Plains GP Holdings LP (PAGP) 2014 Q4 法說會逐字稿

Welcome to the Plains All American Pipeline fourth-quarter and full-year results conference call.

(Operator Instructions)

As a reminder, this conference is being recorded.

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

Thanks, Gail. Good morning, and welcome to Plains All American Pipeline's fourth-quarter and full-year 2014 results conference call. The slide presentation for today's call is available under the Events and Presentations tab of the Investor Relations section of our website at www.plainsallamerican.com.

In addition to reviewing recent results, we will provide forward-looking comments on PAA's outlook for the future. In order to avail ourselves of Safe Harbor precepts that encourage companies to provide this type of information, we direct you to the risks and warnings included in our latest filings with the Securities and Exchange Commission.

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 Guidance and Non-GAAP Reconciliations tab of the Investor Relations section of our website. There, you will also find a table of selected items that impact the comparability of PAA's financial information between periods.

Today's presentation will also include selected financial information of Plains GP Holdings, or PAGP. As the control entity of PAA, PAGP consolidates the results of PAA and PAA's general partner into its financial statements. Accordingly, we do not intend to cover PAGP's GAAP results. Instead, we have included a schedule in the appendix to the slide presentation for today's call that reconciles PAGP's distributions received from PAA's general partner with the distributions paid to PAGP shareholders, as well as the condensed consolidated balance sheet.

Today's call will be chaired by Greg Armstrong, Chairman and CEO. Also participating in the call are Harry Pefanis, President and COO, and Al Swanson, Executive Vice President and CFO. In addition to these gentlemen and myself, we have several other members of our management team present and available for our question-and-answer session.

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

Thanks, Ryan. Good morning, and welcome to all. Anticipating that there is more interest in our comments regarding the future than this past quarter's performance, I intend to keep my opening remarks on 2014 brief, and focus mostly on 2015.

PAA reported fourth-quarter and full-year 2014 results near the upper end of the guidance range furnished on November 5, 2014. Adjusted EBITDA for the fourth-quarter and full-year 2014 was $594 million and $2.2 billion, respectively.

Slide 3 contains comparisons for a variety of metrics to our performance in the same quarter of last year versus our fourth-quarter 2014 guidance; and slide 4 highlights that this is the 52nd consecutive quarter that PAA has delivered results in line with, or above, guidance. Given the events occurring in the crude oil market after our last earnings call, we are pleased with how PAA finished out the final quarter of 2014.

As noted on slide 5, we are also pleased to report that PAA accomplished each of its four goals for 2014, and PAGP exceeded its targeted distribution growth for the year as well. For this quarter, PAA declared a distribution of $0.675 per common unit, or $2.70 per unit on an annualized basis, which will be paid next week. This distribution represents an approximate 10% increase over PAA's distribution paid in the same quarter last year, and a 2.3% increase over PAA's distribution paid last quarter.

Distribution coverage for the quarter on a stand-alone basis was 111%, and was also 111% for the year. PAA has now increased its distribution in 41 out of the past 43 quarters, and consecutively in each of the last 22 quarters. Additionally, PAGP's quarterly distribution of $0.203 per share represents a 27% increase over the non-pro-rated quarterly distribution paid for the same quarter of last year, and a 6% increase over the distribution paid just last quarter.

Turning to 2015, I want to provide some color on PAA's 2015 guidance that we furnished yesterday, and the context for the changes from the preliminary guidance we furnished on November 5, 2014. In our third-quarter earnings call in early November, we provided preliminary guidance range for 2015 adjusted EBITDA of $2.35 billion to $2.5 billion, with a midpoint of $2.43 billion. Prior to the call, we announced an acquisition that, at effective full utilization, we estimated would raise our run-rate adjusted EBITDA by approximately $100 million per year, with a ramp up in 2015 that would result in incremental adjusted EBITDA of around $90 million, and bring the midpoint of our acquisition-adjusted guidance to just over $2.5 billion.

As illustrated by slide 6, our business model and asset base have been purposely structured to generate solid results in almost any commodity price environment, and have proven their resiliency over the last 15 years in a variety of markets. While we have minimal direct exposure to commodity prices, our performance is influenced by certain differentials and overall production levels that, in turn, are impacted by major price movements and their effects on producers' drilling activities.

For example, capacity limitations on pipelines, or changes in location differentials, can impact the volume of Bakken production that is required to be moved, or preferentially elects to move, by rail, which, in turn, impacts our facilities segment activities. A material reduction in such volumes at the margin could impact our rail volumes and/or compress margins due to competition.

Since our November earnings call, crude oil and natural gas liquids prices have decreased approximately 40%, and basis differentials in a number of locations have compressed meaningfully. Natural gas prices have declined by 30% or more. These combined declines in commodity prices have collectively reduced the level of cash flow producers have available to reinvest by a meaningful amount.

In response, most producers have significantly reduced their capital budgets for 2015 relative to 2014 actual levels, as well as relative to their initial 2015 plans. The magnitude of such budget reductions varies among producers, but in general, it appears the average reduction is roughly in the 30% to 40% range, with respect to producers that impact North American crude oil production the most.

Our preliminary 2015 guidance anticipated some further weakening in crude oil prices from the roughly $80-per-barrel level, with the lower end of our guidance range effectively allowing for crude oil prices to fall to approximately $65 a barrel for a relatively short period of time. The prominent WTI price so far has averaged $48 per barrel, which is around 25% below the $65-per-barrel level.

