Plains GP Holdings LP (PAGP) 2015 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the PAA and [PAGP] 4Q 2015 and final year results call.

(Operator Instructions)

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 Plain's 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 Chiang, Chief Operating Officer US; and Al Swanson, Chief Financial Officer. In addition to these gentlemen and myself we have several other members of our senior management team present and available for the Q&A portion of today's call.

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

Thanks, Ryan.

Good morning and welcome to everybody. Yesterday PAA reported fourth-quarter and full-year 2015 results. Slide 3 contains comparisons of PAA's performance metrics to the same quarter last year and also to the fourth-quarter 2015 guidance as furnished of November 3, 2015.

Adjusted EBITDA for the fourth quarter 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 range as 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 commitment 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 amount will be transferred to revenue when the makeup occurs 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 an 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'll 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 mid-point 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 4, adjusted segment profit for the transportation segment was $256 million, or approximately $19 million below the mid-point of our guidance. Approximately $6 million of the shortfall is related to volume deficiencies under minimum volume contract 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 pipeline were approximately 40,000 barrels per day less than anticipated due to a combination of one maintenance issue with a third party connecting pipeline, and then secondly, lower than expected volumes under a minimum volume commitments contract.

The balance of the volumetric shortfall was due to a combination of first, longer than forecasted refinery turnaround; second, certain receipts not meeting our pipeline quality specifications; third, short-term diversions of volumes around certain bottlenecked 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 facility segment was $150 million, which was approximately $10 million above the mid-point of our guide.

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 mid-point of our guidance, 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 mid-point of our guidance.

Volumes of approximately 1.2 million barrels per day were in line with our guidance, however NGL sale 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 mid-point 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 in 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 US and Canada. This is basically timing issues; these volumes are expected to be delivered in 2016.

Slide 5 provides an illustration that reconciles our fourth-quarter guidance furnished in November to our fourth-quarter 2015 performance. The key take away from this slide is that the negative variance was primarily related to the two timing issues previously mentioned.

Let me now move to slide 6 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% of the 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 -- 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 the facility 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 second quarter 2016.

Adjusted segment profit per barrel is expected to be $0.40, which is $0.01 higher than 2015. For 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 the segment is due to anticipated increases in NGL sale activity. Segment profit per barrel is lower due to our expectation that we will continue to have a challenging crude oil market conditions into 2016.

Finally, slide 7 provides a summary illustration by segment of our 2016 adjusted EBITDA guidance compared to our 2015 performance.

Moving on to our capital program, slide 8 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 an 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 for the project.

Additionally, in December, Valero exercised their option to acquire a 50% interest in our Diamond pipeline project, which reduced PAA's cost in 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.

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 counter-party credit and performance risk. PAA ended 2015 with a solid financial position which is illustrated on slide 9. We had long term debt-to-capitalization ratio of 57%, a long-term debt-to-adjusted EBITDA ratio 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 9. We hosted a detailed conference call announcing the financing on January 12 where we characterized this as a one and done transaction that pre-funds 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 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 mid-point 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 mid-point 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 will adjust our forecast to reflect variances between forecasted volumes and the volumes we will be paid cash for under the MVC arrangement. In all cases we have excluded from our cash forecast expected shortfalls from counter-parties that we deem to be of questionable collection.

With respect to our supply and logistics 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 pressures will continue to negatively impact lease gathering margins and type basis differentials in the current environment.

The right half of slide 10 highlights two aspects of our 2015 guidance. The first is the build in our fee-based transportation and facility segment the 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 letters of credit or prepayments. For these crude oil sales, approximately 85% of the exposure is to investment grade [entities] or where we have secured the exposure by letters of credit and prepayment.

The remaining 15% is open credit to noninvestment 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.

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.

Counter-party 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 facility segment, our supply and logistics segment is a significant customer with a 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 the investment grade entities.

Demand for storage capacity in this oversupplied environment has remained strong and overall we believe that where there may be risk 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 fairly 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 line fill on the pipelines which, as with the facility 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 noninvestment grade refiners associated with demand pull projects or noninvestment grade producers on supply push projects.

The performance risk associated with noninvestment 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 counter-party 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 the 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 issuance is -- 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 declined 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 US and Canadian crude oil industry.

PAA is quite frankly the largest crude oil centric midstream MLP with leading positions in substantially all US and Canadian resource plays and market interchanges and has the most interconnected crude oil transportation terminaling 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's somewhat upside down. By that I mean the long-term view is clearer than the short-term. Over the intermediate to long-term it's very clear that the industry cannot replace production declines or meet projected crude oil demand with oil at $30 per barrel, and the world will need US production growth to balance the market.

