Plains GP Holdings' (PAGP) CEO Greg Armstrong on Q4 2015 Results - Earnings Call Transcript

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Plains GP Holdings LP (NYSE:PAGP)

Q4 2015 Earnings Conference Call

February 9, 2016 11:00 AM ET

Executives

Ryan Smith - Director of Investor Relations

Greg Armstrong - Chairman and CEO

Harry Pefanis - President

Willie Chiang - Chief Operating Officer US

Al Swanson - Chief Financial Officer

Analysts

Brian Zarahn - Barclays

Jeremy Tonet - J.P. Morgan

Kristina Kazarian - Deutsche Bank

Faisel Khan - Citigroup

Ethan Bellamy - Baird

John Edwards - Credit Suisse

Chris Sighinolfi - Jefferies

Becca Followill - U.S. Capital Advisors

Michael Blum - Wells Fargo

Jeffrey Birnbaum - Wunderlich

Selman Akyol - Stifel

Sunil Sibal - Seaport Global

Noah Lerner - Hartz Capital

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the PAA and PAGP Fourth Q ‘15 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 given at that time. [Operator Instructions] As a reminder, this conference is being recorded.

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

Ryan Smith

Thanks, Tom. Good morning, and welcome to Plains All American Pipeline’s fourth quarter 2015 results conference call. The slide presentation for today’s call is available under the Investor Relations and News & 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 financial information tab of the Investor Relations 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 the 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, and CFO. In addition to these gentlemen, and myself we’ll 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.

Greg Armstrong

Thanks, Ryan. Good morning and welcome to everybody. Yesterday PAA reported fourth quarter and full year 2015 results. Slide 3 contains comparisons of PAAs performance metrics to the same quarter of last year and also 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 of 2015, both of which are slightly below our 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 GAAP. The first is the deferral margin on NGL volumes expected to be sold in the quarter and related inventory costing items.

The second is under deliveries of contracts with minimum volume commitments that essentially results in revenue deferral. These represented amounts we have either received or will receive for which the shippers had the right to make up volumes in the future. These amounts will be transferred to EBITDA [ph] when the makeup occurs or when they lose the ability to make up for the volume shortfall. Harry will provide additional information in his comments.

As per 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 amounting $0.24 per Class A share on an annualized basis, which is also 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 PAAs 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 20136 guidance.

Harry Pefanis

Thanks, Greg. During my portion of the call I’ll review our fourth quarter operating results compare 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 shortfalls related to volume deficiencies under minimum volume contracted exceeding the levels we forecasted.

For the quarter the total impact of the deficiencies was approximately $15 million, the deficiencies were all from credit worthy parties. However, Greg mentioned the revenue recognition of these deficiencies differed until the actual volumes are delivered or until the makeup period has expired.

Approximately $8 million of the shortfalls we’ve had because of 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 a third party connecting pipeline and then secondly, lower than expected volumes under our minimum volume commitment contract.

The balance of the volume metric shortfall was due to a combination of both longer than forecasted refinery turnarounds; second, certain receipts not meeting our pipeline quality specifications; third, short-term diversions of volumes around certain volume [ph] activities in the Permian Basin and then fourth, lower than anticipated gathered volumes. This was partially due to the in climate weather at the end of both November and December.

Adjusted segment profit of $0.62 per barrel is 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 mid-point 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 mid-point 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 mid-point 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 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 narrowed 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 unfeasibly warm weather in certain areas of the US and Canada, 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 timing issues previously mentioned.

We now move to Slide 6 to review the operational assumptions used to generate the 2016 guides 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 our 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 or due to forecasted increases in our Permian Basin area pipelines driven by completion of our Delaware Basin systems and the continued ramp up from 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 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 placed 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 $0.01higher than 2015.

For Supply & 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 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 capital program, Slide 8 recaps our major projects for 2016. The vast majority of which are underpinned by MVC’s mineral 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 will note the timing of the receiving the final permits for the Diamond pipelines 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 joined 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 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 and capital to be in the $190 million to $210 million range for 2016.

So, with that, I’ll turn the call over to Al.

Al Swanson

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 9. 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 in return to within our targeted range as we realize the benefit of new projects coming online in 2016 and ‘17 coupled with an industry recovery.

In January, we completed $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 characterize 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 pro-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 onto 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 forecast and others are modifying previously disclosed plans which will have an impact on PA’s performance in the coming year.

As an example since mid-December when we generated our 2016 forecast, total rig counts 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 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 we’re in 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 forecasted to be approximately 87% for 2016, based on midpoint guidance.

Our2016 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 the tighter differentials.