As I mentioned in our November earnings call, we are not immune to the adverse impacts of a major step change in commodity prices that is accompanied by a similar change in producers' activity levels, especially during the transition. Accordingly, we have reduced the midpoint of our acquisition-adjusted EBITDA guidance for 2015 by 6.5% from just over $2.5 billion to $2.35 billion. This updated midpoint is based on our updated guidance range of $2.25 billion to $2.45 billion.

We have also revised our distribution growth target range for 2015. We are currently targeting distribution growth for PAA of 7% for 2015. PAGP's correlative distribution increase would be approximately 21%.

The decision to adjust our distribution growth was not without significant thought and deliberation. In establishing this new target, we considered a number of factors, including: our revised guidance range for adjusted EBITDA, and the developments and related uncertainties that triggered those revisions; our previous guidance for distribution growth, and our sense of current market expectations; our desire to be a top-quartile performer within the large-cap MLP universe on a sustainable basis; the concept of positive distribution coverage serving as a rainy day reserve; the upside and downside implications of a variety of alternative courses of action regarding distribution growth in an uncertain environment; the flexibility to adjust during the year should market conditions meaningfully change; and finally, the incontrovertible fact that stuff happens.

We also assessed our conviction that the current low oil prices are not fundamentally sustainable and, therefore, are self-correcting; and we contrasted that against the John Maynard Keynes axiom that the market can stay irrational longer than you can stay solvent. We weighed these and many other factors, and believe we landed on a situation-appropriate conclusion.

We retain the option to adjust upwards or downwards if subsequent performance demonstrates that this was a suboptimal decision. Given recent industry developments, we believe that achieving our revised distribution objectives will reflect positively on the resiliency of PAA's business model, the diversity of its asset base, and the strength of its project portfolio. Importantly, we believe PAA continues to represent an attractive risk-to-reward proposition that compares very favorably to our large-cap MLP peer group.

Based on the midpoint of our guidance, our projected distribution coverage is essentially 1 to 1 for 2015, give or take a few million on the $2.3-billion adjusted EBITDA scenario. As we've discussed in previous calls, we generally target minimum distribution coverage of approximately 1.05 to 1.1, based on the concept that relative to baseline performance in a normal market, that level of coverage should provide a cushion against any rainy day events. We believe the recent industry downturn falls into the category of a rainy day event.

Importantly, as we look forward to the next few years beyond 2015, we believe the expected cash flow growth associated with our ongoing expansion capital program will further strengthen PAA's industry-leading crude oil franchise, and enable PAA to continue to deliver attractive distribution growth, while also restoring distribution coverage levels to levels in line with our targeted minimum distribution coverage levels. Slide 7 compares PAA's historical performance with respect to distribution coverage with the crude oil price cycles going over the last 11 years, as well as a recap of our view regarding forward distribution growth and coverage.

Moving on to our CapEx activities for 2015, we believe the investments we have planned for this period will position PAA for solid performance for the next several years. To set the stage for my comments on our 2015 capital program, as well as our outlook towards acquisitions in this environment, I want to share our views on four key industry considerations.

First, the underlying supply-and-demand imbalance is self-correcting for a variety of reasons, and for a variety of reasons we think we will see a recovery in prices and an associated pick-up in drilling activity within the next 12 to 24 months, give or take a few months. An illustration of the potential impacts on production volumes based on recovery periods starting at each end of this range is provided on slide 8.

Second, the large North American resource base remains intact, and will be developed. At reduced activity levels, the overall production curve will shift to the right, peak production levels will be reduced, and the time period required to produce this resource base will be extended. This concept is illustrated on slide 9.

Third, as a result of recent developments, barriers to entry for a number of midstream activities have increased. In a nutshell, capital is less widely available, and it's certainly more expensive. Fourth, operating and commercial expertise and synergies will be more relevant, and fundamentally and financially sound business builders should benefit in the resulting environment, at least for a while.

In summary, although challenging in the near term, we believe this environment is a healthy one for PAA over the long term. We have a strong balance sheet and liquidity position, and an integrated business model and asset base. It is worth noting that we are building pipeline internal assets at strategic locations that interconnect with our existing asset base, and that have very long useful lives; in many cases, as much as 70 years or more.

Accordingly, as long as our ultimate assessment of the resource base, and the commodity price environment required to develop these resources, is directionally on point, we can afford to be wide of the mark regarding production volumes for the first 12, 18, or even 24 months without materially impacting PAA's long-term business or its overall economic returns on such capital investments. As a result, we are well positioned to continue developing our industry platform, develop our business platform via organic growth projects, and also to pursue complementary acquisitions.

With that in mind, we have targeted an expansion capital program for 2015 of $1.85 billion. Consistent with prior programs, the 2015 capital program is diverse, with the single largest project representing less than 10% of the total program; thus reducing the impact of a delay, cost overrun, or other issue on any given project.

Additionally, we continue to target returns in the low-double digits to mid-teens for the vast majority of the projects, reflecting the benefit of adding on to existing assets in the various resource basins, as well as interconnecting with our existing assets in other regions. Aside from the carry-over projects to be finished in the first part of 2015, the bulk of the incremental financial contribution will be layered into years beyond 2015, and thus, set the stage for future growth in adjusted EBITDA. We're also continuing to develop and advance additional projects that could be introduced into the program throughout the coming year.

Finally, we continue to remain very active with respect to acquisitions, and believe our synergies, commercial expertise, and financial flexibility should prove to be more advantageous in this environment than we've experienced over the last two or three years.

