Ryan Smith - Plains All American Pipeline LP Greg L. Armstrong - Plains All American Pipeline LP Harry N. Pefanis - Plains All American Pipeline LP Al Swanson - Plains All American Pipeline LP.

Brian J. Zarahn - Barclays Capital, Inc. Jeremy B. Tonet - JPMorgan Securities LLC Kristina Kazarian - Deutsche Bank Securities, Inc. Faisel H. Khan - Citigroup Global Markets, Inc. (Broker) Ethan H. Bellamy - Robert W. Baird & Co., Inc.

(Broker) John Edwards - Credit Suisse Securities (USA) LLC (Broker) Christopher Paul Sighinolfi - Jefferies LLC Becca Followill - USCA Securities LLC Michael Blum - Wells Fargo Securities LLC Jeffrey T. Birnbaum - Wunderlich Securities, Inc. Selman Akyol - Stifel, Nicolaus & Co., Inc. Sunil K.

Sibal - Seaport Global Securities LLC Noah Lerner - Hartz Capital, Inc..

Ladies and gentlemen, thank you for standing by. Welcome to the PAA and PAGP 4Q 2015 and Final Year Results Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Instructions will be provided at that time. As a reminder, this conference is being recorded.

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

Thanks, Tom. Good morning, and welcome to Plains All American Pipeline's fourth quarter 2015 earnings conference call. The slide presentation for today's call can be found within the Investor Relations and News and Events section of our website at www.plainsallamerican.com.

During today's call, we will provide forward-looking comments on PAA's forward 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 GAAP 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 Chang, 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 welcome to everybody. Yesterday, PAA reported fourth quarter and full-year 2015 results. Slide three contains comparisons of PAA's performance metrics to the same quarter last year and also to the fourth quarter 2015 guidance, as furnished on November 3, 2015.

Adjusted EBITDA for the fourth quarter of 2015 was $563 million and $2.17 billion for the full-year 2015, both of which are slightly below the low end of our guidance ranges furnished last November. As noted in our press release, two items accounted for a fair portion of the gap.

The first is the deferral of margin on NGL volumes expected to be sold in the quarter and related inventory costing items. The second is under deliveries on contracts with minimum volume commitments that essentially results in revenue deferral.

These represent amounts we have either received or will receive for which the shippers have the right to make up volumes in the future. These amounts will be transferred to revenue when the make-up occurs or when they lose the ability to make up for the volume shortfall. Harry will provide additional information in his comments.

As for distributions, PAA announced a quarterly cash distribution of $0.70 per limited partner unit or $2.80 per unit on an annualized basis, which is unchanged from the quarterly distribution paid in November 2015.

PAGP announced a quarterly cash distribution of $2.31 per Class A share, which is $0.924 per Class A share on annualized basis, which also is unchanged from the quarterly distribution paid in November 2015. I will provide some additional comments on our industry outlook as well as our outlook for PAA's 2016 performance in my closing comments.

For now, I will turn the call over to Harry to discuss our fourth quarter operating results and our 2016 guidance..

Thanks, Greg. During my portion of the call, I'll review our fourth quarter operating results compared to the midpoint of our guidance, discuss the operational assumptions used to generate our 2016 guidance and provide a brief update on our 2016 capital program.

As shown on slide four, adjusted segment profit for the Transportation segment was $256 million or approximately $19 million below the midpoint of our guidance. Approximately $6 million of the short fall is related to volume deficiencies under minimum volume contracts exceeding the levels we forecasted.

For the quarter, the total impact of these deficiencies was approximately $15 million. The deficiencies were all from credit-worthy parties. However, as Greg mentioned, the revenue recognition of these deficiencies is deferred until the actual volumes are delivered or until the make-up period has expired.

Approximately $8 million of the shortfall is related to the valuation of pipeline loss allowance barrels. The balance of the shortfall was due to lower-than-expected volumes, partially offset by lower operating expenses. For the quarter, volumes were approximately 4.5 million barrels per day or 249,000 barrels per day below our guidance.

Our crude oil volumes comprised approximately 200,000 barrels per day of the shortfall.

In the Permian Basin, volumes on our export pipelines were approximately 40,000 barrels per day less than anticipated, due to a combination of one, maintenance issues with the third-party connecting pipeline; and then, secondly, lower-than-expected volumes under a minimum volume commitment contract.

The balance of the volumetric shortfall was due to a combination of, first, longer-than-forecast refinery turnarounds; second, certain receipts not meeting our pipeline quality specifications; third, short-term diversions of volumes around certain bottleneck areas in the Permian Basin; and fourth, lower-than-anticipated gathered volumes.

This was partially due to the inclement weather at the end of both November and December. Adjusted segment profit of $0.62 per barrel was slightly below our guidance of $0.63 per barrel. Adjusted segment profit for the Facilities segment was $150 million, which was approximately $10 million above the midpoint of our guidance.

Volumes of 128 million barrels of oil equivalent per month were in line with our guidance. And adjusted segment profit of $0.39 per barrel was $0.03 per barrel above the midpoint of our guidance. That's primarily due to lower operating and general and administrative expenses.

Adjusted segment profit for the Supply and Logistics segment was $157 million or approximately $23 million below the midpoint of our guidance. Volumes of approximately 1.2 million barrels per day were in line with our guidance; however, NGL sales volumes were 29,000 barrels per day or about 10% lower than forecasted.

Adjusted segment profit per barrel was $1.46 or $0.18 below the midpoint of our guidance.

The lower-than-anticipated adjusted segment profit was a combination of the lower NGL sales volumes and inventory costing plus narrower margins at our crude oil gathering business, partially offset by lower-than-forecasted operating and general and administrative expenses.

The lower-than-forecasted NGL sales volume was due to unseasonably warm weather in certain areas of the U.S. and Canada; this is basically timing issue. These volumes are expected to be delivered in 2016. Slide five provides an illustration that reconciles our fourth quarter guidance, furnished in November, to our fourth quarter 2015 performance.

The key takeaway from this slide is that the negative variance was primarily related to the two timing issues previously mentioned. Let me now move to slide six and review the operational assumptions used to generate the 2016 guidance we furnished yesterday.

For our Transportation segment, we expect full-year 2016 volumes to average approximately 5 million barrels per day, an increase of approximately 525,000 barrels per day or 12% over full-year 2015 volumes. We expect adjusted segment profit per barrel to be $0.64 or $0.02 per barrel higher than last year.

The volume increase is primarily forecasted – are due to forecasted increases in our Permian Basin area pipelines, driven by the completion of our Delaware Basin systems and the continued ramp up of our Cactus Pipeline. Increases in other producing areas basically offset the volumes attributable to non-core assets expected to be sold in 2016.

For our Facilities segment, we expect an average capacity of 129 million barrels of oil equivalent per month, which was slightly higher than the 2015 levels, as we place additional storage in service at our Cushing and St. James terminals. The guidance volumes also reflect the sale of our Philadelphia area terminals in the second quarter 2016.

Adjusted segment profit per barrel is expected to be $0.40, which is $0.01 higher than 2015. For our Supply and Logistics segment, we expect volumes to average 1.185 million barrels per day or approximately 17,000 barrels per day higher than volumes realized in 2015.

Adjusted segment profit per barrel is expected to be $1.13 or $0.20 per barrel lower than last year. The volume increase in this segment is due to anticipated increases in NGL sale activity. Segment profit per barrel is due to lower – is lower due to our expectation that we will continue to have challenging crude oil market conditions into 2016.