With respect to our NBC contracts in a few areas we are forecasting volumes to be below contracted level. In the remainder of the areas we forecast the volumes to be in line with contracted level. Throughout the year, we will adjust our forecast to reflect variances between forecasted volumes and the volumes will be paid cash for under the NBC arrangement. 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 & 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 pressure will continue to negatively impact least gathering margins and tight basis differentials in the current environment.

The right half of the Slide 10 highlights to aspects of our 2016 guidance. The first is the build in our fee based transportation facility 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 demands 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 counterparty credit exposure and performances. 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 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. The NGL sales activity is best characterized by the 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 exposures for our fee based Facilities and transportation segments, is much smaller than our supply and logistics segments 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 within 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 customer’s inventory, which provides a form of credit protection in the event of non-payment.

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 within their investment grade entity. Additionally, shippers typically are required to carry line fill on the pipelines which as with the facility segments provide the form of credit protections in the event of non-payments.

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 other 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 makeup 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 are with investment grade entities a number of them are with noninvestment grade refiners associated with the manhole 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 under BridgeTex pipeline that represents approximately 10% of that pipelines capacity, where we concur with the operator’s expectation that the counterparty will not fulfill our contractual commitments and will ultimately default. We have not included any revenue from this contract in 2016 guidance nor was it included in the fourth quarter deferred revenue amount 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 relationships 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, redemption wherever 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 credit rating purposes the preferred would receive 50% equity credit from both rating agencies. The statement was supported by written confirmation we had received from both of the rating agencies. Moody’s had since informed us that for investment grade MLP’s, preferred issuance is that contain a cumulative dividend feature will be treated as if the distribution payment 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 rational 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 preferred should be considered a 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 will turn call back over to Greg.

Greg Armstrong

Thanks, Al. I want to close with a few comments about PAA’s overall positioning 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 industry in MLP with leading positions of substantial all US and Canadian resource place and market interchanges and has the most interconnected crude oil transportation terminal network in North America.

Moreover, as a result of the recent one and done activity financing PAA has the balance sheet strength and liquidity to manage to 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 to somewhat upside down. By that, I mean 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 make projected crude oil demand with oil at $30 per barrel and that the world will need US 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 US and Canada 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 in 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 the 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 was fee, certainly an amount was validated. Moreover, we believe industry conditions over the next several months have the potential to be more challenging and stressful for the industry than in 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 investor conditions. Nonetheless, PAA near-term operating results could well be impacted by the actions of others. During today’s call, we provide a quarterly and annual guidance in the formats somewhere to that provided by PAA over the last 15 years. However, more so than in the past years PAA’s near-term performance will be influenced by uncontrollable and unknown factors such as variations and producer activity levels and competitive reactions from certain of our public and private Midstream peers.

At PAA we will continue to compare our performance against NBA and be accountable for the guidance we provide each quarter. The given current commodity price levels, produced or 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 in sustain basis reduces US producer’s annual cash flow by approximately $32 billion which suggests producers will need to reduce their capital programs significant 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 way we believe the supply access will be worked off to 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 our 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 with investors evaluating their 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 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 still take 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 has proven through performance during the period of a number of cycles. Second, about 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 of capital commitments beyond 2017.

We also have the ability to maintain our distribution while we work our way back to our target distribution coverage of 105% to 110% and where we can then focus on resuming distribution growth. Next, we have visibility for incremental cash flow contributions in 2016 and ‘17 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, although we have called recovery lift off and that investing in either security [ph] they will generate attractive total returns, which an investor is getting paid handsomely while they’re away. 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 25th 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 update 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.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is from the line of Brian Zarahn with Barclays.

Brian Zarahn

Good morning.

Greg Armstrong

Good morning, Brian.

Brian Zarahn

On your 2016 guidance, the transportation segment obviously is the key growth driver and 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 stellar basin projects?

Greg Armstrong

We can. I think as far our assumptions, we have, as we mentioned, we now 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 ‘16 versus the average for ‘15. On a peak to trough basis, if you go to the highest level in ‘15 going down to the lowest level in ‘16, 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, here in the [Indiscernible] 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 been fewer rigs being put to work, but they're having better success with A12, so technology is kind of overcoming rig count. So, we've got a 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 forecasted increased, a fair portion of those are associated with MVCs that have been 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 going on to areas where we've kind of built out in Delaware and the Midland basin. Is that fair, Harry?

Harry Pefanis

Yeah, so most of the growth really comes from the Delaware Basin. 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 is 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.

Brian Zarahn

And I appreciate the overview of counterparty risk on bridge tax on the shipper that's not currently shipping. Is that a private or public company?

Greg Armstrong

We don't give out the information on - we’re not required or allowed by regulation, Brian, to give any information on our customers there, with that volume hasn’t been in any of our forecast.