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

Thanks, Greg. During my portion of the call, I'll review our fourth-quarter operating results compared to the midpoint of our guidance, the operational assumptions used to generate our 2015 guidance, and provide an update to our 2015 capital program.

As shown on slide 10, adjusted segment profit for the transportation segment was $270 million, which was approximately $9 million above the midpoint of our guidance; and volumes of 4.3 million barrels per day were in line with our guidance. Adjusted segment profit per barrel was $0.68, or $0.02 above the midpoint of our guidance. The acquisition of a 50% interest in the BridgeTex pipeline in mid-November was the primary contributor to our financial overperformance in the quarter.

Adjusted segment profit for the facility segment was $151 million, which was approximately $4 million above the midpoint of our guidance. Volumes of 122 million barrels were in line with the midpoint of our guidance, while adjusted segment profit per barrel was slightly above guidance at $0.41 per barrel. Although volumes were in line with guidance, adjusted segment profit was higher than anticipated, primarily due to higher throughput on our Cushing terminal, and lower-than-expected operating expenses, partially offset by a slight delay in the start-up of our Bakersfield crude oil rail terminal.

Adjusted segment profit for the supply and logistics segment was $173 million, or approximately $12 million above the midpoint of our guidance. Volumes of 1.3 million barrels per day were in line with the midpoint of our guidance. Adjusted segment profit per barrel was $1.48, or $0.09 above the midpoint of our guidance. The higher-than-anticipated adjusted segment profit was primarily due to crude oil differentials that were more favorable than forecasted, partially offset by lower-than-forecasted profits in our NGL activities, which was largely a shift in timing into the first quarter of 2015.

Let me now move to slide 11, and review the operational assumptions used to generate our full-year 2015 guidance. For our transportation segment, we expect 2015 volumes to average over 4.9 million barrels per day, an increase of approximately 831,000 barrels per day, or 20% over full-year 2014 volumes. We expect adjusted segment profit per barrel of $0.68, or $0.04 higher per barrel than last year.

The volume increase is primarily due to forecasted increases of approximately 200,000 barrels per day on our Permian Basin-area pipelines, 137,000 barrels per day on our Sunrise pipeline, 90,000 barrels per day on our Cactus pipeline, 38,000 barrels per day on our Line 63/2,000 system, 96,000 barrels per day attributable to our interest in the BridgeTex pipeline, and 83,000 barrels per day attributable to our interest in the Eagle Ford joint venture pipeline.

For our facilities segment, we expect an average capacity of 128 million barrels of oil equivalent per month. Adjusted segment profit per barrel is expected to be $0.38, which is an approximate 7% decrease compared to 2014. The volume increase is attributable to a combination of minor increases in storage capacity at our Cushing, St. James, and Yorktown terminals, coupled with increased rail volumes, primarily attributable to our new Bakersfield facility; the expansion in our Niobrara facility; and our new Kerrobert terminal, which is expected to be in service in mid-year 2015. The decrease in segment profit per barrel is due to forecasted decreases in gas porosity, [swing] margins at our Gulf Coast facilities, and in rail fees related to the movement of certain volumes of Bakken crude oil.

For our supply and logistics segment, we expect volumes to average 1.19 million barrels per day, or approximately 33,000 barrels per day higher than volumes realized in 2014. Adjusted segment profit per barrel is expected to be $1.27, or $0.27 per barrel lower than last year. The volume increase in this segment is primarily due to anticipated increases in lease gathering activities. Segment profit per barrel is estimated to be 18% lower compared to actual 2014 results, as we expect to see compressed margins in the current low price environment, partially offset by increased margins related to crude -- to contango storage opportunities.

Let's now move on to our capital program. During 2014, we invested slightly over $2 billion in organic growth projects, which is in line with the guidance range provided last quarter. As reflected on slide 12, our expansion capital expenditures for 2015 are expected to total approximately $1.85 billion; and, as is typical with our capital programs, this is composed of a number of small- to medium-size projects spread across most of the liquids-rich resource plays.

Consistent with past practice, we will adjust our expected capital investment level quarterly, based on our progress on approved projects, and the potential approval of additional projects within our project portfolio. The expected in-service timing of the larger projects in our capital program is included on slide 13. I'll take a few minutes to provide a status update for a few of the larger investments.

Let me start with an update on our Cactus pipeline. We expect the line to be in partial service in April 2015. Initial operations will be in the 50,000 to 100,000 barrel per day range, ramping up to 150,000 barrels per day by August, corresponding with the completion of an expansion of our Eagle Ford joint venture pipeline. The line will be capable of moving approximately 250,000 barrels per day, and will be expanded to approximately 330,000 barrels per day by the first quarter of 2016, once our [quarter point] pumps are installed.

In the Permian Basin, we expect to invest approximately $365 million in 2015. We placed our Monahans to Crane pipeline in service in January this year. That line created about 100,000 barrels per day of additional take-away capacity out of the Delaware Basin.

In March, we'll begin construction of our 24-inch loop of the basin pipeline system from Wink to McCamey, which will ultimately add approximately 300,000 barrels per day of take-away capacity for the Delaware Basin. The line is expected to be in service in August of this year, with full utilization expected in 2016.

In addition, we have four projects in the Delaware Basin: a 16-inch pipeline from the [Brea Draw Area] to Wink; a 12-inch pipeline extension of our Blacktip pipeline to connect the Chevron/Cimarex Triple Crown station in Culberson County; our 16-inch state line pipeline extending towards the Cotton Draw area in New Mexico; and our 20-inch pipeline loop from Blacktip to Wink.