Finally, slide seven provides a summary illustration by segment of our 2016 adjusted EBITDA guidance compared to our 2015 performance.

Moving on to our capital program, slide eight recaps our major projects for 2016, the vast majority of which are underpinned by MVCs, minimum volume commitments or other types of contractual commitments that will be coming online or ramping up over the next 24 to 30 months.

The projects are moving forward as planned, but I'll note the timing of the receipt of final permits for the Diamond Pipeline could push the start of construction a little bit in 2016. There are two additional items worth mentioning.

In November, the Saddlehorn partnership announced the formation of a undivided joint interest with NGL Energy Partners' Grand Mesa pipeline project, which reduced PAA's cost in the project by approximately $100 million, with no impact to our anticipated tariff revenues from the project.

Additionally, in December, Valero exercised their option to acquire a 50% interest in our Diamond Pipeline project, which reduced PAA's cost on this project by 50% to $465 million. And lastly, we expect maintenance capital to be in the $190 million to $210 million range for 2016. So with that, I'll turn the call over to Al..

Thanks, Harry. During my portion of the call, I will review our financing activities, capitalization and liquidity, our guidance for the first quarter and full year of 2016 and our counterparty credit and performance risk. PAA ended 2015 with a solid financial position, which is illustrated on slide nine.

We had long-term debt-to-capitalization ratio of 57%, a long-term debt-to-adjusted EBITDA ratio of 4.6 times and $2.3 billion of committed liquidity.

While our long-term debt-to-adjusted EBITDA ratio remains elevated relative to historical levels in our targeted range, we expect it will improve and return to within our targeted range as we realize the benefit of new projects coming online in 2016 and 2017, coupled with an industry recovery.

In January, we completed a $1.6 billion preferred equity raise, the pro forma impacts of which are illustrated on slide nine. We hosted a detailed conference call announcing the financing on January 12, where we characterized this as a one-and-done transaction that prefunds our equity requirements for 2016 as well as 2017 in all material respects.

The transaction closed on January 28 and was upsized to $1.6 billion from the $1.5 billion that was originally announced. This equity substantially enhances PAA's credit metrics and, therefore, PAA's ability to manage through a potential lower-for-longer scenario.

In addition to this transaction, we have executed binding agreements for the sale of several non-core assets totaling approximately $325 million. We expect these transactions to close within the next 60 to 90 days.

We are working on a couple of additional non-core asset sales and believe that the total aggregate sales for 2016 could be in the $400 million to $500 million range.

Moving on to PAA's guidance for the first quarter and full year of 2016 and as Greg will discuss in his closing remarks, in response to recent price fluctuations, producers are still developing their 2016 capital plans and production forecasts.

And others are modifying previously disclosed plans, which will have an impact on PAA's performance in the coming year. As an example, since mid-December when we generated our 2016 forecast, total rig count has declined approximately 143 rigs or 25%, with more than half of that rig count reduction coming in the last two weeks.

As a result, there are a number of variables and unknowns that will make our task of providing guidance more challenging than in past years.

With that in mind, we have elected to essentially maintain the preliminary guidance we've provided on January 12 conference call but intend to adjust throughout the year as developments warrant and a clearer picture of activity levels is available.

As summarized on slide 10, we are forecasting midpoint adjusted EBITDA for the first quarter of $570 million and $2.275 billion for the full year. We expect the fee-based contribution to be 78% for 2016, up from 74% in 2015.

Based on PAA's $2.80 per unit annual distribution, distribution coverage is forecast to be approximately 87% for 2016 based on midpoint guidance.

Our 2016 guidance assumes that producer activity remains near current levels with lower 48 onshore production volumes ratably declining by approximately 325,000 barrels per day over the course of the year, although production profiles will vary by basin.

While we have minimal direct commodity exposure, we will be impacted by the anticipated lower 48 production decline and also are impacted by tighter differentials. With respect to our MVC contracts, in a few areas we are forecasting volumes to be below contracted levels.

In the remainder of the areas, we have forecasted volumes to be in line with contracted levels. Throughout the year, we'll adjust our forecast to reflect variances between forecasted volumes and the volumes we'll be paid cash for under the MVC arrangements.

In all cases, we have excluded from our cash forecast expected shortfalls from counterparties that we deem to be of questionable collection.

With respect to our Supply and Logistic segment results, although we could benefit from potential volatility during the coming year, our 2016 guidance assumes a below-historical baseline type of environment for this segment, consistent with our expectations that competitive pressure will continue to negatively impact lease-gathering margins and tight basis differentials in the current environment.

The right half of slide 10 highlights two aspects of our 2016 guidance. The first is the build in our fee-based Transportation and Facilities segment that we expect to see throughout 2016. The second element is that the NGL business within our Supply and Logistics segment has an inherent seasonality.

NGL volumes and margins are typically highest in the first and fourth quarters of each year due to weather-driven demand in the winter months. The seasonal impact will likely result in higher distribution coverage in the first and fourth quarters with lower coverage during the second and third quarters. Shifting gears.

In consideration of the current industry conditions, I'm going to comment on PAA's counter-party credit exposure and performance risk. Over 85% of our credit exposure is associated with our Supply and Logistics segment. The credit exposure in this segment is mainly attributable to our crude oil activities and is primarily from selling oil to refiners.

The refining sector has been one of the best-performing sectors in the energy industry in this low-price environment. Additionally, our exposures under these arrangements are generally for periods of 60 days or less, and we have the right to request security should we deem it appropriate.

We manage our credit exposure to all customers through our credit analysis and monitoring, which includes assigning specific credit limits and securing excess exposure via letter of credits or prepayments For these crude oil sales, approximately 85% of the exposure is to investment-grade entity or where we have secured the exposure by letters of credit and prepayments.

The remaining 15% is open credit to non-investment grade or unrated entities that have been reviewed and approved by our credit department. A smaller part of our Supply and Logistics credit exposure is associated with NGL sales.

The NGL sales activity is best characterized by small individual credit exposures to hundreds of entities for periods of less than 30 days. Larger credit extensions for NGL sales are typically in the $5 million to $10 million range and are typically to refiners or retail propane distributors.

Counterparty credit exposure for our fee-based Facilities and Transportation segments is much smaller than our Supply and Logistics segment due to the fee-based nature of the activity. The credit extensions are also generally 60 days or less.

For the Facilities segment, our Supply and Logistics segment is a significant customer, with the majority of the third-party customer activity being associated with storage leases and throughput and processing arrangements. A large majority of the third-party business is with investment-grade entities.

Demand for storage capacity in this oversupplied environment has remained strong. And overall, we believe that where there may be risks that customers don't perform on their commitments that we would be able to replace those contracts.

Additionally, we typically have possession of some of our customers' inventory, which provides a form of credit protection in the event of nonpayment.

For the Transportation segment as a result of our lease gathering activity, our Supply and Logistics segment is a thoroughly large shipper on our pipelines, with a large majority of the third-party business being with investment-grade entities.

Additionally, shippers typically are required to carry linefill on the pipelines which, as with the Facilities segment, provides a form of credit protection in the event of nonpayment.

We also have a number of MVC or minimum volume commitment contracts supporting our Transportation segment, mainly supporting pipelines that were recently constructed or that are under construction. However, there are also a number of these contracts that support certain of our legacy pipelines.

Additionally, certain of the pipelines in which we own a joint venture interest have MVC contracts including BridgeTex, Saddlehorn and the Eagle Ford joint venture.