Brian Zarahn

I understood. And then on the remaining 70% of contracted capacity on bridge tax, that's - was there any change on your outlook for those shippers?

Greg Armstrong

No.

Brian Zarahn

Okay. And then on - turning to asset sales are certainly making progress, upsizing a bit, how should we think about after-tax proceeds of the $400 to $500 million.

Greg Armstrong

After tax and before tax will be the - it’s on the US side.

Brian Zarahn

Okay. And then the last one from 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?

Greg Armstrong

No change.

Brian Zarahn

Thank you.

Operator

Our next question is from the line of Jeremy Tonet with J.P. Morgan. Please go ahead.

Jeremy Tonet

Good morning.

Greg Armstrong

Good morning, Jeremy.

Jeremy Tonet

I'm just curious as far as the guidance outlook for ‘16 and I appreciate that's very much a fluid situation right now. I think the market is just looking for whatever color that can be provided, maybe some activity wise that if the current environment persists through year in ‘16, is there any sense you can give us for what that would do to the guidance employees or anyways to think about that?

Greg Armstrong

I mean it's an excellent question. A couple of things kind of running counter to each other, so clearly to the extents that we have volumes that are forecast under MVCs that are produced, Jeremy, will still get the cash, but it may shift the recognition of that from EBITDA to deferred revenue. So, from a unit holders or debt holder’s perspective, the 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 reported. It’s not going to affect the way we collected.

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 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, if volumes stay in this range right here, I don’t know, 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 face here because, again, we've got - the volume is 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.

Jeremy Tonet

Great. Thanks for that. And if I could just turn to a couple of 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 fine growth in there and also the rail volume growth in the supply and logistics, wondering if you could just expand on that a bit.

Harry Pefanis

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 of Cactus.

Greg Armstrong

We actually have - Jeremy, I think we've got Cactus rolling over from a peak of about - 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 a rolling down 250,000 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 Cactus into our Eagle Ford JV system.

Al Swanson

And then the second point I want to make is we completed an expansion of that system and have committed volume on it in late August or early September. So you're getting the full year impact of that next year versus only partial of your last year. So, if you look fourth quarter or the first quarter, this flat probably down just a touch on Eagle Ford volumes.

Jeremy Tonet

Okay, great. And then the rail for the supply and logistics side, I think that was going up a bit 1Q ‘16 to full year ‘16?

Greg Armstrong

The full year ramps up. Yeah, and it’s not all supply and logistics related. A lot of it is 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.

Jeremy Tonet

Okay, great. And then just one last one for me if I could, in the past, I think you guys have discussed the potential to collapse the structure. I was just wondering if you could provide us for any updated thought there and when that might make - when and if that could make sense for you?

Greg Armstrong

Yeah, to be clear, what we've 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've indicated probably middle of the year before we completed that. Candidly, Jeremy, trying to analyze anything today is like trying to nail jello to a tree. The valuations and the expectations are moving around significantly. So, back to my jello to a tree, I can see it and I can touch it, but trying to control it right now when the valuation is moving around, it 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. In fact, quite candidly we've been so focused on addressing the capital side of it. We're just now turning our attention to that.

Jeremy Tonet

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

Operator

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

Kristina Kazarian

Hi, guys.

Greg Armstrong

Good morning.

Kristina Kazarian

I know you guys touched on this a couple of times today, so just maybe if you could help me a bit more. When I'm thinking about that MVC deficiencies, how do I think about how much that MVC deficiency payments are deferral on payments makes up of my calendar year ‘16 adjusted EBITDA assumptions? Just I'm just trying to understand overall magnitude here.

Greg Armstrong

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 in EBITDA.

Kristina Kazarian

Okay. So, but then if I use that on - to help me understand generally timeframe to companies, are they delivering the volume or when the makeup 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?

Greg Armstrong

So just to be clear, I mean, it’s a number. There’s probably 50 different types of the 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 on quarterly, so it really just varies when you - we have to - 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, 75 millions of them…

Al Swanson

1% to 2% of our…

Greg Armstrong

Yeah, so as Al said, maybe if you're worried about how much might be under delivery so at the end of year, we have the cash, but not the EBITDA that’s in deferred revenue. We call it order of magnitude 1 to 2%.

Kristina Kazarian

Yeah, that's really, really helpful. And then…

Greg Armstrong

I would just point out that in this type of environment what we figured out is we 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.

Kristina Kazarian

Yeah. 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 maybe non hygienic 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 respect could come in the next 12 months, but isn't quite here yet if we stay in the current commodity environment?