In the Eagle Ford, we expect to invest $120 million in 2015. We remain on pace to complete the expansion of our joint venture pipeline from Gardendale to Three Rivers in April of 2015, coordinating with the expected [partial] in-service date of the Cactus pipeline. The joint venture is also looping the segment from Three Rivers to Corpus Christi in conjunction with the gathering system the joint venture is building from the Karnes and Live Oak County production areas to the Three Rivers terminal.

The joint venture is also developing a marine terminal at Corpus Christi. The facility is expected to be in-service in late 2016, and will have the ability to service ocean-going vessels.

In the Rockies, we expect to invest approximately $50 million in 2015 to build a pipeline from Cheyenne, Wyoming, to our Carr, Colorado, railroading terminal, facilitating the movement of Niobrara crude on rail.

In Canada, we have approximately $520 million of expansion projects at our Fort Sask facility, including two new 350,000-barrel spec product caverns, two new ethane caverns with a combined capacity of 1.6 million barrels, approximately 5 million barrels of additional brine capacity, a truck rack, and a rail loading facility. These projects are all progressing on schedule.

We also have a couple of rail projects in progress. The rail loading facility in Kerrobert, and the expansion of our unloading facility at St. James, are the two most significant projects. Our Kerrobert terminal is expected to be in service in mid-2015, and the St. James project, which will enhance our ability to receive heavy crude oil, is expected to be in service by the third quarter of 2015.

Shifting to maintenance capital, expenditures for the fourth quarter totaled $73 million, resulting in total 2014 expenditures of $224 million, about $19 million higher than the top of our guidance, as we were able to make more progress on our maintenance projects than anticipated. For 2015, we expect our maintenance capital to range between $205 million and $225 million.

Before I turn the call over to Al, I wanted to mention a couple of other matters. First, during the fourth quarter, we received confirmation from the BIS that condensate process at our Gardendale facility meets definition of a product that can be exported. To date, we have not exported any processed condensate; however, we believe we are well positioned to segregate the processed condensate and to export the product when market conditions warrant.

Second, we've had a couple of lawsuits that have received some publicity. The first suit relates to our Diamond pipeline. The suit challenges our status as a common carrier. We believe we are a common carrier, and will defend our position, but have been advised not to discuss the matter on the call.

Also, in California, a group of plaintiffs filed suit seeking to have the court void the Air District's approval of our oily water sewer system permits at our Bakersfield rail terminal. Again, we believe we have valid permits, and will defend our position, but we've been advised not to discuss the matter on the call.

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

Thanks, Harry. During my portion of the call, I will provide comments on a few year-end accounting items and a general overview of our financing activities, capitalization and liquidity, as well as our guidance for the first quarter and full year of 2015.

As a result of significant price decreases during the fourth quarter, we had mark-to-market derivative gains, net of operating inventory valuation adjustments, of $166 million, which are associated with operating activities in 2015 and beyond. Additionally, we recorded a non-cash impairment totaling $85 million on our long-term inventory. As a reminder, our long-term inventory is comprised of minimum inventory and third-party assets and other working inventory that is needed for our commercial operations and is required for the foreseeable future.

From a business perspective, we consider long-term inventory to be similar to line sales, and do not hedge it, as doing so would create price risk, not eliminate it. However, under GAAP accounting rules, our long-term inventory is subject to impairment testing, which resulted in the non-cash impairment. Line fill is not subject to this type of impairment testing. As is our standard practice, both of these non-cash items were treated as selected items impacting comparability and, therefore, are not included in our adjusted results.

Moving on to finance-related items, in the fourth quarter, PAA issued approximately 3.6 million units, raising $197 million in equity capital through our continuous equity offering program. As illustrated on slide 14, for the full-year 2014, we issued 15.4 million units through this program, raising $866 million in equity capital. Since first implementing the program in 2012, we have raised approximately $1.9 billion. In the debt capital markets, PAA raised $1.15 billion through the sale of $500 million of five-year senior notes, and $650 million of 30-year senior notes, with interest rates of 2.6% and 4.9%, respectively.

As illustrated on slide 15, PAA ended 2014 with strong capitalization, credit metrics, and liquidity. In January, we entered into a new $1-billion, 364-day credit facility. This credit facility increased our committed liquidity from approximately $2.6 billion to $3.6 billion. At December 31, 2014, PAA had a long-term-debt-to-capitalization ratio of 52%, and a long-term-debt-to-adjusted-EBITDA ratio of 3.7 times.

Slide 16 summarizes information regarding our short-term debt, hedged inventory, and line fill at quarter end.

Moving on to PAA's guidance for the first quarter and full year of 2015, as summarized on slide 17, we are forecasting midpoint adjusted EBITDA for the first quarter of $580 million, and $2.35 billion for the full year. This guidance assumes that 2015 oil prices are plus or minus $50 per barrel, and that producer drilling activities are materially reduced relative to 2014. As Greg noted earlier, while we have minimal direct commodity exposure, we will be impacted by the anticipated reduction in oil production growth, and are also impacted by tighter differentials. Accordingly, although we could benefit from potential volatility during the coming year, our 2015 guidance assumes a near-baseline type of environment for supply and logistics, with compressed margins in this low price environment, partially offset by some contango storage opportunities.

As reflected on slide 18, our guidance for 2015 forecasts strong growth in our transportation segment relative to 2014. This 27% growth is primarily the result of our organic capital investments in the BridgeTex acquisition. The facility segment is forecast to be essentially in line with 2014. Collectively, adjusted EBITDA from the fee-based transportation and facilities segments are forecast to increase $253 million or 16% from 2014, and are expected to represent 77% of our total adjusted EBITDA. We expect this fee-base percentage to migrate to 80% or more over the next several years relative to baseline activities.