MVC contracts provide a higher certainty of revenue but also have performance risk and create potential timing issues for revenue recognition as a result of having to record deferred revenues for deficiencies which have unused or unexpired make-up rights.

A large majority of the dollar value associated with the MVC contracts supporting our pipeline systems are with investment-grade entities. For those that aren't with investment-grade entities, a number of them are with non-investment-grade refiners associated with demand-pull projects or non-investment-grade producers on supply-push projects.

The performance risk associated with non-investment-grade producer contracts is relatively modest and in a worst case would represent approximately 2% of PAA's 2016 adjusted EBITDA guidance.

I should also note that there is one MVC contract on the BridgeTex pipeline that represents approximately 10% of that pipeline's capacity where we concur with the operator's expectation that the counterparty will not fulfill their contractual commitment and will ultimately default.

We have not included any revenue from this contract in our 2016 guidance, nor was it included in the fourth quarter deferred revenue amounts Harry mentioned earlier. With that said, we value the business relationships we share with all of our customers, and we chose not to discuss the specifics of any of those relationships.

With that in mind and without getting into the specifics of our relationship with any one specific customer, I do want to note that PAA's exposure to a specific customer was mentioned in a couple of recent reports which, as indicated by our assessment of the worst-case scenario, overstates or exaggerates the potential impact to PAA.

The bottom line is that given the nature of our business and the financial strength of the customers that represent a large majority of our revenues, we believe PAA's credit exposure and MVC-related performance risk is very manageable and relatively modest.

Before I turn the call over to Greg, I want to provide an update on the equity credit percentage that we understand Moody's will apply to the $1.6 billion of preferred equity we recently issued.

As we stated on our January 12, 2016 call, we consider this $1.6 billion preferred equity to be part of our permanent equity capital structure, as it is perpetual and is junior to all of our debt. Additionally, if redemption were ever contemplated or required, it would be PAA's intention to redeem with common equity, which is at our sole discretion.

On our January 12 call, we stated that for credit rating purposes, the preferred would receive 50% equity credit from both rating agencies. This statement was supported by written confirmation we had received from both of the rating agencies.

Moody's has since informed us that for investment grade MLPs, preferred issuances that contain a cumulative dividend feature will be treated as if the distribution payments are mandatory, irrespective of the actual structure or terms to the contrary. And as a result, they intend to apply only 25% equity credit.

We don't agree with the rationale and have requested that Moody's reconsider this issue. However, they decline to do so at this time but indicated that they may reconsider in the future.

Based on direct and indirect communications with our bondholders, it is our understanding that they share PAA's view that the preferred should be considered 100% equity as opposed to the 50% equity credit. Nonetheless, we wanted to share with you the information that Moody's will assign 25% credit to the preferred security.

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

Thanks, Al. I want to close with a few comments about PAA's overall position in the current environment and some thoughts about our guidance for the next 12 to 24 months. Although PAA does not have material direct exposure to crude oil price variations, its performance is clearly tied to the overall health of the U.S. and Canadian crude oil industry.

PAA is quite frankly the largest crude oil-centric midstream MLP, with leading positions in substantially all U.S. and Canadian resource plays and market interchanges and has the most interconnected crude oil transportation and terminalling network in North America.

Moreover, as a result of the recent one-and-done equity financing, PAA has the balance sheet strength and liquidity to manage through an extended period of challenging industry conditions without depending on future access to equity capital markets.

Without question, the entire energy sector is facing a challenging period with future visibility that is somewhat upside-down. By that I mean that the long-term view is clearer than the short term.

Over the intermediate to long term, it is very clear that the industry cannot replace production declines or meet projected crude oil demand with oil at $30 per barrel and that the world will need U.S. production growth to balance the market.

As a result, the proven and well-defined North American resource base and ever-improving technology bode very well for the U.S. and Canadian energy sector in general and for PAA's role in the crude oil midstream sector in particular. However, visibility over the next 12 to 24 months is pretty cloudy.

A significant driver in PAA's motivation to pursue an aggressive timeline for raising the $1.6 billion of equity capital was that we believed it was possible that oil prices and capital market conditions could get worse before they got better.

Crude oil prices are now 20% lower than they were at the time we made that decision and have been as much as 30% lower. And as Al mentioned earlier, the rig count is almost 25% lower. Accordingly, we feel our obsession with speed, certainty and amount was validated.

Moreover, we believe the industry conditions over the next several months have the potential to be more challenging and stressful for the industry than the last few months.

Specifically, in the absence of an exogenous event such as OPEC reducing their production, we believe crude oil inventories will continue to increase toward uncomfortably high levels, oil prices will remain under pressure and the viability of many highly leveraged entities could be tested.

Financially, PAA is very well positioned for such potential industry conditions. Nonetheless, PAA's near-term operating results could well be impacted by the actions of others. During today's call, we provided quarterly and annual guidance in a format similar to that provided by PAA over the last 15 years.

However, more so than in past years, PAA's near-term performance will be influenced by uncontrollable and unknown factors such as variations in producers' activity level and competitive reactions from certain of our public and private midstream peers.

At PAA, we will continue to compare our performance against and be accountable for the guidance we provide each quarter. But given current commodity price levels, producer drilling and completion activities could turn out to be lower than the levels necessary to deliver the volume forecast incorporated in our 2016 guidance.

For reference, a $10 decrease per barrel in the price of crude oil on a sustained basis reduces U.S. producers' annual cash flow by approximately $32 billion, which suggests producers will need to reduce their capital programs significantly to remain within adjusted cash flow.

A number of recent producer announcements for the period to indicate capital cuts are larger and the rig count will be lower than we previously assumed in our industry outlook. However, we believe current price levels are unsustainable.

With the passage of time, we believe the supply excess will be worked off through a combination of modest demand growth and reduced activity levels resulting in achievement of a balanced market in the second half of 2016 or shortly thereafter.

This balance will be accompanied by declining inventory levels and a rise in prices to stimulate activity levels in order to satisfy rising demand. These developments should provide incremental visibility to near-term performance.

For those reasons, although we intend to continue to measure our performance against our guidance, we think there are really two key issues that are arguably the most important considerations when investors evaluate an investment in PAA in the current environment.

These two issues are PAA's ability to manage through an extended period of challenging industry conditions if needed and PAA's ability to grow meaningfully upon the industry recovery without having to rely on external capital or further organic expansion of its system. Consistent with this context, we have three simple goals for the coming year.

First is 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 also position PAA to benefit meaningfully as U.S. production volumes increase.

And lastly, optimize our assets and focus our organization to deliver the best possible results under whatever conditions we encounter in the near term. Let me close our comments with the observations provided on slide 11. PAA has the best, largest and most interconnected crude oil midstream platform in the U.S.

and a business model that has proven through performance during the period of a number of cycles. Second, solid balance sheet, significant liquidity and financial flexibility. We have fully funded financing needs for 2016 and substantially all of 2017.

We have very minimal debt maturities over the next 24 months, and we have no material capital commitments beyond 2017. We also have the ability to maintain our distribution while we work our way back toward our target distribution coverage of 105% to 110%, where we can then focus on resuming distribution growth.

Next, we have visibility for incremental cash flow contributions in 2016 and 2017 from project completions backed by MVCs and other contractual support. And then finally, we have 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 the U.S. crude oil production growth or what we have called recovery lift-off. And that investing in either security, they will generate attractive total returns, which an investor is getting paid handsomely while they wait.