Greg Armstrong

So again, we’re not given away any specifics on a customer by customer basis. What we looked at is, we try to figure out who is or could be in financial distress that makes up a small portion of that, very small portion of non-investment grade customers that we have on the producer side and that 2% by the definition of the word worst case, assume pretty much that if they have a challenge and they went into bankruptcy and we didn't get those volumes that would be the 2%, to be very, very clear, you used 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 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're connected to their facilities and you're the only gathering system out of the area, there's not a lot of other ways for them to get it around, except for more expensive methods or required a lot of capital. So we use 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.

Kristina Kazarian

Yes. Again, really help on that number. So, my last question for you guys is when I think about the asset sales that we've talked about and you guys have been very successful on it executing two that have been publicly available for us to figure out so far. They started 2 to 4, now it’s 4 to 5. Is that kind of what you're thinking about for ‘16 on an end rate? Or is there the potential for this number to come up again in ‘16 or maybe do we reassess it back in ‘17 in some point?

Greg Armstrong

Well, we always reassess. Okay. So, but I think that's one of the magnitude of what we expect to have completed in 2016.

Kristina Kazarian

Perfect. Thanks, guys. I appreciate it.

Greg Armstrong

Thank you.

Operator

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

Faisel Khan

Yeah, good morning.

Greg Armstrong

Good morning.

Faisel Khan

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 cost, as [Indiscernible] said where there are some refining downtime other things, I think the concern that the market might have is that that wheels are coming off the track and volumes are going down faster than what you guys to forecast. I just want to understand sort of what caused the mess and the other part of it 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, I could see if one of the pipelines was very volume than the others. So we'll have that granularity, so I understand why you remove that from the reporting results?

Greg Armstrong

Well, from our reporting standpoint, we thought it was better to disclose that by area. It’s 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 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. What we found is that one might be up, the other might be off. So, we sort of aggregate it in sort of the producing areas. From a volume standpoint, I think I sort of hit on it all of the high level issues.

Faisel Khan

I just want to understand that the volume issue in terms of guidance versus where you ended up, is that - is it - it is all weather and downtime or was there some underlying production decline that caused the numbers to be lower than what you thought?

Greg Armstrong

Faisel, there really wasn’t much in the way of unexpected declines that happened we did have and we acknowledged you on the November report, 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 magnitude we probably by the end of the quarter, fourth quarter had captured back as much 60,000 or 70,000 barrels a day.

When you say volumes are going down, if you actually look quarter-to-quarter is going up, what happens is they are going up at lesser rate than we may have thought six or seven months ago because of these issues, we are raising in general the decrease rate of growth at a particular area or the increased competition and so it was not areas really fallen 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 though West Texas right now you are going to see what is happening out there. There is probably two or three hundred trucks from third party haulers that are sitting there unused right now. Part of that is because we built pipelines and parts of those Plains [ph] has become more aggrieves of capturing of those volumes and making sure that we use our entire value chain to optimize the margins.

Harry Pefanis

Hey Faisel, I can give you little more details we probably had that 20,000 - 25,000 barrels a day, the volumes are there, there were just quality issues, so you can’t do on the pipe. And those are being remedy by producers because to their economic advantage to have it on pipe versus on trucks. We have some refinery turnarounds that probably made up another 30,000 - 35,000 barrels a day. So that’s not you know, refining turnarounds occur but these happen to an extent longer than we had anticipated in our guidance. So this is the volumes there we probably had pretty 20,000 - 25,000 barrels a day related to MVC’s on one pipe, so that will gives you little better.

Faisel Khan

Yeah, now it does and just on the volume from the Midland and Cushing. Did you see any sort impact sort of the competitive force there, where you roughly flowing to volumes, you thought you would on the Midland and Cushing route, I mean given how basis differential sort of moved around.

Greg Armstrong

Those were actually in-line with what we had expected, but when you look at basin pipeline, it is kind of unique pipeline. Our EBITDA is pretty close the same whether that volume goes to Cushing or if it goes to Wichita Falls, it goes connecting carriers or if it goes to Colorado city goes connecting carriers. So the tariffs is set up on a sliding scale that we’re almost indifferent as to whether the goes to Colorado city and then down to Gulf Coast or was that barrel goes all way to Cushing. So, but the volumes on basin were at pretty much the amount what we expected.

Faisel Khan

Okay and just going back to the - how you report the MPC’s in deferred revenues, so I understand that those numbers will not show up in EBITDA but my assuming is that they will show up in the DCF is that correct way of looking at.