As Greg mentioned, our 2015 organic capital investment program is $1.85 billion. The majority of this capital will be invested in our fee-based transportation and facilities segment, and will have minimal contribution to 2015 results, but will provide growth for 2016 and beyond. This level of investment, combined with the $3.1 billion of capital investments we made in 2014, provide us with good visibility for continued multi-year growth, given the time lag associated with achieving full run-rate cash flows.

I would also like to point out some additional considerations regarding our 2015 guidance. First, our NGL business within our supply and logistics segment has inherent seasonality. NGL volumes and margins are typically the highest in the first and fourth quarters of each year, due to weather-driven demand in the winter months.

Slide 19 directionally illustrates our forecasted 2015 quarterly supply and logistics adjusted EBITDA, as illustrated in the green portions of the bars. 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.

Secondly, as illustrated on slide 19, we expect our fee-based transportation/facility segment to generate favorable aggregated quarterly comparisons in 2015 relative to the corresponding quarters of 2014. However, in our supply and logistics segment, our guidance assumption for near-baseline market conditions throughout 2015 results in negative quarter-over-quarter supply and logistic segment comparisons for the second and third quarters of 2015 relative to the corresponding quarters of 2014.

For more detailed information on our 2015 guidance, please refer to the Form 8-K that we furnished yesterday.

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

Thanks, Al. We are pleased with PAA's overall performance for 2014.

With respect to 2015 guidance, our planning case incorporates oil prices hovering around the $50-per-barrel level for the entire year, and producer activity levels calibrated to that outlook. Based on our understanding of the public information put forth so far by a number of producers, our approach appears to be on the more conservative side, as it appears many are forecasting a pick-up in prices during the second half of the year, which supports a higher activity level than incorporated into our outlook. As we proceed through the year, actual prices and developments will likely require all of us to recalibrate to some extent.

We believe our approach of honoring a continuation of current prices for the entire year is a reasonable and prudent course of action that hopefully errs on the conservative side, and positions us to benefit from an improvement in prices and activity levels, while minimizing our downside during an uncertain environment. We feel good about the guidance range we provided for 2015 operating and financial performance, as well as our distribution growth targets, and believe our expansion capital program will further strengthen our business platform for many years to come.

With this outlook in mind, let me now review our 2015 goals, which are highlighted on slide 20. During 2015, we intend to deliver operating and financial performance in line with, or above, guidance. We intend to successfully execute our 2015 capital program, and set the stage for continued growth in 2016 and beyond; increase our November 2015 annualized distribution by 7% over our November 2014 distribution levels; and finally, selectively pursue strategic and accretive acquisitions.

PAGP's goal is also highlighted at the bottom of this slide, which is to increase PAGP's November 2015 annualized distribution by 21% over the November 2014 distribution level. We are off to a good start with respect to our distribution goals, and we look forward to updating you on our progress throughout the year.

Prior to opening the call up for questions, I would like to mention that Ben Figlock was recently appointed by Occidental Petroleum Corporation to serve on its behalf as a member of our Board of Directors of PAA and PAGP, replacing Vicky Sutil. Ben currently serves as Vice President and Treasurer at Occidental. We are pleased to welcome Ben, and look forward to working with him over the coming years. We also want to thank Vicky for her dedicated service to PAA and PAGP Boards.

Additionally, I want to mention that we will be holding our PAA and PAGP 2015 Investor Day on June 4 in New York. If you have not received an invitation but would like to attend, please contact our investor relations team at 866-890-1291. That's 866-890-1291.

Once again, 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 in our first-quarter earnings call in May.

Gail, at this time, we would open the call up for questions.

(Operator Instructions)

We'll go to Brian Zarahn with Barclays. Please go ahead.

Good morning.

Good morning, Brian.

Greg, during the oil price slide, you've been able to get commitments for new projects, including today's Permian announcement. But given your new oil price assumptions, how do you view the organic opportunity set going forward?

Brian, I would tell you that we take a fundamental approach. Ours is a grassroots, ground up assessment of the resource base and a well by well, county by county analysis. We're picking the spots that we choose to build projects and to work on building future projects. I don't think the overall project portfolio has really changed in the aggregate size.

Certainly, I think there is -- versus maybe a view of what we would have assumed those projects would have been developed on, let's say, six moments ago, it's probably pushed out and to the right a little bit. But for the near-term, I really don't think we're going to see much different in what we undertake over the next 12 to 24 months than what we might have otherwise. It's really going to affect years three, four and five.

You kind of get that -- you see that impact, Brian, in that one slide where we showed the $80 case and the $50 case and the two recovery cases, it's basically just pushing everything out and to the right, but it's really not changing, from our perspective, the projects we were going after. I think it can affect the marginal projects that others might have been chasing to try and knock the top off the peak production curve, but that hopefully means there's probably less competition as we go forward, but our project portfolio really hasn't changed materially, wouldn't you say, Harry?

Yes, I would agree.

So, more of a timing issue. I'm looking at one of your projects. Can you give a little update on Capline? Has the timing of that potentially changed? I know it's a little farther out.

How should we think, if that project does move ahead, what is the opportunity potentially to bring West Texas barrels over to St. James, potentially increasing Diamond's capacity? How should we think about your overall asset footprint to get more barrels to the Louisiana Gulf Coast?

I'll let Harry comment on some of the details.