As a result, the proven and well-defined North American resource base and every improving technology bode very well for the US 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 had 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 month, 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 producer's 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, the 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 US producers' annual cash flow by approximately $32 billion, which suggests producers will need to reduce their capital program significantly to remain within adjusted cash flow. A number of recent producer announcements would appear 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 access will be worked off through a combination of modest demand growth and reduced activity levels resulting in achievement of a balance 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 demands. 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 -- or industry conditions if needed, and PAA's ability to grow meaningfully upon 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 US 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 my comments with the observations provided on slide 11. PAA has the best, largest, and most interconnected crude oil midstream platform in the US, and a business model that is proven through performance during a period of a number of cycles. Second, of that 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 to where our target distribution coverage, or 105% to 110% at 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 US crude oil production with no to low incremental CapEx. For those reasons, we believe PAA and PAGP represent inexpensive, low risk, long dated calls on US crude oil production growth or what we have called recovery lift off, and that investing in either security today will generate attractive total returns which an investor's 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 team 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 are ready to open up the call for questions.

(Operator Instructions)

Brian Zarahn, Barclays.

Good morning.

Good morning, Brian.

On your 2016 guidance, the Transportation segment obviously is the key growth driver. And the bulk of your volume growth is 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, as we mentioned earlier and Al mentioned, we had production in the onshore lower 48, Brian, I think roughly at 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 750,000 barrels a day decrease. 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 [Nine Briar] area of the DJ Basin are areas that we think are roughly flat to slightly up throughout the year. That's one of the things that we will just have to watch and monitor. The wells -- there's being fewer rigs being put to work, but they are having better success with each well. So technology is 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 are ramping up throughout the year. And then others are based upon activity levels that in feedback we have from either acreage commitments from producers. And we know what activity levels they have that's coming onto areas where we have built out in the Delaware and Midland Basin.

Is that fair, Harry?

Yes, 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 area is not as well developed, so you still have drilling to maintain leases at positions and maybe a little softer volumes in the Midland Basin relative to the Delaware Basin.

I appreciate the overview of counterparty risk. On BridgeTex, on the shipper that's not currently shipping, is that a private or public company?

We don't give out information on -- we are not 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, any change on your outlook for those shippers?

No.

Okay. And then turning to asset sales, you are 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 US side.

Okay and the last one for me.

Greg, given the fluid environment, certainly it's a challenging backdrop. But you have taken care of the 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.

Jeremy Tonet, JPMorgan.

Good morning.

Good morning, Jeremy.

I was just curious. As far as the guidance outlook for 2016, I appreciate that it's very much a fluid situation right now. I think the market is just looking for whatever color that can be provided. Maybe sensitivity-wise, 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?

No. It's an excellent question and a couple things kind of running counter to each other. Clearly to the extent that we have volumes that are forecast under MVCs that aren't produced, Jeremy, we will still get the cash. But it may shift the recognition of that from EBITDA to deferred revenue.

So from a unitholder's or 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 what we call unpredictable but recurring aspect of it. We just have trouble putting that in our numbers on a quarterly basis. So we're at 2.275, if volumes stay in this range right here.

I don't know, Al, if 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 are $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 are 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 are 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 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 there and also the rail volume growth in the supply and logistics. Wondering if you could expand on that a bit.

Sure, in the Eagle Ford, it's really just modest growth through this year. And a large part of that is tied to increase volumes on Cactus.

Jeremy, I think we've 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 barrels to 350,000 barrels a day. So we're actually projecting lower volumes in that regard. But remember, we are transporting an increasing volume from West Texas down in Cactus into our Eagle Ford JB system.

And then the second point I want to make is we completed an expansion of that system, and it 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. It's not all supply and logistics related. A lot of it's third party. And in the first part of the year, we had 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 it 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 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 and if that could make sense for you?

To be clear, what we said is we are committed to evaluating 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 would 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 moves around makes it very difficult.

But we do have the ability, obviously, to study it and be ready for 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 have 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.

Kristina Kazarian, Deutsche Bank.

Hello.

Good morning.

I know you touched on this a couple times today, so just maybe if you can 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 overall magnitude here.

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

Okay, so help me understand generally timeframe to companies either delivering the volume or when the makeup period expires. I'm just 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?

Just to be clear, it's a number. It's probably 50 different types of MVC contracts or more. So when you ask that question, some of them may have a one-year makeup and some of them may have a two-year makeup.

And some quarterly.