Greg Armstrong

We haven’t modified our DCF to include that cash yet. We are trying to study how to do it, it is just now becoming an issue that I think the industry focused in on and we seen being in some areas or some companies that we’ve monitored so far that have had little bit bigger issue than we have on trailing basis, where they have added in cash received and then backed out EBITDA recorded for the make-up volumes that were really associated with cash received in the prior periods and Faisel, we 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 are going to try to make sure because we think as a general rule it is going to be a bigger issue for the industry as a whole. We have studied balance sheets of others and we have seen a couple of companies that may have as much as $400 million or $500 million cumulative deferred revenues on their balance sheet. That’s probably a big enough sized where you need to make an adjustments so far at $15 million, it hasn’t become big enough yet, but we are probably going to do it in ‘16 sometimes. And we will make sure we clarify that on our next release as to how we handle that.

Faisel Khan

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

Greg Armstrong

I’m not so sure, I would rather predict regulatory agencies or crude oil prices, neither one of them are very precise. Let me just stay where we are from the fiscal standpoint, cleanup was effectively accomplished within almost three months, three and half months of the release. By middle of late August we had basically concluded most of the cleanup activities or substantially - we were in monitoring mode, we are very close to being through the monitoring mode now because we’ve had long time, so from that standpoint the costs are reflected, we made the accrual, we have accrued that up here recently with just a matter of amount. As far as the regulatory process we are still going through a lot of details - there were - effectively there has been an root cause analysis, but still in draft form and until we get that totally resolved we haven’t come out with a forecast publically as to when that might be put back in the service order of magnitude that’s probably in the $40 million year flow impact.

Harry Pefanis

$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 it is - that’s sort of where we are right now, when we get close to finalization then we will provide a restart plan.

Faisel Khan

Okay, make sense. I appreciate the time guys, thank you.

Harry Pefanis

Thank you

Operator

Next question is from the line of Ethan Bellamy with Baird. Please go ahead.

Ethan Bellamy

Hey guys, good morning. Greg what’s the crude oil price embedded in your guidance for ‘16.

Greg Armstrong

So and again we generate this in the middle of December, we had $35 for the first quarter; $45 for the second; 55 I think in the third and 16 the fourth, so it averaged about $47.50. Currently right now, obviously we are 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 is what was embedded in that and we try to true up Ethan, budgets against that for the purposes of drilling activities and rig counts in different areas and as I mentioned earlier I think we had areas like the Mid-Cont and Eagle Ford and the Bakken trending down volume wise and we had relatively flat, very slightly up in the Permian and DJ. What you can - the take away from this call is, if obviously if the rig count is falling faster and it’s not offset by efficiencies, we are probably going to see the by the time we get to the middle of the year volumes, rowing over more than what we forecasted. So we may have some shift from EBITDA to deferred revenues on the NBC contracts, but again we will have the cash.

Ethan Bellamy

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 is okay. And is there reluctance to give you equity credit specifically force your hand to raise more equity at some point or sooner than you otherwise would have.

Greg Armstrong

No, we are still one and done and as a practical matter I mean we raised enough not only disease [ph] our obligations for ‘16, but almost all of ‘17 and we have no meaningful debt maturities. I think we have 175 million in August of ‘16 and 400 million in January and that’s it. And if you look at our liquidity positions, whether we carry as debt on senior notes or whether we carry that as debt on our existing credit facility really makes no difference for the agency. So I don’t think there is a situation they acknowledge - I think it is better to have preferred on the balance sheet that it would be to have the proportionate debt and equity. There is just a phenomenon on the way that created in the writings process. We are all on the negative outlook at Moody’s and Baa2 so you if God forbid they should do the wrong thing and downgrade us, we are still investment grade both agencies. So we really don’t have or had to do anything that would be illogical and we have every clear sideline aside basically to finish the capital program for ‘16 and ‘17 without any derail on the markets of our.

Ethan Bellamy

Okay, that’s helpful and one last one. Are the non-core asset sales baked into the guidance and if you sell 500 million assets and complete 1.5 billion in capital projects. What is the net gain to the cash flow going to be from those two things that offset somewhat?

Greg Armstrong

We haven’t provided information on the latter part of it, but to answer your first part, should give you comfort, it is built-in to our guidance. If we complete the 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 that while we have - I think we originally gave guidance assume itself [ph] 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, what we are going to try to sell it one multiple and buy another multiple in terms of what we realize, realizing that the buyers that buy from us, we intend to enhance it with synergies and so it will be a net trade up, if we can buy it at X multiple and sell it X multiple and buy 60% of X multiple, that is going to be a net add to the forecast that we provided to you. But we have factored out that asset sales out there, we haven’t factored any of the new purchases in there.

Harry Pefanis

Ethan [ph] you’ll see that people who buy the assets from us have synergies as well. So that’s what sort to makes the multiples work.

Ethan Bellamy

That’s helpful, thank you.

Operator

Next question is from line of John Edwards with Credit Suisse. Please go ahead.