I would just say, if you stand back and look at it from 15,000 or 20,000 feet and you look at the interconnectivity, the extension of the Diamond pipeline from Cushing to Memphis, where it will cross over and be able to touch the Capline system and as you mentioned, the interconnectivity then, we already have barrels coming from West Texas, barrels from the Rockies into Cushing and then more Canadian crude coming in.

It really puts PAA in the cat bird seat with respect to being able to service many, many markets. I really can't add much in the way of information regarding the status of Capline and what's been put in the press so far, which is that the owners are conducting a study. I think in a call earlier this week, Marathon, which was the operator, acknowledged that they thought they would be bringing the study to a conclusion with respect to -- or finishing the analysis in the first quarter and then, obviously, there's a lot of discussion that has to happen with the operators. When you think about it, Diamond really adds a lot of additional optionality to the potential to optimize Capline.

It's a longer-term project. Diamond won't be in service until 2017. Any potential reversal of Capline would have to be after Diamond is in service. It's going to be largely supported by Canadian crude, supplemented by the ability to source crude off of Diamond, as well. Like I said, it's hard to say a lot more than Greg already mentioned, other than it's probably going to think of it as a longer-term project.

I would view it as an upside option, because it really does -- its' not contributing significantly to cash flow to date. I think the current cash flow that we receive off of Capline is probably in the $10 million a year or less. So, limited downside, very significant upside if you start running any kind of meaningful volumes through there on a reset tariff.

I'll stay tuned on that. Last one for me, on potential M&A, if oil prices are expected to recover over the next 12 months, does that imply a rather small window to do acquisitions? What's your view of the competitive environment to do accretive deals, given that there's so many potential acquirers?

This is John.

Let me back up and I'll give you a couple of comments on some things that have actually happened in the market and what we infer from them. We've obviously seen two material asset transactions, one of them in Williston, of note. The transaction obviously happened very quickly from a process standpoint. The price was, I would argue, attractive from a seller's standpoint, but sold to a very strategic partner and it was for cash.

The other inferences, E&P company, high quality E&P company, well-capitalized E&P company. I'm doing something this strategic. I'm going to bring that up because we would expect to see some more of that in the premium basins, which the Williston is. Second transaction I bring up happened in the Permian, a little bit smaller, all cash, clearly starts ups, sold by a private equity shop.

I bring it up because it was a cash transaction, again, one, in a premier basin, two, and the buyer is betting on a recovery in activities over the long term. It's probably analogous to what we're going to see going forward on the asset side, both from the E&P companies who are now looking at the sale as a more attractive alternative to an IPO because of timing and the amount of cash they can get up front and the need and desire to put their capital into the ground faster.

The third transaction, obviously, was the consolidation among the affiliated parties and is of note, which I'll now segue into what, from my perspective, we think is going to happen going forward. On the consolidation side combination, it feels like we're going to see, over the next 12 to 18 months, and I don't just put the timeframe in the next 12 months, that we will see an increase in consolidation among the MLPs, primarily because of the demographics value.

We've gone from 20 to 120-plus MLPs. Going into this, we had an enterprise value of $750 billion-plus and we've had a major change in the underlying fundamentals of the business, which will be the catalyst for consolidation. I do think, A, it's going to be very constructive and it will be at a measured pace. There is not going to be a sense of urgency, but it will be a measured pace.

People seem to be going through the machinations of trying to understand what the impact of the downturn is on their existing assets, their growth projects and their access on cost to capital. They're doing that now over the next three to six months as people figure out what the best alternatives to their business are, you should see an increase in activity. I don't expect it to be tomorrow. It's going to be, again, measured in what I would call constructive over the next 12 to 18 months.

This will be very self-serving. Hopefully, we've positioned ourselves, both from an access to capital and wherewithal from a capital perspective, to participate on the asset side where cash is necessary and more importantly, on the combination side, because I think the value of the equity, having a footprint, a large footprint for businesses when you're talking about combinations will be paramount in this market.

People are going to -- the deals will be bigger and the owners and Boards will give a lot of thought to who they are merging and taking equity from. I think it'll be on a constructive environment and an environment, which we've somewhat anticipated but planned for.

Brian, I would just say, I think, again, as John said, we're not really restricting our thoughts to the next 12 months, what we think is a 12- to 24-month window. I do think that, as John alluded to, the synergies and commercial capabilities that we have, have more value in this type of environment than they have had over the last three years when we were competing against broad availability of capital to everybody at very cheap levels.

And the other thing I'd just leave you with is that our goal is not to try and pick the bottom and say, let's wait until everything bottoms out before we make a move. We're looking for opportunities to build our business, make it stronger, make it accretive, and part of the negotiation for any transaction, especially when you've got a lot of synergies that it takes to make a transaction work is who gets the benefit of those synergies?

Do all of them accrue to the benefit of the buyer or do you have to share some of those with the seller to be able to get a deal done? The answer is probably the latter. So, again, we're not here to pick the bottom, but we are here looking for ways to, as we look out five and 10 and 15 years, how do we improve the strength of our business franchise?

Appreciate the color, thank you.

Our next question comes from Steve Sherowski with Goldman Sachs.

Just trying to drill down a little bit more on the guidance revision. It looks like your volumes, especially out of your Transportation and Facility segment are strong, at least expectations are for strong volume growth into 2015. I'm just wondering what was the primary revision with the guidance?

Does it have anything to do with, perhaps, your expectation for lower tariffs on certain pipelines or lower spot volumes? Maybe you could just talk a little bit about that.