Some quarterly, so it really just varies. 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

1% to 2% of our --

As Al said, if you're worried about how much might be under delivery. So at the end of the year, we have the cash but not the EBITDA and it's in deferred revenue. Call it order of magnitude 1% to 2%.

That's really helpful.

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

That's very helpful.

And another clarification question on counterparty risk. The 2% number that you talked about, is that the upward bound on how you are thinking about risk associated with, especially maybe on the producer side, companies that may be non (inaudible) now but still okay? But if we look at them in six to eight months might enter the default range?

So 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?

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 portion of that very small portion of no-investment grade customers that we have on the producer side. That 2%, by the definition of the word worst-case, assumed pretty much 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 -- use the word worst-case, that's what it's intended to be. In almost every case, Kristina, where we are at, we have either the lowest are a very competitive transportation rate. And so the chances of us losing all of 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 are connected to their facilities and you are the only gathering system out of the area, there's not a lot of other ways for them to get it around it except for more expensive methods or requiring a lot of capital. So we use the term worst-case to assume that effectively they either shut the wells in, or somebody came in and displaced us. And that's just highly unlikely

Yes, again, really helpful on that number.

My last question for you is when I think about the asset sales that we've talked about -- and I know you have been very successful in executing two that have been publicly available for us to figure out so far. The rate started at 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?

We always reassess, okay? But I think that's sort of the magnitude of what we expect to have completed in 2016

Perfect, thanks, I appreciate it.

Thank you.

Faisel Khan, Citigroup.

Good morning.

Good morning.

On the volumes in the Transportation segment, sort of down 5% from your guidance, I want to understand. If you could go back and give a little more granularity on what caused it. I know you said weather or some refining downtime, other things. I think the concern that the market might have is that wheels are coming off the track and volumes are going down faster than what you could forecast. I just want to understand 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. So we could see if a refinery was down, we could see of one of the pipelines was running a lower volume than the others. So we don't have that granularity anymore. So I want to understand why you removed that from the reporting results.

From a reporting standpoint, we thought it was a better disclosure 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 -- the Permian Basin. We sort of have a forecast on what is going to be exported out of the Permian Basin.

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

I understand the volume issue in terms of guidance versus where you ended up. Is it 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 some competitive forces showed up. And we had barrels that were basically being moved from one area to another area by trucks. 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 fourth quarter had captured back as much as 60,000 barrels or 70,000 barrels a day.

When you say volumes are going down, if you actually look quarter to quarter to quarter, they are 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 are raising -- in general, the decreased rate of growth in a particular area or the increased competition. It's not really areas really falling off the face of the map. There are 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 are probably 200 or 300 trucks from third-party haulers that are sitting there unused right now. Part of that is 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.

Faisel, I can give you a little more detail. I know we probably had 20,000 barrels to 25,000 barrels a day. The volumes are there; there were just quality issues, so they couldn't go on the pipe]. Those are being remedied by the producers because it's to their economic advantage to have it on pipe versus on truck. We had some refinery turnarounds that probably made up another 30,000 barrels or 35,000 barrels a day.

So refinery turnarounds occur, but these happened to occur and extend a little longer than we had anticipated in our guidance. So (inaudible) the volumes there, we probably had 20,000 barrels to 25,000 barrels a day related to MVC on one pipe.

Does that give you a little better picture?

Yes, it does. And then on the volumes from the Midland to Cushing, did you see any sort of impact to the competitive forces there? Or were you roughly flowing the volumes you thought you would on the Midland to Cushing route, given how basis differentials have moved around?

Those were actually in line with what we had expected. 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 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 as to whether that goes to Colorado City and then down to the Gulf Coast or whether that barrel goes all the way to Cushing. But the volumes on Basin were pretty much in line with what we expected.

Okay. And just going back to how you report the MVCs and deferred revenues. I understand that those numbers will not show up in EBITDA. But my understanding is they will show up at 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 has focused in on.

We've seen in some areas or some companies that we've monitored so far that had a little bit bigger issue than we have on a trailing basis where they have added in cash received and then backed out EBITDA recorded for makeup volumes that were really associated with cash receipt in the prior period. And, Faisel, we will probably 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 to $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 do it in 2016 sometime. And we'll make sure we clarify that on the next release as to how we handle that.

Makes sense.

Last question for me, the line 901 incident -- I want to make sure I understand where you are in that process, and when we could see 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 tell you where we are from a physical standpoint.

Clean up was effectively accomplished within almost 3 months, in 3.5 months of the release. So by middle of late August, we had basically concluded most of the cleanup 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've 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 those 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, make sense, I appreciate the time, guys. Thank you.

Thank you.

Ethan Bellamy, Baird.