John Edwards

Yeah, thanks everybody. Greg just following up Ethan’s last question, what is the project timing right now of the asset sales in the guidance?

Al Swanson

Between now and midyear.

Greg Armstrong

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

John Edwards

Okay, then similar on you are expecting that for the acquisitions you’re contemplating.

Al Swanson

Subject to regulatory stuff, yeah.

John Edwards

Okay and then just kind of going back to Faisel’s question on competitive forces. Just you talk a little bit just about volumes, if we’re translating the impact of those forces from call it from a revenue standpoint, how should we be - I mean even from a rate standpoint, how should we be thinking about that?

Greg Armstrong

We try to factor that into our guidance, but we were it is fair to say widely criticized for coming out in August of last year and say we think this is going to be much more competitive when we lowered our guidance because of that. We factored that we would whether we got precisely right of not, we will find out at the end of the year but I think we are being as forthright as 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 and I think what happens is we probably ended more market share at the end of day because I think we have got weaker competitors and plans, weaker from a standpoint of not only balance sheets, but weaker from a standpoint of the lack of interconnected assets that allow us to be able to capture full stock of margins as opposed to discreet assets.

John Edwards

Okay, so I mean in terms of pricing I mean how much - kind of percentagewise can you talk about how much it’s impacting and then you are presuming already baked into your guidance any kind of contract renewals and such if you could comment on that, will be helpful too.

Greg Armstrong

The margin pressure is going to be on the supply and logistics, not in the transportation segment.

John Edwards

Okay.

Greg Armstrong

And then as far as trying to quantify to me, I think with our supply and logistics 486 - against we had 560, so I mean if you just to the spread probably about 75 million against debt year-to-year comparison John. And then we have given guidance in the past we thought it is 500 to 550 is the baseline. So if we used the 525 you startle a range roughly of about 40 million to 70 million, but that is built into our guidance.

Greg Armstrong

I guess our storage business there is no really re-contracting risk.

John Edwards

Okay and so the numbers you’re giving in the guidance that $1.13, you’re basically baking in the competitive landscape on as backed into those estimates correct of the guidance right?

Greg Armstrong

Bingo

John Edwards

Okay, great. Alright 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 your reconciling the fact that you’re seeing these volumes that are declining but the storage keeps - you’re building in the US and you are 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 would help your own thinking in that regard.

Greg Armstrong

John, the biggest driver to inventories is imports and if you will notice the imports for the first four weeks of this year have been upwards of 8 million barrels a day. We can talk about reasons why that is, but effectively we built in the US almost 100 million of inventory by the end of 2015 and if you go back to our Analyst Day, we gave of forecast for that and we were asked that we were I much closer than many I think we had it on our asset [ph] case being about 83 million barrels at the end of ‘15 relative to ‘14 and then 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 got it trending up until turnarounds are completed by the end of April, first part - excuse me end of - 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 at the end of ‘16, we could be wrong and if turns out that the price doesn’t hit our target until the first quarter of ‘17, we’re not going to do a lot of apologizing because that is pretty close you know just about any measures so.

John Edwards

Okay, great. That’s helpful, that’s all I have, thanks.

Operator

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

Chris Sighinolfi

Hey Greg, good morning

Greg Armstrong

Good morning.

Chris Sighinolfi

Just one to follow up on - I appreciate you confirming Ethan’s question about the cadence of your price expectations, just curious there is some really in 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 the basis across the three segments?

Greg Armstrong

Yeah, I’ll probably focused on the materially weaker, with stronger there are so many variables go into how it got there et cetera, but I think order magnitude what we are seeing is 3% to 4% on the downside. And because there– and hopefully there is mitigating factors that might even make less because again depend on what triggers it to stay low, if we continue to say 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 is not a 10% adjustment downward if it stays in this range, it’s less than 5%, probably close to the 3%.

Chris Sighinolfi

You are saying on the aggregate guidance number you gave.

Greg Armstrong

Correct.

Chris Sighinolfi

Yeah, okay. Okay and then just to confirm the implied DCF that you guys guided in last night’s release on Slide 10 that’s prior to the distributions on the preferred right?

Greg Armstrong

Correct.

Al Swanson

Correct.

Chris Sighinolfi

Okay and then the final point of just from me is, note number nine to the AK [ph] you guys put last night which just deals with the equity index, index equity compensation. It says within that Greg, that you know you have made the assessments that are 290 annualized distributions is probable and the reasonable in the foreseeable future. So I was just curious how to interpret that relative to the dialogue you had with [indiscernible] on the January call that how we should for all reasonable expectations expect something flat at 280 for the next couple of years.