Yes, Steve, if you look -- and we included this concept out there, but we have slides like this on each and every area basin. On slide 8 is really an overview of what an $80 environment looks like versus a $50 environment. As you can see, the volume growth in the red and the blue line stays pretty strong through the first three, four, five months of the year and then you start to see a fall off.

You're correct, in the projects that we have, we've got good volume growth, but at the margins, the volumes that were not included in the guidance now that we were before that may have been the uncontracted spot volumes we would expect to capture because of the overall just material balance that you need to do for takeaway capacity certainly adds a lot at the margin.

The second thing is, I think you saw the Facility segment was flat to down slightly. That's a combination of volumes, obviously, as I mentioned in my comments. At the margin, volumes competing for an exit out of the Rockies on rail are going to, number one, more competition to try and everybody fill up their rail cars and, two, it's going to compress margins.

It's a combination of expecting margin compression and having to adjust fees if appropriate to capture that value. It's really an amalgamation of all of that, but it's all really driven by the outlet, that change between the blue and the red line that you see there as it affects both pipeline and facilities.

On the Transportation segment, it's not tariff-related, it's volume-related. The tariffs are the tariffs. We had a forecast a little growth in 2015 and as Greg mentioned, it's flattened out to slightly declining in the second half of the year.

Hopefully, we're running a $50 case. We're certainly aware that others may be running expectation for, I heard, $65 on average. We would just observe that, in order to get to a $65 average when we've already averaged under $50 for the first 33 days of the year, prices would have to go tomorrow to $67 a barrel and stay there the next 330 days. Or if you believe we stay at $50 a barrel for the first quarter, you're going to have to go to $71 a barrel for the next 330 days.

I think we've got a very realistic outlook about what capital's going to be available to be invested, what's going to get invested, and more importantly, if you go beyond slide 8 and you look at each and every one of the areas, that's how we built that up. I hope, at the end of the day, they're right and we're wrong because our being wrong means we get to up our numbers. When somebody else is wrong, that means they've got to come down with their numbers and I'd rather be where we're at looking up than I would up there looking down.

That makes sense. That's helpful.

Moving on to John's comments earlier, just on E&P, potential E&P midstream asset sales. Is there any way that you could quantify or scope that opportunity?

Not -- I would prefer not to.

It's meaningful or we wouldn't have mentioned it.

Talking too much -- most of the time I want to respond about like Sergeant Schultz. The group at the end of the table doesn't even know who Sergeant Schultz was. Anyway, so I do want to kind of restrict some of my comments. I actually think it'll be fewer than most people expect, because you're going to want to have high quality assets underlying the mystery asset on what you're buying.

Those are, by definition, go to the people who have the most wherewithal to go through the downturn. I think it'll be fewer than most people expect today, coupled with there are a lot of people lining up in the private equity shops, lining up in particular, that want to step in and do structured deals. So, it'll be active, but I would take the under that it won't be as much as the market thinks.

I am probably think this will be the driver of the consolidation we've all been anticipating for the last decade within the industry, but it will take 12 to 18-plus months to unfold. Again, it's going to be constructive. I mean that in a positive way. It's not destructive consolidation.

Got you. That's helpful. If I could just have a quick follow-up question, in the past, you've mentioned that your Supply and Logistics business has occasionally acted almost as a private equity shop, filling demand or back stopping volumes, if you can't get those committed volumes from third parties. Do you see any potential opportunities for that type of transaction or deal playing out over the next 12 to 18 months, given weaker commodity price environment?

I may not have understood the comment. I don't think we ever view ourselves like a private equity shop, period. I think what we are able to do is we're able, because we have a very active gathering and marketing effort and we basically purchase at the wellhead roughly 1.1 million barrels a day, we have a better feel for the market than many.

We're able to, when we purchase those barrels, to determine how we're going to get those to the best market, whether we're going to move it by pipelines on our pipelines or by rail or on third party pipelines or in the case where we think there's, let's say two competing new pipeline projects necessary, where at least one of them's necessary to move product away from the market, we certainly have the ability to make a commitment from our S&L group to the Transportation group because we, again, have under contract those barrels and we get to select which market they go to.

So, I wouldn't characterize it as a private equity approach at all where I think they're just monetizing credit rating more than they are moving barrels on. That's what the self help is. That's why, during these down cycles that you saw on one of the slides I talked about, we're able make sure that the barrels go -- charity begins at home and we're going to send it through our pipelines.

That's helpful. That's it for me. Thank you.

Our next question comes from Jeremy Tonet with JPMorgan. Please, go ahead.

Hi, good morning.

Hi, Jeremy.

I was just wondering if you could comment a little bit more on the market structure for Contango out there. It seems like it's favorable right now. I know generally Plains only bakes in what's near-term and visible as far as guidance is concerned. I was just wondering what potential upside could we see if a favorable Contango environment persists through the balance of the year?

Certainly, we haven't put to bed all the Contango opportunities that are out there right now. There's a lot of considerations that go into those opportunities. There's certainly some potential for upside. As you say, we do factor into our near-term guidance capturing that, which is obviously available and makes sense to lock in.

I think, I would tell you at this point in time, while, again, there's upside to our numbers, there's other things going on out there. If we go back to $44 or a $40 price level, you might see that yes, we captured more Contango, but we may see producers producing less volumes than we forecasted.

So I go back to my comments in the conference call that we feel good about the guidance, we feel good about the distribution growth, and we certainly feel good about the long-term, but I would hate to try to take one aspect of what's going on in the market and say that will be additive and nothing else change.

