to other segments, so that is one of the issues that's there.

So, again, we have definitely made that, as part of our optimization of the total system, part of our priority..

That makes sense.

And, Al, thinking about the credit side, just wondering, you seem very firmly committed to maintaining investment grade there, and I was just wondering if you could update us as far as conversations with Moody's, if you have previewed these earnings or touched base with them recently and just walk us through what levers or steps going forward you might be looking to take if they want more actions taken there..

Yeah. Sure. We maintain kind of ongoing dialogue with, now, all three of the agencies that rate us, so that's been historically part of the process that we've gone through. What I would say, again, we don't directly share specific conversations with an agency, say, Moody's, but that's the one you asked about.

But I would say, generically, the communications that they've provided us and the feedback they've provided us is consistent with what they've put out in writing. And so, I think the last piece they put out publicly was July 12 right after our simplification announcement.

And they were very specific with putting out a process and a view of what they wanted and expected us to do as to a deleveraging plan. And we look at that and we are fully expecting to comply or be ahead of that. So, including based on the guidance that we've just set. So, again, I would point you to that piece and, again, it was dated July 12.

But they acknowledged our leverage is higher now and what they're basically articulating is they want to see a plan and have comfort in that it will recede by – as we progress throughout 2017. So, again, we're looking at that and focused on delivering that or a little better as far as our deleveraging plan..

That's it for me. Thank you very much..

Thanks, Jeremy..

Thank you. And our next question is from Brian Gamble at Simmons & Company. Please go ahead..

Morning, team..

Morning, Brian..

Greg, you've been talking about MVCs in practically every answer, but wanted to touch on it one more time to see, the catch-up that needs to happen to, I guess, eliminate MVC payments and get barrels on a (48:53) with commitment.

What is that lag? And maybe a second part to that question is you're expecting kind of a roll-off starting late 2017, early 2018 some of those MVCs. Can we quantify that in any way as to what is expected to roll off over that time period or the next 12 months, or any kind of quantification for both of those would be helpful..

Well, we know what we have and we really don't have any material roll-offs in there, but what we do know is a lot of these commitments that we – in some cases, Brian, we're dealing with second- and third-hand information, but information we've aggressively gone out to try to get, to try and solve the issue of how big an impact is the MVCs having on the business.

And we came back with the conclusion, it's fairly significant. So, I think, Al's comments, we think, probably – I'm going to throw a number out there for illustration, but for example, if the first 100,000 barrels a day out of the Permian of increased production from current levels, we think would probably go to fill some existing commitments.

Obviously, we've got MVCs and people are paying us and they're not shipping. When they increase production and they give us the barrel, okay, we'll now see that higher recorded volume that we're moving, but you won't see a linear relationship in our reported transportation revenues. We try to make those same assessments for how it impacts others.

And again, that 100,000 barrels, we would allocate part of that to our MVCs that have yet to be fulfilled and we think we have a feel for what others are. There's probably a couple of 100,000 barrels a day over the next 18 months that will be expiring.

And if you add that to the 300,000 barrels a day of increase, that's 0.5 million barrel a day of incremental headroom above that 80%. So, the 80% goes down. Yeah. And I should point out, that will be offset, to some extent, in 2018, Enterprise will clearly have their pipeline in service and we understand they probably got some commitment there.

So it's a pretty dynamic situation. I think one of the things to keep your eye on and certainly we are is that the quality shift over time. The Delaware is much lighter than other areas of the Permian.

And so, we're going to see quality start to play more of a role in that and as the MVCs roll off, you may see quality of volumes going different direction. So, unfortunately, it's more three dimensional than a linear model will allow itself to forecast..

And the other thing I should add to what Greg said, when we think of MVCs, we also think about demand from refineries that have to run this crude. So you take, in the Permian Basin, you have 400,000 barrels a day that's going to be run by refineries. So, we think of that as an MVC.