Before we open the call up to questions, I want to mention that we will be holding our 2016 PAA and PAGP Investor Day on May 25 here in Houston. If you have not received an invitation but would like to attend, please contact our Investor Relations teams at 866-809-1291.

Once again, we thank you for participating in today's call and for your investment in PAA and PAGP. We look forward to updating you on our activities on our first quarter earnings call in May. Tom, at this time, we're ready to open up the call for questions..

Our first question is from the line of Brian Zarahn with Barclays. Please go ahead..

Good morning..

Good morning, Brian..

On your 2016 guidance, the Transportation segment obviously is the key growth driver and it's the bulk of your volume growth in the Permian.

Could you elaborate a bit on your assumptions on the base business in the Permian and then Cactus, Delaware Basin projects?.

We can. I think as far as our assumptions, we have as we mentioned earlier and Al mentioned, we had production in the onshore lower 48, Brian, I think, roughly 325,000 barrels down. To be clear, that's the average for 2016 versus the average for 2015.

On a peak-to-trough basis, if you go to the highest level in 2015 going down to the lowest level in 2016, I think it's about 650,000 to 700,000 barrels a day decrease. So I think our numbers are directionally lining up with others. It's just we're all trying to guess as to what may happen in the future.

With respect to Permian in particular, it and the Niobrara area, the DJ Basin are areas that we think are roughly flat to slightly up throughout the year. That's one of the things we'll just have to watch and monitor. The wells, there's being fewer rigs being put to work but they're having better success with each well.

So technology's kind of overcoming rig count. So we've got it roughly flat – I think maybe flat to up slightly 2% by the end of the year. As far as the volumes that we've got forecast to increase, a fair portion of those are associated with MVCs that have – ramping up throughout the year.

And then others are based upon activity levels and feedback we have from either acreage commitments from producers – and we know what activity levels they have – that's coming on to areas where we've kind of built out in the Delaware and the Midland Basin.

Is that fair, Harry?.

Yeah. So most of the growth really comes from the Delaware Basin. When we look at the Permian, we see probably growing volumes in the Delaware. And a lot of that's due to the fact that, that area's not as well developed, so you still have drilling to maintain leases and positions.

And maybe a little softer volumes in the Midland Basin relative to the Delaware Basin..

Okay. And then I appreciate the overview of counterparty risk.

On BridgeTex, on the shipper that's not currently shipping, is that a private or a public company?.

We don't give out information on – we're not required or allowed by regulation, Brian, to give any information on our customers there. But that volume hasn't been in any of our forecasts..

Understood.

And then on the remaining 70% of contracted capacity on BridgeTex, that's – any change on your outlook for those shippers?.

No..

Okay. And then turning to asset sales, you're certainly making progress upsizing a bit.

How should we think about after-tax proceeds of the $400 million to $500 million?.

After tax and before tax will be the same since it's on the U.S. side..

Okay. And then the last one for me, Greg. Given the fluid environment is certainly – it's a challenging backdrop, but you have taken care of your equity financing needs. You are raising your asset sales.

So putting everything together, any change in your potential distribution policy this year?.

No change..

Thank you..

Our next question is from the line of Jeremy Tonet with JPMorgan. Please go ahead..

Good morning..

Good morning, Jeremy..

I was just curious as far as the guidance outlook for 2016 and appreciating that's very much a fluid situation right now.

I think the market's just looking for whatever color that can be provided maybe sensitivity-wise, that if the current environment persists through year-end 2016, is there any sense you can give us for what that would do to the guidance in place or any ways to think about that?.

I mean it's an excellent question. A couple things kind of running counter to each other. So clearly to the extent that we have volumes that are forecast under MVCs that aren't produced, Jeremy, we'll still get the cash. But it may shift the recognition of that from EBITDA to deferred revenue.

So from a unitholder's or a debt holder's perspective, their biggest focus should be on our ability to collect cash. And so in that regard, we don't expect much in the way of variation under the MVCs. Again, it's going to affect the way we report it, but it's not going to affect the way we collect it.

With respect to Supply and Logistics, to the extent it stays in this environment, we're likely to see more opportunities on the – what we call unpredictable but recurring aspect of it. Just hard to – we just have trouble putting that in our numbers on a quarterly basis.

And so we're at $2.275 billion, if volumes stay in this range right here – I don't know, Al – we're off 3% or 4% at the end of the day. So it's meaningful but it's not huge, Jeremy.

It's not like it falls off the face of the earth because again, we've got – the volumes, whether they're $30 volumes or they're $100 barrels have to move through the transportation systems. I think because of our interconnected networks, and obviously, we're talking our book because we're very proud of it.

We're one of the few that actually have the ability to give our customers access to almost any market in any direction. And we're competing against some competitors out there that have individual pipelines that in that type of environment, we think they don't fare as well as we do. So we may be the tallest standing short person out there.

But we should be able to basically hold our market share, if not increase it in that type of environment. So we haven't forecasted it that way but we're certainly prepared to manage it that way..

Great. Thanks for that. And if I could just turn to a couple points in the guidance. I was just wondering if you could touch on as far as what the drivers are for the Eagle Ford growth. I think there was some volume growth in there and also the rail volume growth in the Supply and Logistics. Wondering if you could just expand on that a bit..

Sure. In the Eagle Ford, it's really just modest growth through this year and it's – a large part of that's tied to increased volumes off Cactus. Go ahead..

We actually have – Jeremy, I think we've got Cactus rolling over from a peak of about – skip Cactus, I'm sorry – we got the Eagle Ford rolling over from a peak of about 1.65 million barrels a day. I think we've got it rolling down 250,000 to 350,000 barrels a day. So we're actually projecting lower volumes in that regard.

But remember, we're transporting an increasing volume from West Texas down Cactus into our Eagle Ford JV system..

And then the second point I want to make is we completed an expansion of that system and has committed volumes on it in late August, early September. So you're getting the full-year impact of that next year versus only partial-year last year.

So if you look fourth quarter to first quarter, it's flat to probably down just a touch on the Eagle Ford volumes..

Okay. Great.

And then the rail for the Supply and Logistics, I think that was going up a bit 1Q 2016 to full-year 2016?.

The full year ramps up, yeah. And it's not all Supply and Logistics related. A lot of it's third party. And in the first part of the year, we have the expectation that some of that volume will get the MVCs on it, but we won't see the volume so it's not going to impact cash flow. And we have forecasted later in the year those volumes going back to rail.

If we miss on the volumes, it's not going to have a huge cash flow component to it..

Okay. Great. And then just one last one for me, if I could. In the past, I think you guys had discussed the potential to collapse the structure. I was just wondering if you could provide us for any updated thoughts there and when that might make – when and if that could make sense for you..

To be clear, what we've said is we are committed to evaluating a potential simplification to see if it makes sense. We're in the process of doing that. I think on the last call, we'd indicated it'd probably be middle of the year before we completed that. Candidly, Jeremy, trying to analyze anything today is like trying to nail Jell-O to a tree.

The valuations and the expectations are moving around significantly. So back to my Jell-O to a tree, I can see it and I can touch it but trying to control it right now when the valuation's moving around makes it very difficult.

But we do have the ability, obviously, to study it and be ready for it and have dialogue with some of our very large holders to see what might make sense. But nothing has been concluded. And in fact, quite candidly, we've been so focused in on addressing the capital side of it, we're just now turning our attention to that..

That makes sense. That's all very helpful. Thank you..

The next question's from the line of Kristina Kazarian with Deutsche Bank. Please go ahead..

Hey, guys..

Good morning..