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

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 -- and 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 these 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 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 will have the cash.

Okay that's helpful.

And 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 is okay? And is there reluctance to give you equity credit to 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, we raised enough to not only 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 the agency. So I don't think they are in a situation -- they acknowledge that it's I think better to have preferred on the balance sheet than it would be to have the proportion of debt and equity there. It's just a phenomenon in the way they treat it in the 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 clearest line of sight basically to finish the capital program for 2016 and 2017 without needing to rile the markets at all.

Okay that's helpful.

And then one last one. Are the non-core 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 those two things that offset somewhat?

We haven't provided information on the latter part of it. But to answer your first part, it 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.

The other element is that while we have -- I think we originally gave guidance and said we'd sell $200 million to $400 million. And we've increased that a little bit. We are 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 will be a net trade up if we can sell at X multiple and buy at 60% of X multiple, that's going to be a net add to the forecast that we've provided to you. But we have factored out the asset sales out of there. We haven't factored any of the new purchases in there.

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

That's helpful, thank you.

John Edwards, Credit Suisse.

Thanks, everybody.

Greg, just following up Ethan's last question, what's the projected timing right now of the asset sales in the guidance?

Mid-year, second quarter. You've got regulatory approvals and things that have to be done, but between here and the middle of the year.

Okay, and then similar, you are expecting that for the acquisitions you are contemplating?

Subject to regulatory stuff, yes.

Okay. And then just kind of going back to Faisel's question on competitive forces. You talked a little bit about volumes. If we are translating the impact of those forces -- call it from a revenue standpoint, even from rate standpoint -- how should we be thinking about that?

We've 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'd probably end up with more market share at the end of the day because I think we've got weaker competitors than Plains. Weaker from a standpoint of not only balance sheets, but weaker from the standpoint of lack of interconnected assets that allow us to be able to capture full cycle margins as opposed to discrete assets.

Okay, so in terms of pricing, how much 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 is going to be in supply and logistics, not in the Transportation segment.

Okay.

And as far as trying to quantify it. I think -- Al, what's our -- supply and logistics is $486 million? Against we had $560 million. So if you just do the spread, it's probably about $75 million against that year-to-year comparison, John.

We've given guidance in the past that we thought is $500 million to $550 million is the baseline. So if you used the $525 million, you'd straddle a range roughly of $40 million to $70 million. But again, that's built into our guidance.

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

Okay, so the numbers you are giving in the guidance -- that's the $1.13 -- you are basically baking in the competitive landscape into that guidance, right?

Bingo.

All right, thanks.

I guess the other thing, I'm kind of wondering from where you guys sit. How are you guys thinking about reconciling the fact that you are seeing these volumes that are declining, but the storage keeps building in the US; and you are seeing it go up. 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. 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 US 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 is 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 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 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.

Okay, great, that's helpful. That's all I have. Thank you.

Chris Sighinolfi, Jefferies.

Hello, Greg, good morning.

Good morning.

Just wanted to follow up on -- I appreciate you confirming Ethan's question about the cadence of your price expectations. Just curious, because there's 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 have forecasted as a base across the three segments?

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

And hopefully there are 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 storage assets improves quite a bit. 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 are saying on the aggregate guidance numbers you gave?

Correct.

Okay, and just to confirm the implied DCF that you guided in last night's release and on slide 10. That's prior to the distributions on the preferred, right?

Correct.

Okay. And then the final point of inquiry for me is note No. 9 to the 8-K you put out last night, which deals with the index equity compensation. It says within that, Greg, that you've made the assessment that at $290 million 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 Chenier on the January call about how we should, for all reasonable expectations, expect something flat at $280 million for the next couple years.

We have to look at our extended forecast when we do that. We also, I think, had already hit $290 million before the bottom fell out; so we left at the same. We didn't try to go back and recapture and record income because we would lower probabilities. We just left it there.

Understood, so you were there from a calculating the equity comp before everything, and then you just left it flat?

That's correct. That level has been in place for, I think, well over 12 months.

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

Becca Followill, US Capital Advisors.

Good morning. Thanks for extending the call.

I'm still confused on the Permian volumes on transportation. 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 barrels. Yet I don't think you are forecasting that Permian volumes in aggregate for the industry grow by that level. So I know there are new pipes coming on, but I assume this is a significant market share that you are taking from the industry?

Keep in mind sometimes if we have two tariff movements in there, Becca, you're going to count the same barrel twice. So we have tariff movement A to B; it's a separate tariff. Then if they move it from B to C, it's going to be another tariff volume. So you're going to have some double counting that 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, yes, it's a market share issue. But again, if we have 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 it 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.