If you look at (52:05), let's say, basin in West Texas Gulf, two legacy pipes that don't have committed volume on it and the tariffs really don't work to move crude out of those areas, but yes crude is moving and that's because there's refinery demand for that crude.

So, like Greg said, it's a little more three dimensional than just a linear evaluation of what are the MVCs compared to the production in the area..

So, that's fair. I recognize it's a complicated equation. One more on that front. Greg, in your answer, just talking about the shifting complexity of the barrel or the shifting components of the barrel more NGL heavy particularly as the Delaware side picks up versus the Midland side.

Does that benefit you directly in any way because of the footprint of your system and the capabilities of the system? Maybe you could walk through and how that changes your potential uplift into next year?.

Well, I think one of the – and I'll let Willie to chime in here. But the first thing that comes to mind is we've set up our entire Delaware Basin system to be able to segregate the different types of crude qualities that exist, and we think there is a difference between what's being developed in the inside (53:24) Spraberry versus the Delaware.

We think there ultimately be demand for the lighter crudes that we're looking at some opportunities right now to sort of capture that in the nearer term. But, Willie, why don't you go ahead and....

Yeah. I think the other thing I would add is if you look at our Cactus system, I mean it was essentially designed to be able to move the lighter barrels out with capability of segregation, access to Corpus Christi, connected in the pipelines to get to Houston.

So, I think that's a real key cog for us because it also pulls the light barrels out of the base in South without clogging up light barrels that go into the entire Midland Basin system and further dilute that. So, I think the Cactus stream is by far a big strategic driver for us..

Yeah. Brian, when we look at our forecast and we forecast not only volume by area, but we're forecasting specifically how much do we think that that is going to be condensate, what's the gravity, how much is light, medium and heavy, what's the gravity, where are the markets for that to go to, and what are the relative values.

And so, three dimensional may not even be doing it a service, it may be more four dimensional. And then overlaying that are the MVCs that have basically in the past forced somebody to deliver a particular type of crude, so they've had to go out and buy barrels to make that cocktail work to deliver to me the pipeline specs that they're committed on.

As volume goes up and the quality evolves and the commitments come off, okay, you may see a barrel that use to go one direction, go a totally different direction because they can't pay enough to buy back into that market because of what Harry said, the refiners – and they're going to win every time. They've got better economics than everybody.

They're going to buy the barrel that they really want for value.

And so, that's going to force the movements whereas, again, these MVCs – and you're right, I keep harping on it, I'm going to stay on message because I think it's the single most important factor that's different than the last 50 years is it's not access capacity of infrastructure, it's the artificial influences that over-commitments are making and forcing people to act irrationally if you don't have the information they have.

And so, they're just trying to minimize their losses or their sunk cost..

I might add something more on the light crudes. If you think about what's developed over the number of years, we've developed light crudes, but it's been prettily easily absorbed into the system.

And when you look at refining margins that were very, very wide, one refiner is have the capability to run it plus with the wide, wide crack spread margins, they were very willing to run it. As that tightens up and more like it's in there, I think there's going to be a lot more focus on quality.

And I think pricing and quality is going to change than it has over the last five years..

Great. Guys, let me sneak in one more, it's a complicated question, but I'll give you one workout, Greg, if you want it.

Are you more worried, just as worried or less worried about the E&P plans for 2017 at this point in the year as you were when they gave their 2016 plan last year?.

Well, as the chief worry officer, I guess I stay worried all the time. I think we don't know enough to know how to answer that question other than which puts us on alert to just be cautious. I mean, we saw some massive reversals in positions between November last year and February.

And if you are to answer to that same question, I would have given you a naïve answer, says this is what the producers told us. This is what we think they should do. If oil prices continue to drift south, my guess is statements made will change. And if OPEC comes to some semblance of an understanding, those numbers could go up.

And that's why I think the best thing we can do in our guidance is kind of give you an indication of where we're at, let you know asset sales that have or about to happen will impact our EBITDA, what is done on DCF which is a lot less, and then tell you we're going to give you a better update in February.