I know you guys touched on this a couple times today, so just maybe if you could help me a bit more. When I'm thinking about the MVC deficiencies, how do I think about how much that MVC deficiency payments or deferral on payments makes up of my calendar year 2016 adjusted EBITDA assumptions? I'm just trying to understand a overall magnitude here..

Well, it's not in the EBITDA. If the answer is we assume that they're not going to meet the MVC, then we don't include it in EBITDA..

Okay. So – but then if I use that on a – so help me understand generally timeframe to companies either delivering the volume or when the make-up period expires. I'm just, one, trying to understand when that happens and then how I should be shifting around or how big the number is that I should be shifting around associated with that..

So just to be clear, I mean it's a number. It's probably 50 different types of MVC contracts or more. So when you asked that question, some of them may have a one-year make-up and some of them may have a two-year make-up....

Some quarterly..

Some quarterly. So it really just varies when you asked that. When we do our model, we have to make a judgment, so it's really hard to simplify. I would tell you order of magnitude, $50 million to $75 million, something like that..

Or less. Yeah. I would say 1% to 2% of our....

Yeah. So, as Al said, maybe – if you're worried about how much might be under delivery so that at the end of the year we have the cash but not the EBITDA and it's in deferred revenue....

Yeah..

Call it order of magnitude, 1% to 2%..

Yeah. That's really, really helpful. And then....

Yeah. I would just point out that in this type of environment, though, what we've figured out is if you miss by 1% or 2%, the market's kind of punitive. So we just wanted to make sure everybody understood what the presumptions were going into it..

Yeah. No, that's very helpful. And then another clarification question on counterparty risk.

The 2% number that you guys talked about, is that the upward bound on how you guys are thinking about risk associated with, especially maybe on the producer side, companies that may be (43:19) now but still okay; but if we look at them in six to eight months might enter the default range? So I guess the overall question is, how do I think about what the magnitude of risk that could come in the next 12 months but isn't quite here yet if we stay in the current commodity environment?.

So again, without giving away any specifics on a customer-by-customer basis, what we've looked at is, we've tried to figure out who is or could be in financial distress that makes up a small – a portion of that very small portion of non-investment-grade customers that we have on the producers side.

And that 2% by the definition of the word worst case assumed pretty much that, that if they had a challenge and they went into bankruptcy and we didn't get those volumes, that would be the 2%. To be very, very clear, that's – use the word worst case, that's what it's intended to be.

In almost every case, Kristina, where we're at, we have either the lowest or a very competitive transportation rate. And so the chances of us losing all that would be extremely slim and, in fact, we might end up not losing any of it. We might end up with the MVC associated with those types to go away.

But as a practical matter, when you're connected to their facilities and you're the only gathering system out of the area, there's not a lot of other place for them to get it around except for more expensive methods or requiring a lot of capital.

So we used the term worst case, assume that effectively, they either shut the wells in or somebody came in and displaced this. And that's just highly unlikely..

Yes. Again, really helpful on that number. So my last question for you guys is, when I think about the asset sales that we've talked about – and I know you guys have been very successful in executing two that have been publicly available for us to figure out so far. The (45:11) started 2 to 4; now it's 4 to 5.

Is that kind of what you're thinking about for 2016 on an end rate, or is there the potential for this number to come up again in 2016? Or maybe do we reassess this bucket at 2017 at some point?.

Well we always reassess, okay? So – but I think that's sort of the magnitude of what we expect to have completed in 2016..

Perfect. Thanks, guys. I appreciate it..

Thank you..

The next question's from the line of Faisel Khan with Citigroup. Please go ahead..

Yeah. Good morning..

Good morning..

On the volumes in the Transportation segment sort of down 5% from your guidance, I just want to understand. If you go back and give a little more granularity on what caused this. I know you said weather, some refining downtime, other things.

I think the concern that the market might have is that the wheels are coming up the track and volumes are going down faster than what you guys could forecast. I just want to understand sort of what caused the miss.

And the other part of that, too, is just, you used to give details on the volumes that were transported on different pipelines and so we could see if refining – if a refinery was down, we could see if one of the pipelines was running at a lower volume than the others. So we don't have that granularity anymore.

So I just want to understand why you removed that from the reporting results..

Well, from a reporting standpoint, we thought it was better to disclose it by area. It was only a couple of pipelines that we really had segregated information on. And if you take a look at – I'll give you an instance, Basin – or the Permian Basin. We sort of have a forecast on what is going to be exported out of the Permian Basin.

And whether that moves on Mesa, Basin, Sunrise or Cactus or BridgeTex, we're not so much worried about that because a lot of times what we found is that while one might be up, the other might be off. So we sort of aggregated in sort of the producing areas. From a volume standpoint, I think I sort of hit on all the high-level issues..

So just so I understand, the volume issue in terms of guidance versus where you ended up, is this all weather and downtime? Or was there some underlying production decline that caused numbers to be lower than what you thought? I'm just trying to understand....

Faisel, there really wasn't much in the way of unexpected declines that happened.

We did have and we acknowledged on the November report that we – some competitive forces showed up and we had barrels that were basically being moved from one area to another area by trucks, okay? And I think if you go back and read very carefully our language, we said we're going to change our approach and become much more aggressive on capturing those volumes.

And I think, order of magnitude, we probably, by the end of the quarter, fourth quarter, had captured back as much as 60,000 or 70,000 barrels a day. When you say volumes are going down, if you actually look quarter to quarter to quarter, they're going up.

What's happening is they're going up at a lesser rate than we may have thought six or seven months ago. Because of these issues you're raising in general, the decreased rate of growth at a particular area or the increased competition And so it's not really areas really fallen off the face of the map. There's clearly some competitive issues.

I think if you got in a truck or a car and you drove through West Texas, right now, you're going to see what's happening out there. There's probably 200 or 300 trucks from third-party haulers that are sitting there unused right now.

Part of that's because we built pipelines and part is because Plains has become more aggressive at capturing those volumes and making sure that we use our entire value chain to optimize the margins..

Hey, Faisel, I can give you a little more detail. I know we probably had 20,000 to 25,000 barrels a day. The volumes are there; they were just quality issues so it couldn't go in the pipe. And those are being remedied by the producers because it's to their economic advantage to have it on pipe versus on trucks.

We had some refinery turnarounds that probably made up another 30,000, 35,000 barrels a day. So that's not – refinery turnarounds occur, but these happen to occur at extent a little longer than we had anticipated in our guidance. So we'll still see the volumes there. We probably had 20,000, 25,000 barrels a day related to MVCs on one pipe.

So does that give you a little better perspective on....

Yeah. No, it does. Yeah.

And then just on the volumes from the Midland to Cushing, I mean was there any – do you see any sort of impact to sort of the competitive forces there? Or were you roughly flowing the volumes you thought you would on the Midland to Cushing route, I mean given how basis differentials have sort of moved around a little bit?.

Those were actually in line with what we had expected. But when you look at Basin Pipeline, it's kind of a unique pipeline. Our EBITDA is pretty close to the same, whether that volume goes to Cushing or it goes to Wichita Falls, it goes to connecting carriers....

Sure..

Or if it goes to Colorado City and goes to connecting carriers. So the tariffs are set up on a sliding scale that we're almost indifferent is to whether that goes to Colorado City and then down to the Gulf Coast or whether that barrel goes all the way to Cushing. So – but the volumes on Basin were pretty much in line with what we expected..

Okay. And then just going back to the – how you report the MVCs and deferred revenue. So I understand that those numbers will not show up in EBITDA, but my understanding is they will show up in DCF.