That's all I have. Thank you.

And just so you know, Becca, if 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 go from the fourth quarter to the first quarter, it's not as much of a ramp if you go December to January as you might think.

Thank you.

Michael Blum, Wells Fargo.

Thanks.

Just one question. If Moody's were to -- as you said, Greg, god forbid, downgrade you -- and realizing that you'd still be investment grade, my question is simply are there any ramifications in terms of the cost of doing business? Whether that's the supply and logistics, counterparty posted letters of credit, the cost of your facility? Just trying to think through that scenario.

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.

Jeff Birnbaum, Wunderlich.

Good morning, everyone. 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 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 further segment that into perhaps -- 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 redevelop as we move through this very fluid 2016?

I think the best that 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 you our best shot at the worst-case at the 2%.

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

Okay, thanks.

And then a couple on the preferreds. Are you assuming you are going to pick those at this point, given how the guidance was laid out last night?

We've got it forecasted as cash paid.

You do? Thank you.

One last question, on the maintenance CapEx down slightly the second year in a row, what was driving that?

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

And a little bit of it is some of the assets we have sold had a higher maintenance capital.

I think that's the biggest component of it.

Understood, thank you.

Selman Akyol, Stifel.

Thank you, and I am appreciative of the additional time. Real quickly, you had talked in terms of refineries being able to request additional security if you needed 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. That's a very standard provision in virtually any purchase or sales contract in the crude oil business. So from time to time, we do do that.

Granted, you are 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, it just comes up on an as-needed basis? Okay. Thank you very much.

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 will take those two and then wrap this up.

Sunil Sibal, Seaport Global Securities.

Hello, good morning. And I appreciate all the color and you taking the time. So I have just one quick clarification on the supply and logistics. First of all, I presume that $440 million to $540 million number includes the $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?

The $15 million carryover is included in our 2016 guidance. I think I answered the first part of your question.

The second part, were you asking if there's a potential for any further compression in the $1.13 margin?

Yes, that and then any particular area which will have increased sensitivity to that margin where the basis differentials are quality differential wise?

First off, the $1.13 is the mathematical result of different variations. You are going to have higher and lower margins in different areas, Suni. So I think what we've tried to do -- and again, we try to be as forthright as possible -- we've tried to give our best guesstimate of what the impact is going to be on a per-unit basis as a result of that area-by-area buildup.

So we've given you what we think is out there in that regard, and suggested it's going to be below baseline for that. So there's not much more granularity we can provide without giving somebody a road map for how we compete in each area.

All right, that's very helpful. That's all I have. Thanks.

Noah Lerner, Hartz Capital.

Thank you.

I'll try to make this brief because you have given us a lot of time. A quick question. When you talk about the credit support, getting back to the 85% of the credit exposure and the market logistics as investment grade or LOC. Do those LOCs 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 multi-year comfort as you see it weaken. But if you had to go against a letter of credit, how much security does that really provide you?

Our LCs in the 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 50 days; 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 are giving zero credit to and you are selling and you're getting LCs, you have no unhedged exposure there -- no remaining exposure.

But 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 at $2 million open line and then give them $18 million LC. Realizing that every month it kind of refreshes because what rolls off gets renewed. So you 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 a month rolloff.

So all the counterparties to the MVC contractual support that's laid out on slide 8, that's above and beyond these people we're talking about here -- the producers for the market and logistics? Is that a correct statement?

Yes, there are two different things. You are talking about facilities and transportation. All these projects that you see on slide 8 are related to the tariff for the fee-based on facilities.

Okay, so how have you gone about monitoring? And what kind of credit risk is there to those counterparties? You had 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 commitment. So you basically put them in zero because you think they're on the ropes.

How do you go about taking all those contracts coming on board and all those counterparty risks into the guidance? Are both of those investment grade, or are there non-investment grade there as well?

Noah, I walked through that. Virtually all -- the large majority of our MVCs supporting our pipeline systems are investment grade. There are several that are non-investment grade refiners behind 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 a 15-year MVC type deal and get an LC to support them. So we have open credit for (inaudible).

Noah, if I can, remember the beauty of our system is it's an integrated interconnected system. So we've been at this for quite a long time. So there has been in the past, for example, we may have built a pipeline to a refiner. 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 refiner and they shut down, then we reverse that pipeline. And we moved the barrel they used together 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 Systems because we can always find a home for the crude because we are interconnected. I think you are 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 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?

Again, a couple 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 it might impact our collection against. Just because 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. Great. Thanks a lot.

Tom, I believe that's the last question. Why don't we go ahead and wrap up the call up, please.

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