I feel a little bit like the weatherman where us and our peers are all trying to use the radar and the tools and the knowledge and experience we had to predict the weather. I think, PAA, because of its footprint, has as good a radar and information as others.

But what I found out is, is if we're the ones that predict it's going to be stormy this weekend and clear next week and everybody else is saying it's going to be clear this weekend, even if we're right, they get mad at us. I mean, we didn't make the weather. We just are trying to predict it.

So, our view right now is we're cautious in the very near-term. No question. We are unbelievably optimistic about the intermediate and long-term.

The question is, define near-term, is that six months or nine months or 12 months? What I am proud of is that I think we've taken all the steps to put Plains in a position that if this is a potential extended downturn and we stay on bottom, we think we're near the bottom, but if we stay here for a while, we're going to be fine financially.

We think we've set the distribution at the right level. Our coverage is, if you run the numbers for next year, even at the $1.6 billion, I think, shows a 1.08 times to 1.10 times coverage on the distribution. And we wish we could report better results.

But if we end up in that deal, we know that we're going to see a very strong recovery, we think, in the Permian and other areas, and we're positioned to capitalize on it. We just can't make people drill wells on the schedule we want them to..

Thanks, Greg..

Thank you..

And we go now to Harry Mateer with Barclays. Please go ahead..

Hey. Good morning. I guess first is following up on the Moody's comments from earlier. Two of the specific numbers the agency laid out were 5.5 times adjusted leverage on their numbers and then EBITDA also turning to $2.5 billion next year.

So, with your preliminary guidance a bit below that, but some of that attributable to asset sales, do you think the asset sales you're looking at will be sufficient to ensure you're on compliance with the Baa3 requirements or is it a combo of asset sales and then perhaps leaning more on the COP program?.

I mean, clearly, asset sales have been a key component, especially with you're getting good value for them. We think the tool that we're going to use are a combination of all the ones I mentioned. Clearly, we think Moody's is very much focused on leverage which is the key one and also distribution coverage. We think those work very well.

Clearly, one of the key components they're focused on is the 5.5 times, as you mentioned..

If I just add too, and, Al, correct me if I'm wrong, but I think at the time that you measure that, you look other trailing basis because that's what you need to do, but you also look at what's the slope or what you can see in front of you.

And, again, with the visibility, if it's clearing up, it's going to be – if it's just a matter of a quarter or two before things are turning because you can see production volumes have come up and things have aligned. So, I think we want to leave our options open.

But what I think you hear Al saying very clearly is we have all the tools that we need to do what we need to do..

And, clearly, with regard to the ATM, I mean, clearly it's a component of our CapEx program but it's also a tool to manage our capital..

Okay. Thanks for that. And then you've got a $400 million maturity coming up in a couple of months.

What are your thoughts at this point in terms of addressing that? Do you refinance of the new deal pay down for revolver or perhaps look to pay it down with asset sale proceeds or some other form of capital?.

We always don't look at a one specific maturity. We look at king of our overall needs, what we've got currently funded on our facilities or through CP, what our capital program is looking forward? We would, based on our views, consider accessing the market either before the end of this year or in the first half of next year.

So, that would be our thoughts with regard to that but it wouldn't be just specifically to fund that particular note..

Okay. Thanks. And then last one from me, just if you can share this.

Do your current estimates assume that Plains' debt balance is higher or lower or unchanged at the end of 2017 relative to 2016?.

We hadn't disclosed that. But again, we're looking at – I think the key factor that we're looking at is the leverage metric. And we're considering how Moody's looks at it. And so, my comments earlier about being at or better than the ratios that Moody's quoted in their July 12 release is very much a focus of ours.

So, whether the debt is a little higher or lower, depending on where EBITDA is, that becomes not as important as making sure we are deleveraging on the plan that we've discussed in detail with Moody's..

Okay, got it. Thank you both..

And next, we go to Vikram Bagri at Citi. Please go ahead..