Is that the correct way to look at it?.

We haven't modified our DCF to include that cash yet. We're trying to study how to do it. It's just now becoming an issue that I think the industry's focused in on.

And we've seen in some areas or some companies that we've monitored so far that have had a little bit bigger issue than we have on a trailing basis where they have added in cash received and then back out EBITDA recorded for make-up volumes that were really associated with cash received in the prior period..

Right..

And, Faisel, we're probably going to try to resolve that before we get to the next quarter. Again, $15 million on a $2.2 billion number, we just haven't taken a position on it yet. But we're going to try to make sure because we think, as a general rule, it's going to be a bigger issue for the industry as a whole.

We've studied balance sheets of others, and we've seen a couple of companies that may have as much as $400 million or $500 million cumulative deferred revenue on their balance sheet. That's probably a big enough size to where you need to make an adjustment.

So far, at $15 million, it hasn't become big enough yet for us but we're probably going to do it in 2016 sometime. And we'll make sure we clarify that on our next release as to how we handle that..

Okay. Makes sense. And last question for me. That the Line 901 incident, just want to make sure I understand where you guys are on that process and when we could see sort of that line repaired and being brought back to service..

I'm not so sure I'd rather predict regulatory agencies or crude oil prices. Neither one of them are very precise. Let me just tell you where we are from a physical standpoint. Cleanup was effectively accomplished within almost three months – three-and-a-half months of the release.

So by middle, late August, we had basically concluded most of the clean-up activities or substantially all. We were in monitoring mode. We're very close to being through the monitoring mode now because we've had a long time. So from that standpoint, the costs are all reflected. We made the accrual.

We've trued that up here recently with just a minor amount. As far as the regulatory process, we're still going through a lot of details there where effectively, there's been a root cause analysis but it's still in draft form.

And until we get that totally resolved, we haven't come out with a forecast publicly as to when that might be put back in service.

Order of magnitude, that's probably in the $40 million-a-year cash flow impact?.

$35 million to $40 million. And then we don't have anything forecasted in 2016 on the volumes. And as Greg mentioned, we can't submit the restart plan until the root cause analysis is completed. So that's sort of where we are right now. We're getting close to finalization, but then we'll provide a restart plan..

Okay. Makes sense. I appreciate the time, guys. Thank you..

Thank you..

The next question's from the line of Ethan Bellamy with Baird. Please go ahead..

Hey, guys. Good morning.

Greg, what's the crude oil price embedded in your guidance for 2016?.

So – and again, we generated this in the middle of December – we had $35 for the first quarter, $45 for the second, $55 I think in the third and $60 in the fourth. So it averaged about $47.50. Currently right now, obviously, we're below that.

I think – this is qualified as Greg Armstrong's personal opinion – the longer we stay underneath that forecast, the more likely the end-of-the-year forecast is going to be right. But that's what was embedded in that. And we tried to true-up, Ethan, budgets against that for purposes of drilling activities and rig counts in different areas.

And as I mentioned earlier, I think we had areas like the Mid-continent, Eagle Ford and the Bakken trending down volume-wise. And we had relatively flat, very slightly up in the Permian and the DJ.

The takeaway from this call is, if obviously if the rig count is falling faster and it's not offset by efficiencies, we're probably going to see by the time we get to the middle of the year volumes rolling over more than what we forecasted.

So we may have some shift from EBITDA to deferred revenue on the MVC contracts, but again, we'll have the cash..

Okay. That's helpful.

And then with respect to the reduced equity credit on the preferred, are you still one and done for equity purposes for Moody's, despite the fact that the balance sheet's okay? And does their reluctance to give you equity credit specifically force your hand to raise more equity at some point or sooner than you otherwise would have?.

No. We're still one and done. And as a practical matter, I mean we raised enough not only to defease our obligations for 2016 but almost all of 2017. And we have no meaningful debt maturities, Ethan. I think we have $175 million in August of 2016 and $400 million in January and then that's it.

And if you look at our liquidity position, whether we carry that as debt on Senior notes or whether we carry it as debt on our existing credit facilities really makes no difference to agencies.

So I don't think they're in a situation where – they acknowledge that it's, I think, better to have preferred on the balance sheet that it would be to have the proportion of debt and equity. There is just – it's a phenomenon, the way they treat it in their ratings process.

We are on negative outlook at Moody's at Baa2, so God forbid, they should do the wrong thing and downgrade us. We're still investment grade at both agencies.

So we really don't have a gun to our head to do anything that would be illogical, and we have every clear sight – line of sight basically to finish the capital program for 2016 and 2017 without any derail (57:37) in the markets at all..

Okay. That's helpful. Then one last one.

Are the noncore asset sales baked into the guidance? And if you sell $500 million in assets and complete $1.5 billion in capital projects, what's the net gain to cash flow going to be from that – from those two things that offset somewhat?.

We haven't provided information on the latter part of it. But to answer your first part, should give you comfort, it is built into our guidance. If we complete a sale a month earlier than we forecast, we may have to tweak it a little bit, but it's not like we left it in for the whole year.

And then the other element is, is that while we have – I think we originally gave guidance that said we'd sell $200 million to $400 million. And we've increased that a little bit. We're working on some acquisitions as well that might offset that and bring back incrementally more cash flow.

Clearly, we're going to try to sell at one multiple and buy at another multiple in terms of what we realize, realizing that the buyers that buy from us intend to enhance it with synergies. And so it'll be a net trade up.

If we can buy at X multiple and – excuse me – sell at X multiple and buy at 60% of X multiple, that's going to be a net add to the forecast that we provided to you. But we have factored out the asset sales out of there. We haven't factored any new purchases in there..

I think you'll see that the people that buy the assets from us have synergies as well, so that's what sort of makes the multiples work..

That's helpful. Thank you..

The next question's from the line of John Edwards with Credit Suisse. Please go ahead..

Yeah. Thanks, everybody. Greg, just following up Ethan's last question.

What's the projected timing right now of the asset sales in the guidance?.

Between now and midyear..

Yeah. Second quarter..

I mean you got regulatory approvals and things that have to be done, but between here and the middle of the year..

Okay.

And then similar, you're expecting that for the acquisitions you're contemplating?.

Subject to regulatory stuff, yeah..

Okay. And then just kind of going back to Faisel's question on competitive forces, just – you talk a little bit about volumes.

Just, if we're translating the impact of those forces from a – call it, from a revenue standpoint, how should we be – and even from a rate standpoint, how should we be thinking about that?.

Well I mean we tried to factor all that into our guidance. We were, I think it's fair to say, widely criticized for coming out in August of last year and saying we think this is going to be much more competitive, and we lowered our guidance because of that. We factored that in.

Whether we got it precisely right or not, we'll find out at the end of the year. But I think we're being as forthright as we possibly can to say, this is what we think the impact will be in a highly competitive environment on volumes and on margins.

And somebody asked the question earlier, if it stays lower for longer, I feel pretty good about our role in that.

I think what happens is we probably end up with more market share at the end of the day because I think we've got weaker competitors in Plains; weaker from the standpoint of not only balance sheets but weaker from the standpoint of the lack of interconnected assets that allowed them to – us to be able to capture full-cycle margins as opposed to discrete assets..

Okay. So I mean in terms of pricing, I mean how much kind of percentage-wise? Can you talk at all about that, how much it's impacting? And then we're presuming already baked in your guidance or any kind of contract renewals and such. If you can comment on that, it would be helpful, too..