Greg Armstrong

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

Chris Sighinolfi

Understood, understood, okay. So you were there from a calculating the equity comps before everything and then you just left it blank.

Greg Armstrong

Correct

Al Swanson

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

Chris Sighinolfi

Okay, thank you very much for confirming that, thanks guys.

Operator

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

Becca Followill

Good morning guys and thanks for extending the call. Just too confused on the Permian volumes on transportation, so it looks like on your guidance, average ‘15 versus average ‘16 is up about 500,000 barrels a day and from work Q4, it’s up about 400,000, yet. I don’t think you guys are of forecasting Permian volumes in aggregate for the industry grow by that level, so I know there’s new pipes coming on, but I assume this is significant market share that you’re taking from the industry.

Greg Armstrong

Well, keep in your mind, sometimes if we had two-tiered moments in the backend you’re count saying barrel twice, right. So we have tariff movement A to B, it’s a separate tariff and then if they say, move it from B to C; that’s going to be another tariff volume. So you’re going to have some double counting and it is always happens depending on where the volumes move and we have MVC step ups throughout the year, so to the extent that volumes don’t increase to that yet so the market share issue. But again if we got the contracts behind it I feel pretty good forecast and that again if it turns out that they don’t ship on that let’s choose to go another route I’m still going to get cash.

Becca Followill

So it is kind of the connectivity that you have increased that is kind of exacerbating the increase. When you get it flow on a separate pipeline in addition to the new pipeline that you just built for the connectivity.

Greg Armstrong

We are all about value chain, if I can collect three tiers for one barrel that is outstanding.

Becca Followill

Great, that’s all I have, thank you guys.

Al Swanson

And just [indiscernible], Becca, if you look at the end of the fourth quarter the volumes are higher than they were in the fourth quarter as well, so even in the fourth quarter the first quarter is not as much a ramp, if you go December to January it might be.

Becca Followill

Thank you.

Operator

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

Michael Blum

Thanks just one question, if Moody’s were to as you said Greg, downgrade you guys and assume it’s still be the investment grade and my question is simply are there any ramifications in terms of just the cost of doing business whether that’s the supply and logistics, counterparty post letters of credit, that cost of your facility just trying to think through that scenario.

Greg Armstrong

Yeah, the big - yeah, I said [indiscernible] if they do the wrong thing and downgrade us, I think is the way I said, but the last thing they take the action now it’s not going to have a material impact on our business.

Michael Blum

Great thank you.

Operator

Our next question is from the line of Jeffrey Birnbaum with Wunderlich. Please go ahead.

Jeffrey Birnbaum

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 of follow-up. Greg, I just want 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 the things are so fluid is there a way sort of further segment that into perhaps and maybe this could be something going forward were you tier that based on investment grade ratings call it upper medium to lower medium so that investors can get a bit of better sense of how things can be develop as we move through this very fluid 2016.

Greg Armstrong

I think the best thing we do is keep the appraisals go through there, we don’t –again we went to our worst-case scenario, we tried to make that assessment as to who we thought was investment grade today if somebody might not be investment grade that then might not honor their contract and we give our best shot at the worst-case at the 2%.

Al Swanson

And Jeff just to be clear most of the focus that we believe and most of the questions we’ve gotten have been around the producers, that 2% was very rare estimate based on noninvestment grade producer shippers.

Jeffrey Birnbaum

Okay, thanks and then a couple just on the - on the preferred, are you assuming you’re going to pick those at this point just kind of given the how the gallons is laid out last night.

Al Swanson

We got a forecast is cash paid.

Jeffrey Birnbaum

Did you, okay thank you and then one last question on the maintenance CapEx, down flow second year in a row, I just guess what was driving it?

Greg Armstrong

Pretty much as more schedules and not needing to repeat repairs and little bit of that is some of the assets that we sold where little bit at a higher maintenance capital so some of that - I guess that is the biggest component of it.

Jeffrey Birnbaum

Understood, thank guys.

Operator

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

Selman Akyol

Thank you and I am appreciative with the additional time. Real quickly, you guys talked about in terms of refineries being able to request additional securities if needed high have you requested that from anybody or do you have any other parties out there you are seeking additional security on.

Greg Armstrong

From time to time we do that is and that is a very standard provision and virtually any purchase or sale contract include oil business. And so from time to time we do that and now you’re extending credit for 60 days so it is not a frequent thing. You normally know before you extended it, should you be worried or not as for it, but occasionally you do implement that.

Selman Akyol

All right, so in this environment it is not like earnings changer or what you are looking at it just comes up on as needed basis, all right thanks very much.

Greg Armstrong

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

Al Swanson

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

Operator

Okay, next question is from the line of Sunil Sibal with Seaport Global. Please go ahead.