Hey, guys. A quick question on financing requirement in 2017. Apologies if I missed this. Once the transaction closes, how should we think about equity issuances at PAA versus PAGP level, given PAGP trades when it trades at exchange ratio higher than the proposed ratio and there's a deferred tax asset at PAGP.

How should we think about issuances after November 15?.

Currently, we do not have an ATM up there. We will look to do that and we will look to optimize the best cost of capital for the entity. So, our view was is that with the tax asset, the structure, that entity, we felt like that stock may trade at a premium to the underlying unit. It has so far.

We'll see if that continues, but our intent would be to use that as a funding source as well. So, don't be surprised if we look at some point here to post-closing to put in an ATM facility up at that entity..

And, Vikram, we announced this when we made the simplification announcement. There was a lot of back and forth between the two sides as to what's a fair trade? But we did hardwire into that arrangement the ability to effectively sell equity at the top and backstop it with the issuance of units for PAA on a one-to-one basis..

Great. That's helpful. A couple of quick questions on assets. With Saddlehorn online and Grand Mesa is online as well, how should we think about long-term outlook for White Cliffs Pipeline? I believe White Cliffs has a deeper reach into the basin, but the rates are not competitive enough.

So, longer term, what's the expectation for volumes on White Cliffs?.

I think we're going to let the operator give you their version on that. I would just point out we've got 40% ownership in Saddlehorn and 36% ownership in White Cliffs. And so it's not that we're necessarily indifferent to it.

It's just it's not as big an issue to us of which pipe it goes down, and I'll leave it to the operator of White Cliffs to address that issue..

Okay. And just as a final question. You talked about growth through acquisitions and JVs on your Analyst Day and you talked about that in the past as well.

I was wondering if – how does an asset like Express-Platte fit into your portfolio, does it help you in (65:38) sell in the longer term, does it help you in White Cliffs volumes? And how should we think about M&A once the transaction closes? Are you looking at potential assets prior to simplification or you'll consider that once the transaction closes?.

First, it never is prudent for us to talk about trying to buy assets from somebody that may be considering selling them and showing our cards, so we'll hold off that. I think the concept you had about we look at it on a strategic basis of how it all fits together, we're all about how do we improve our system.

And we're business builders, not asset aggregators. I think we've even looked at, and kind of back to Harry Mateer's comment earlier, I mean, for the right asset, you might go in and overfund it with equity if it's strategic and you have the kind of synergies and actually an acquisition could help you de-lever on your debt-to-EBITDA on that basis.

And yet, the unitholders might stand back. And we think we'd look at it and say, good value move because it improves the overall value of the system.

So, I don't want to talk about any particular assets, but I can tell you, we all are looking at it, I think, with the same lens that you've talked about, which is a mosaic of how do we make pieces fit together so that one plus one equals something greater than two..

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

And now we go to Becca Followill with U.S. Capital Advisors. Please go ahead..

Good morning, guys, and thanks for extending the call a little bit. You guys talked about continued margin pressure impact in Supply and Logistics, and it looks like guidance for Q4 is flat despite the fact that you're kind of rolling some of Q3 into Q4.

Is something specifically happening to cause additional margin pressure in the last three months?.

Well, exactly, that's what we're communicating is that it's intensified the margin pressure as barrels are up. We're seeing margin – I mean, people are competing very, very, aggressively. The beneficiary of this is clearly the producer. It's not the midstream companies that are basically both trying to drop to the floor.

And, ultimately, we think the most integrated entities on the midstream side will be winners, but maybe winners because they're the tallest short person in the room..

And in some areas, we're seeing a little more margin compression in the NGL space as well. I'm not saying that's across the board everywhere, but there are areas where that is occurring..

Okay. Thank you.

And then, just to clarify, the 2017 guidance includes the impact of the sale of the West Coast terminals even though that's not finalized yet?.

It's contracted. And, yeah, it does. I mean, it's that and a few others that are basically impacted in there. Yes..

Thank you. And then, the last one.