The margin pressure's going to be in Supply and Logistics, not in the Transportation segment..

Okay..

Yeah.

And then as far as trying to quantify it, I mean I think what's our – Al, our Supply and Logistics is $486 million?.

Yeah..

Okay?.

Yeah..

Against – we had $560 million. So I mean if you just do the spread, it's probably about $75 million against that year-to-year comparison, John. And then we've given guidance in the past and we thought is $500 million to $550 million is the baseline. So if you use the $525 million, you'd straddle a range roughly of $40 million to $70 million.

But again, that's built into our guidance....

All right..

Our gas storage business, there's really no re-contracting risk..

Okay.

And then so the numbers you're giving in the guidance, that's the $1.13 that – you're basically baking in – the competitive landscape is baked into those estimates, correct, or that guidance, right?.

Bingo..

Yeah. Okay. Great. All right. Thanks. And then I guess the other thing, just I'm kind of wondering from where you guys sit is how are you guys thinking about reconciling the fact that you're seeing these volumes that are declining but the storage keeps building in the U.S.

and you're seeing it go up? I mean can you give us any kind of macro commentary in regard to how maybe we should be thinking about that? I know you don't want to really talk about the crude oil price forecast, but obviously, maybe that could help our own thinking in that regard..

John, the biggest driver to inventories is imports. And if you'll notice, the imports for the first four weeks of this year have been upwards of 8 million barrels a day. We can all talk about reasons why that is. But effectively, we've built in the U.S. almost 100 million barrels of inventory by the end of 2015.

And if you go back to our Analyst Day, we gave a forecast for that, and we were off, but we were, I think, much closer than many. I think we had it on our high-side case being about 83 million barrels at the end of 2015 relative to 2014, and it came in very close to 100 million barrels.

We see it continuing to build because bottom line is production's not falling off as much as predicted and imports continue to stay relatively high. And so we've got it trending up until turnarounds are completed in probably the end of April, first part – excuse me – end of April – yeah, end of April, first part of May.

And then we start to see the decline coming down and of course, we also see demand being stimulated by lower prices. So ultimately, we start feeling pretty good about the end of 2016. We could be wrong.

And if it turns out that the price doesn't hit our target until the first quarter of 2017, we're not going to do a lot of apologizing because that's pretty close by just about any measure. So....

Okay. Great. That's helpful. That's all I have. Thanks..

Next question is from the line of Chris Sighinolfi with Jefferies. Please go ahead..

Hey, Greg. Good morning..

Good morning..

Just wanted to follow up on – appreciate you confirming Ethan's question about the cadence of your price expectations. Just curious – there're so many moving parts within the business.

How do you think about sort of relative sensitivities if the market proves to be materially stronger or weaker than what you guys have forecasted as a base across the three segments?.

Yeah. I'll probably focus in on the materially weaker. If it's stronger, there's so many variables that go into how it got there, et cetera. But I think order of magnitude, I think what we're saying is 3% to 4% on the downside.

And hopefully, there's mitigating factors that make that even less because again, depending on what triggers it to stay low, if we continue to stay in a very pronounced contango, our ability to earn returns on our storage assets improves quite a bit. So it's not like it's huge. It's not a 10% adjustment downward if it stays in this range.

It's less than 5%; probably closer to 3%..

You're saying on the aggregate guidance numbers you gave..

Correct..

Yeah. Okay. Okay. And then just to confirm the implied DCF that you guys guided in last night's release and on slide 10, that's prior to the distributions on the preferred.

Right?.

Correct..

Correct..

Okay. And then the final point of just inquiry for me is Note number nine to the 8-K you guys put out last night, which is – deals with the equity – indexed equity compensation. It says within that, Greg, that you've made the assessment that a $2.90 annualized distribution is probable in the reasonable foreseeable future.

So I was just curious how to interpret that relative to the dialogue you had with (01:06:33) on the January call about how we should, for all reasonable expectations, expect something flat at $2.80 for the next couple years..

Well, I mean we have to look at our extended forecast when we do that. We also, I think, had already hit $2.90 before the bottom fell out, so we just left it at the same. We didn't try to go back and recapture and record income because we would lower probabilities. We just left there..

Oh, understood. Understood. Okay. So you were there from – calculating the equity comp before everything and then you just left it flat..

That is correct..

Correct..

Yeah. That level has been in place for, I think, well over 12 months..

Okay. Thank you very much for confirming that. Thanks, guys..

The next question's from the line of Becca Followill with U.S. Capital Advisors. Please go ahead..

Good morning, guys, and thanks for extending the call. Just still confused on the Permian volumes on Transportation. So it looks like on your guidance, average 2015 versus average 2016 is up about 500,000 barrels a day; and from Q4, it's up about 400,000.

Yet, I don't think you guys you are forecasting that Permian volumes in aggregate for the industry grow by that level.

So I know there's new pipes coming on, but assume this is a significant market share that you're taking from the industry?.

Well, keep in mind sometimes if we have two tariff movements in there, Becca, you're going to count the same barrel twice, right? So we have tariff movement A to B, it's a separate tariff. And then if they move it from B to C, that's going to be another tariff volume. So you're going to have some double counting.

It always happens depending on where the volumes move. And then we have MVC step-ups throughout the year. So to the extent that volumes don't increase to that, yeah, it's a market share issue. But again, if we've got the contracts behind it, I feel pretty good forecasting that.

Again, if it turns out they don't ship on that and they choose to go another route, I'm still going to get the cash..

So some of the connectivity that you've increased, that's kind of an exacerbating the increase because then you get to flow on a separate pipeline in addition to the new pipeline that you just built with the connectivity..

We're all about value chain. If I can collect three tariffs for one barrel, that's outstanding. Yeah..

Great. That's all I had. Thank you, guys..

And just so you know, Becca, you look at the end of the fourth quarter, the volumes are higher than they were earlier in the fourth quarter as well. So even when you look fourth quarter, the first quarter, it's not as much of a ramp if you go to December and January as you might think..

Thank you..

Next question is from the line of Michael Blum with Wells Fargo. Please go ahead..

Thanks. Just one question. If Moody's were to, as you said, Greg, God forbid, downgrade you guys and realizing that you'd still be investment grade.

My question is just simply, are there any ramifications in terms of just the cost of doing business, whether that's the Supply and Logistics, counterparty, posting letters of credit, the cost of your facility? Just trying to think through that scenario..

Yeah. To be clear, I said if they do the wrong thing and downgrade us, I think is the way I said it. But nonetheless, if they take that action, no, it's not going to have a material impact on our business..

Great. Thank you..

Our next question's from the line of Jeff Birnbaum with Wunderlich. Please go ahead..

Yeah. Good morning, everyone, and thanks again for taking so many questions today. Most of mine have already been asked and answered, so just a couple follow-ups. Greg, I just wanted to clarify your comment earlier.

The 2% worst-case scenario on sort of your credit counterparties, that was reflective of all non-investment-grade counterparty cash flows, right? I guess where I'm going with that is given that things are so fluid, is there a way to sort of further segment that into perhaps, call it – and maybe this could be something going forward, where you tier that based on investment-grade ratings, call it, upper medium to lower medium so that investors can get a bit of a better sense of how things can re-develop as we move through this very fluid 2016?.

I think the best thing we can do is keep you apprised as we go through there. Again, we went to a worst-case scenario. We tried to make that assessment as to who we thought was investment grade today that for some reason might not be investment grade that then might not honor their contract. And we gave your our best shot at the worst case at the 2%..