Sunil Sibal

Hi, good morning guys and I appreciate all the color and you guys taking the time. I just one quick clarification on the supply and logistics, first of all I presume that 440 o 540 million number includes the 15 million carryover from fourth quarter ‘15 and then now that Permian is pretty well plumbed, any particular region which will can the impact your unit margins of $1.13 in that segment.

Greg Armstrong

So the $15 million carryover is included in our 2016 guidance, I think that answer the first part of your question and then the second part where you’re asking if there is potential for any further compression in the $1.13 margin?

Sunil Sibal

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

Greg Armstrong

First of the $1.13 is the mathematical result different variation you’re going to have higher and lower margins in different areas Sunil so, I think we what we’ve tried to do and again we’ve tried to be forthright and we try to give our best estimate of what that impact is going to be on a per unit basis in that as a result of area by area buildup. So we’ve given what we think is out there in that regard and suggest that it’s going to be below baseline for that. So there is not much more granularity we can provide with that given somebody a roadmap of how we can compete in each area.

Sunil Sibal

Alright guys, this is very helpful. That’s all I had, thanks.

Operator

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

Noah Lerner

Thank you. I’ll try to make this brief because you guys have given us a lot of time. Just a quick question when you’re talking about the credit support when you are getting back to the 85% of the credit exposure in the Mark logistics investment-grade or LOC do those LOC’s cover 100% of value the contract 12 months of the values of the contract. I’m just trying to get the sense you know investment-grade company you can have a multi-year comfort, as you see we can both - if you had to go against the line of credit, letter of credit rather. How much securities that will really provide you?

A - Al Swanson

Our LCs and crude oil sales and this is I think the universal across - not only us, but across the industry are typically nervous that for 60 days period. Your max credit exposure is generally is 50 days, you settle on 20th of the month following. You don’t really re-extend, so you don’t - you don’t have term deals for a year where you will be a have the ability to re-ask before you ever delivered that volume. So these are generally thirty-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.

Greg Armstrong

But you may just picking up humane double somewhere you got 10 million a month exposure so you have a the 20 million LC or you may say I’m gone I extend on the $2 million dollar open line and get and 18 million LC, realizing that every month it kind of refreshes because what roles off gets removed. So you’ll have a - you may have that LC in place for one or two years, but as Al pointed that is only for 60 days in terms of life exploration and they renew it each time you have a month or below

Noah Lerner

So all the counterparties to the MVC contractual support that laid out on Slide 8, that is above and beyond these people were talking about sure the producers are were the market and logistics is that correct statement.

Greg Armstrong

Yes, that - yeah, there are two different things. So you think about facilities and transportation is, what is all these projects that you see on Slide 8 are related to the tariff of the fee-based on facilities.

Noah Lerner

Okay, so how have you gone about I guess monitoring or what kind of credit risk is there to those counterparties not being able to - you had one now that you’ve now given zero credit to and you’ve got in, so it’s not going to be able to move up to their minimum volume commitments that you - so you basically put them zero because you think they are on the ropes. How do you go about taking this - all those contracts coming on board and all those counterparty risks into the guidance? Are most of those guys investment grade or are there non-investment grade guys there as well?

Al Swanson

Yeah, I’ll walk through that. Virtually all our - the large majority of our MVCs supporting our pipeline systems are investment grades. There are several that are non-investment grade refiners behind kind of demand pool projects and we’ve got several that are non-investment grade producers, i.e., supply pushed ones. And we quantify 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 getting out fee to support them, so we’ve opened credit for the investment [ph].

Greg Armstrong

Yeah and - no, if I can, I mean just remember, the beauty of our system is it’s an integrated, interconnected system. So we’ve been in practice for quite a long time, so there’s been in the past, for example, we may have built a pipeline to a refiner, okay and so we would have to obviously monitor the heck of the credit [indiscernible] to 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 move the barrels they used together locally, that they rented to the refinery now have had 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 like you were being tougher on somebody that had a one trick [indiscernible] somebody that had his integrated system with a lot of crows and a lot of bonnies [ph].

Noah Lerner

Okay and then one last one, moving 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 have been able to go out into the marketplace and replace that customer deals [ph] to wait for them to declare back and see them go to the whole bankruptcy process, can you try to re-contract them now?

Greg Armstrong

Yeah, so again a couple of things and I’m going to go back. I’ll just comment, we don’t get into specifics on particular customers, but keep in mind, number one, that was an acquired contract. When we brought 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 into 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 might impact our collection I guess. Because just because we don’t record it in the future for forecast doesn’t mean we don’t pursue it from a contractual nature to the course.

Noah Lerner

Got you. Okay, great. Thanks a lot.

Greg Armstrong

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

Operator

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