I know it's de minimis, but is any expansion dollars for maybe expansion of BridgeTex or Cactus included in your CapEx for 2017?.

No comment..

Okay. Didn't think so. Thank you..

And next, we have Ross Payne at Wells Fargo. Please go ahead..

Harry, most of my questions have been – well, most of my questions across the board have been answered on Moody's, so I don't want to go there right now.

But, Harry, can you go in a little more detail this $30 million in delayed NGL inventory and crude inventory sales and how that might have manifested itself relative to prior quarters when we didn't use to hear about this? Thank you..

It's happened occasionally in the past, Ross. It's basically you take a month like September where we had low NGL prices and you have an average cost of inventory accounting process, the sales – and higher margin is hedged through the winter period.

It's just sort of dependent on – what happened in this quarter was at the end of the quarter with the lower NGL prices and higher average inventory cost. We had lower profits in September. But that'll manifest into larger profits as the rest of the inventory is drawn in either the fourth quarter or first quarter.

In addition, there was some transportation costs paid on some crude in-transit where the costs were incurred in the third quarter and the sales will occur in the fourth quarter..

And, Ross, the other thing that we specifically chose to keep some contango inventory through this quarter that we had modeled, that'll come out in the fourth quarter..

Yeah..

Ross, on the NGL, on the inventory costing at the risk of over-simplifying, effectively, we have a seasonal program where we buy NGLs during the summer months, we store it and our customers have committed to purchase that inventory sometime between October and the end of March. And so they have to take it out.

We don't know exactly when and part of that's weather-related. So, we buy that. It goes into our average cost of inventory and we sold it back-to-back. We just don't know what the exact timing on that is.

In between that, if we go in and let's say spot prices fall, so we can buy spot barrels at X that's below our average cost of inventory and we sell it at a price that's above the spot price that we just bought it at, accounting requires us to take the sale that we did which is at a depressed price to what we – average cost of the inventory at but above that spot purchase – they make us roll the spot purchase into the average cost of inventory and so you could actually have a situation where – I'll make up numbers – you bought it at $1 for the summer-winter spread and you sold it at $1.20, okay? And then later on prices fall and now it's at $0.90 and you can buy a spot barrel at $0.70 and sell it for $0.90, so you can still make $0.20.

But they're going to make us take that $0.90 sale and match it with that $1 average costing the inventory that's may be $0.99 now. And so you look at it and say, well, that's silly, you lost money. But the answer is, you really made money, in the aggregate. It's just a question of when you realize the money..

And if you look at what happened in the third quarter, July prices and August prices, there was a pretty severe dip down in recovery by the time you came out at the end of September..

Okay. That makes a lot of sense. And, thanks so much for the clarification. And, Al, I got one more for you. Does the 1.08 times to 1.10 times coverage, is that inclusive or does it exclude the PIK on the preferred? And that's it for me. Thanks, guys..

That would be a cash amount and it was excluded..

Very good. Thank you..

Thank you. And next we go to John Edwards with Credit Suisse. Please go ahead..

Yeah. Good morning, everybody and thanks for taking my question here. Just if I could come back to the MVC topic for just a second because I don't think I was quite following.

What are the volumes needed then to cover that? It sounds like, because of the MVCs, there's not enough volumes flowing through your system to actually cover that; that's depressing margins.

What kind of volumes do you need to get to the point where you, in effect, have true market-based rate?.

So, John, the issue is....

(73:16) understanding..

Yeah. The issue is not just us, there's several others in the basin. So, the question is, we don't know what the big scope is broadwise (73:25).

What we do know is that – well, what we think we know is based upon the contracts that we've put together, roughly about 1.7 million barrels of the 2 million barrels of current production out there is spoken for either by refineries or existing commitments, okay.

And so, there's more than enough volume to cover it overall, but it's not always in the right hands. And so somebody who has a 100,000 barrel a day shipping commitment that only termed up 50,000 barrels a day of purchases is constantly going into the market trying to buy that 50,000 barrels a day.