And Jeff, just to be clear, most of the focus that we believe and most of the questions we've gotten had been around the producers. So that 2% was a estimate based on non-investment-grade producer, shippers..

Okay. Thanks. And then a couple, just on the preferreds.

Are you assuming you're going to pick those at this point, just kind of given how the (1:11:40) laid out last night?.

No. We've got it forecast as cash pay..

You do. Okay. Thank you. And then one last question on the maintenance CapEx down slightly the second year in a row.

I just guess, what was driving that?.

Pretty much just work schedules and not needing to repeat, repairs..

Yeah..

And a little bit of it is some of the assets we've sold were a little bit – had a higher maintenance capital, so some of that....

I think that's probably the biggest component of it..

Understood. Thanks, guys..

Next question is from the line of Selman Akyol with Stifel. Please go ahead..

Thank you, and I am appreciative of the additional time. Real quickly, you guys had talked about, in terms of refineries being able to request additional security if you need it.

Have you requested that from anybody, or do you have any other parties out there you are seeking additional security on?.

From time to time, we do. I mean that's a very standard provision in virtually any purchase or sales contracts in the crude oil business. And so from time to time, we do, do that. Now granted, you're extending credit for 60 days, so it's not a frequent thing. You normally know before you extend it, should you be worried or not and ask for it.

But occasionally, you do implement that..

All right. So in this environment, it's not like anything's changed or the way you're looking at it..

No..

It just comes up on an as-needed basis? Okay. All right. Thanks very much..

Yeah. Our view on crude oil sales is we should have zero credit losses on it, and that's been our track record..

Tom, I think we've got two more questions in the queue. We'll take those two and then wrap this up..

Okay. Next question's from the line of Sunil Sibal with Seaport Global Securities. Please go ahead..

Hi. Good morning, guys, and I appreciate all the color and you guys taking the time. So I have just one quick clarification on Supply and Logistics. First of all, I presume that $440 million to $540 number includes a $15 million carryover from fourth quarter 2015.

And then now that Permian is pretty well plumbed, any particular region which will kind of impact your unit margins of $1.13 in that segment?.

So the $15 million carryover was included – is included in our 2016 guidance, so that answers the first part of your question.

And then the second part, were you're asking if there's the potential for any further compression in the $1.13 margin?.

Yeah.

That and then any particular area where – which will have increased sensitivity to that margin whether basis differentials or quality differential-wise?.

Yeah. Well first off, the $1.13 is the mathematical result of different variations. You're going to have higher and lower margins in different areas, Sunil.

So I think what we've tried to do and again, we've tried to be as forthright as – we've tried to give our best guesstimate of what that impact is going to be on a per-unit basis as a result of an area-by-area build-up. So we've given you what we think is out there in that regard and suggest that it's going to be below baseline for that.

So there's not much more granularity we can provide without giving somebody a roadmap for how we compete in each area..

All right, guys. This is very helpful. That's all I have. Thanks..

Thank you..

And the last question is from the line of Noah Lerner with the Hartz Capital. Please go ahead..

Thank you. I'll try to make this brief because you guys have given us a lot of time. Just quick question. When you're talking about the credit support when you – getting back to the 85% of the credit exposure in market and Logistics is investment grade or LLC.

Do those LLCs cover 100% of the value of the contract, 12 months of the value of the contract? I'm just trying to get a sense, an investment-grade company you can have a multiyear comfort as you weaken.

But if you had to against a line of credit – a letter of credit rather, how much security does that really provide you?.

Our LCs in crude oil sales – and this is I think universal across not only us but across the industry – are typically, Noah, set up for 60-day periods. Your max credit exposure generally is 58. You settle on the 20th of the month following. You don't re-extend.

So you don't have term deals for a year where you wouldn't have the ability to react before you ever delivered that volume. So these are generally 30-day sales. So what I would tell you is if you have a customer that you're giving zero credit to and you're selling and you're getting LCs, you have no un-hedged exposure there. No remaining exposure..

But you may – just to pick a number, you may end up with somebody – you've got $10 million a month exposure, so you have either a $20 million LC or you may say, I'm going to extend them a $2 million open line and then give an $18 million LC, realizing that every month it kind of refreshes because what rolls off gets renewed.

So you'll have it – you may have that LC in place for one or two years. But as Al pointed out, it's only for 60 days in terms of life expiration. And they renew it each time you have month roll off..

So all the counterparties to the MVC contractual support that's laid out on slide eight, that's above and beyond these people we're talking about here, the producers for the markets and Logistics.

Is that a correct statement?.

Yes. Yeah. They're two different things..

Okay..

So you're talking about Facilities and Transportation is what's all these projects that you see on slide eight are related to the tariff or the fee-based on Facilities..

Okay. So how've you gone about, I guess, monitoring? And what kind of credit risk is there to those counterparties not being able – you have one that you've now given zero credit to in your guidance, that's not going to be able to live up to their minimum volume commitments, so you basically put them in zero because you think they're on the ropes.

How do you go about taking this – all those contracts coming on board and all those counterparty risks into the guidance?.

On the....

Are most of those guys investment grade or are there non-investment-grade guys there as well?.

Yeah. And Noah, I walked through that. Virtually, all – the large majority of our MVCs supporting our pipeline systems are investments grade. There are several that are non-investment-grade refiners behind kind of demand-pull projects. And we've got several that are non-investment-grade producers, i.e. supply-push ones.

And we quantified that being kind of the worst case, 2% of our 2016 adjusted EBITDA, the exposure on that. You don't take a 10- or 15-year MVC-type of deal and get an LP to support them. So we have open credit for these..

Yeah. And, Noah, if I can, I mean just remember, the beauty of our system is it's an integrated, interconnected system, so – and we've been at this for quite a long time.

So there's been – in the past, for example, we may've built a pipeline to a refiner, okay? And so we would have to obviously monitor the heck out of the credit worthiness of that refiner. But when we built that, we also knew they were gathering local area volumes.

And if something happened to that refinery and they shut down, then we reverse that pipeline. And we move the barrels they used to gather locally that they ran through the refinery now have to be moved to a different market.

So about everything that we do has a plan and a backup plan, and that's a trademark and a hallmark of Plains' integrated system because we can always find a home for the crude because we are interconnected. So I think you're asking a great question.

I just think it would be tougher on somebody that had a one-trick pony than somebody that had an integrated system with a lot of corrals and a lot of ponies..

Okay. And then one last one, looping back real quick to that failure of the MVC or the failure of the counterparty on the BridgeTex pipeline.

What's the process and what's the timing as far as you guys being able to go out into the marketplace and replace that customer? Do you have to wait for them to declare bankruptcy and go through the whole bankruptcy process? Can you try to re-contract them now?.

Yeah. So again, a couple of things – and I'm going to go back to Al's comment – we don't get into specifics on particular customers. But keep in mind, number one, that was an acquired contract. When we bought the pipeline, it came with it. So it wasn't necessarily a judgment we made to extend that was a bad judgment.

It was just something that came with it, and we factored that in, to some extent, in our analysis, number one. And then number two, we have the ability because we do move a lot of barrels to capture value in assets that are underutilized.

So again, wouldn't want to sit here and have a discussion on the phone about how we – it might impact our collection, I guess, because just we don't record it in the future for forecast doesn't mean we don't pursue it from a contractual nature through the courts..

Got you. Okay. Great. Thanks a lot..

Thanks..

Tom, I believe that's the last question.

Why don't we go ahead and wrap the call up, please?.

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