And they're basically willing to go to the wellhead and lose money a quarter a barrel because if they don't buy that, they're going to have to still pay $2.50 or $2.75 or $3 to ship a barrel or to pay for a barrel they don't ship.

So, we disclose – and I don't have the number right here, but we disclose in our adjustments what the shortfall is relative to what we have been paid for or billed (01:14:23), but it's a bigger issue than just us. It's the whole basin..

It's really kind of the tail wagging the dog, right, the incremental barrels, whatever that shortfall is, it doesn't have to be a whole lot. But if that incremental barrel is losing money from the Supply and Logistics segment, it's going to drive the whole complex down.

Same thing happened in reverse, there's a transportation coming out of the Permian Basin a couple of years ago. There may have only been 50,000 barrels a day of shortfall out of 1.5 million barrels, but that shortfall drove the whole complex to a $10 premium because that's what it cost to get the incremental barrel out (75:05)..

Or a $10 discount, yes..

Yes..

Okay. So....

It's not our short. It's the industry's short..

Industry's short. Yeah..

When you had 1.550 million (75:15) of production and 1.5 million (75:17) of transportation, that 50,000 barrels set the price for that differential to go to $10 or $12 a barrel.

To flip it back around, you may have 50,000 barrels short trying to run around and it's driving what would normally be an $0.80 differential or a $0.50 differential to Cushing to a premium sometimes..

Okay. So, I mean, with a lot of the E&P guidance out there, I mean, it's something like, I guess, fourth quarter 2017 over fourth quarter 2016, I guess, depending on what estimate or what numbers you want to look at, it's something like 200,000 barrels a day to 250,000 barrels a day of increase expected, somewhere in that ballpark, it looks like.

I guess the expectation is, is it all these MVCs, at that point, it should basically be over and done with, I would imagine then, by the end of next year? Is that fair, or does it slop over into 2018 a little bit?.

It's more complex than that because, for example, even on our system, we have a step-up in MVCs with the passage of time on Cactus that we've talked about in the past. And so, some roll off, some roll on. If they're in our hands, we like it. If they're not in our hands, we don't like it.

And then, there's some that expire in 2018, but then you've got ECHO coming on. So, you're asking, John, the right question. I think everybody is. But, in some cases, without all the knowledge, it's hard to know. And, ultimately, we think, again, it's not sustainable, but how long it can be sustained before it – that sells out is hard to predict.

And so far we've been less than 100% accurate at predicting its impact on us because it's still been like catching a falling knife..

Okay. And then, just pivoting a little bit. We noticed, compared to last quarter the guide in your guidance that was in the 8-K last night, the Permian volume for the fourth quarter while still rising, it was actually something like 1% lower than what you had guided to in 2Q.

And so, we are just wondering what was behind that? Particularly, given the very optimistic guidance numbers being put out by the E&P companies?.

Keep in mind, I mean, that's what happens is – if somebody is going to drop their willingness to gather barrels at a loss, okay.

They're going to redirect that barrel to their pipeline and we would have assumed that it was go come on ours at a reasonable margin and – so, it's not that the barrels aren't being produced it's a question of whether they're actually being bid for to fill the MVCs..

Okay. So, again, it's a sort of a complicated plumbing dynamics there. Okay. That's helpful. And then, a question for Al, with the GP gone, we're presuming you could have an investment grade credit and still – and run at a higher leverage than you maybe did in the past? I think in the past you we're targeting 3.5 to 4.

Are you going to be targeting a little higher leverage, more like 4, 4.5 or are you still thinking this 3.5 to 4 range?.

We are not looking to change anything clearly with the GP as we close the transaction any debt up in entities above PAA will go away, PAA is assuming that. That's partly why we are using the ATM like we did in the third quarter and early fourth quarter. But now we're committed to the 3.5 to 4 range on the long term debt to adjusted EBITDA basis.

Remember though, John that embedded in that quarterly we have hedged inventory debt. So, that's why we think that level is the appropriate level that with our normal amount of hedged inventory debt.

Clearly our consolidated total leverage which, say, the way Moody's looks at it or other rating agencies that that's within tolerance that they would have for investment grade, mid BBB ratings..

John, I would just add to that comment that clearly we've been in this business a long time that the new issue that has come up that has affected perspective about the right level of leverage is, is this potential for MVCs to come back in the future in some form or fashion – if we go through the next boom.

And so what we see is that there's more pressure in a down market uncertain of our margins that we need to build better cushion into our leverage.

And so, yeah, we got rid of the GP but we have to deal with MVC and so I think what you hear and I'll say very clearly is we're committed to that because that's the level of flexibility we think we need to have to withstand the full cycle and still be on offense throughout the entire time period..

Okay. That's helpful. And then just my last one. So, going back to this recognition of the EBITDA in S&L and some of the other noise that was in there.

What we've noticed is looking back to the guidance last quarter that it didn't really change much and so, we were a little bit confused on how it would – how that recognition then actually works? I mean, you don't need to go back through the whole (01:21:15).

Yeah. The short answer to that is two things. One, the delay, will delayed into the fourth and to the first quarter of 2017. And then, the margin compression that we didn't see last time is impacting the fourth quarter and offsetting some of that delayed carryover benefit..

Okay. All right. Thank you very much..

Thank you, John. We got time for a couple more, I think..

All right, your next question is from Danilo Juvane at BMO Capital Markets. Please go ahead..

Thank you. My questions have been hit. Thanks..

Thank you, Danilo..

All right. Then, the final question we have is from Robert Balsamo at FBR. Please go ahead..

Hey, guys. Thanks for taking the question. Just a little clarification on the compression, the margin compression issue.

When I think about competition for barrels getting on to the longer-haul pipelines, what sort of arrangements are being made as far as (1:22:11) commitments from the producers? Just thinking about like how sticky some of the customers are going to be once they're captured and, ultimately, maybe, how quickly things could respond favorably month-to-month?.

Yeah. So, it varies. I mean, there's some arrangements where you're literally competing on an evergreen 30-day and there are some were people are locking up for six months or a year here..

Yes. Yeah..

So, there's no one simple answer there, Robert, but it – and it varies by areas to some extent based upon their outlook. And so, yeah, I think that's not totally different than what we would have seen five years ago.

Some people were willing to lock up for month-to-month and no longer and some wanted to do six months to a year, so I don't think it's really changed. So, the pattern in a recovery shouldn't look terribly different than it did come in the other direction..

I would say that the producers are seeing better and better prices all the time, so they're probably hesitant to do longer than a year and six months to a year is probably, like what I've said, is the range that we're seeing all of these agreements for..

Great. That's helpful. And then just – I don't know if you are up for (1:23:23) a clarification or not, but I think about that competition as having some legacy assets that are experiencing declines in trying to compete for volumes to replenish that as well as trying to capture kind of new barrels or new producers.

I don't suppose you can give any kind of color on how much of each you're seeing if it's more trying to capture new operators or new producers or offset decline? Do you think that makes sense?.

Well, I think the competition for the barrels has been more on our legacy pipes where we didn't have commitments from them when we built it. If you're asking as to the areas within or the nature of the operation, it really varies.

I mean, clearly, in – we don't have as competitive a position in the up Northern Midland area if we have a very – we're ahead of the crowd, we think, in the Delaware in many of the right areas. So, it just varies. And I realize it's frustrating from an outsider looking in, but from 30,000 feet, the world looks flat.

When you get down to 30 feet, you want to pick where you land very carefully..

Yeah. All right. That's it, guys. Thanks a lot for all the color today..

Thanks..

I believe we're ready to wrap up the call, Noah..

Great. There are no further questions. And that does conclude our conference for today. So, thank you for your participation and for using AT&T teleconference. You may now disconnect..

Thanks, everybody..