Because, I think, personally, you're going to hear changes throughout the year and I think some producers think they can get by with only cutting their budget 20% and our numbers assume that they're going to have to cut 40%, I think you're going to see some of those changes ripple through there. It could be difficult -- there may be more opportunities to capitalize on Contango than what you currently see for the next couple of months as markets are dynamic, but there'll be offsetting aspects to it, as well.

I wouldn't want you just to hang your hat on that one very positive note that, yes, we are aware of it. We're following it and we're participating, but I just have to tell you there's a heck of a lot going on in the industry right now. We're in a state of transition and I think some are in a state of denial.

What we've tried to do is give you a very realistic approach that says, if you think about it, if I gave you a forecast that said, here's our numbers and they're right back where they were, let's say, before we revised it down, and we said we're counting on $65 oil, that means price would have to go up 40% from the current level.

I mean, it just doesn't make sense. You wouldn't want to tell me you at $100 an oil, we're counting on it being $140. So I think we're not in control of the mechanisms that are driving prices. We are on top of the issues that are driving volumes. That's what we've reflected in our guidance.

That makes sense. Thanks for that. I was wondering if you'd comment on rail and how rail fits into this new environment where basis differentials are a bit tighter. Do you see a bunch of change in your outlook there?

I think we forecast that or put it into our forecast for 2015 that we expect, for part of the year, rail differentials to be tighter than normal. It seems like a lot of the volumes are going to Cushing because there's sort of a storage full there and once storage gets full at Cushing, you should see the differentials normalize again where rail will go to a natural market. Cushing is filling up at a pretty high rate and in a few months it will be full.

I think we've seen this before where differentials can get upside down from what you thought historical relationships are. There's a really good chance we're going to see some of that happening here.

I would tell you, in general, rail, whether it's the railroad companies, whether it's those that furnish cars or those that furnish load and unload fees, are just like service and supply guys coming under pressure to the producers. That part of the market's going to come under pressure because there's a lot of excess capacity out there if volumes aren't following up everything and it's going to be margin compression.

As Harry said, we've tried to factor that into the guidance. I hope we're wrong and we get to revise our numbers up. It would have been foolish on our part to assume that we're going to do the same volume at the same price for the marginal barrel when we know that there's an excess of loading capacity certainly and then, as you point out, the differentials have come in.

We've seen already, in the last 45 days, brand trade inside of WTI and today, I think it's $6 outside of WTI. That doesn't sound to me like it's a steady state planning model.

Okay, great. So, at this point, would it be fair to say that you haven't deferred any of your growth CapEx plans on the rail side?

No, I think what we had in progress we were very confident with. We put in-service the Bakersfield facility. We've got a few tweaks backed by commitments on a few other facilities. We're preparing for some additional optionality in some of our unloading facilities.

And we've got the project up in Canada, we'll move heavier Canadian crude.

Okay. Great, thanks.

I suppose I'll leave with the obligatory M&A question at this point. I was just wondering, you guys have a tremendous crude oil platform. I'm wondering, a lot of the crude oil assets, I don't think we have seen as much pain at this point or prices necessarily come down where we've seen more pain in the midstream markets, more outside of crude towards natural gas, NGLs gathering and processing and potentially cheaper assets to be picked up there. I'm just wondering, is that an area that would be of interest to you to diversify further into, or is that something outside of what you're looking for?

We obviously have a substantial NGL business and we have continuously looked at the NGL assets that have been on the market over the last several years. We will continue to look at them.

They probably have been impacted by the commodity downturn as anybody in the, quote, midstream space, just because of the processing contracts, nature of some of the processing contracts and how close they are to the wellhead. So, we're trying to really digest what the cash flow generating capacity of those types of assets and businesses are.

I think that's the first thing you're going to have to do.

I think to kind of add on to that, Jeremy, number one, we're looking for good deals. We don't really have diversification as a strategy. We like the businesses that we're in and we'd certainly like to be bigger in the businesses that we're in.

I think where we have the most competitive advantages in an even playing field, is the absence of widely available cheap capital levels the playing field, is where we have synergies and we have most of those in the crude oil and the NGL areas.

So, we're not against good deals in other parts of the business where we already have a footprint, but we are not looking to, quote, diversify for the sake of diversification. We're looking for good deals and we think the good deals are mostly going to come in the areas where we have the synergies, which would be the crude oil NGL.

That makes sense. Thanks for all that color.

Our next question will come from Mark Reichman with Simmons & Company. Go ahead.

Good morning, just a few questions. With the Contango and the crude market oil structure, could you just talk about the contract profile of your crude oil storage and discuss your ability to benefit from perhaps renewing capacity at higher rates. And also, your plans to keep storage available for your own activities?

Keep in mind, we've got 120 million barrels-plus of above ground storage capacity and I could probably tell you that we're not going to be the company that's going to go out to our customers and say, there's a Contango market and we're going to try to jack your rates up because of that, primarily because the ones, Mark, that we serve are the ones that are going to use it regardless of whether it's a Contango or back-related market.

At Cushing, for example, I think we've got over 20 million barrels and 90% of that, 95% is leased to long-term customers that use it, again, regardless. They're the refiners, the guys that are operational storage. They were the ones that renewed with us when rates were low, at higher rates than others were getting. The ones that would probably fall into the category that you're adhering to are the ones not in the Tier 1, the preferred area at Cushing, but they're in Tier 2 and Tier 3, where they're really the only utilization for Contango opportunities.

They're going to do just what you said, if they can. As far as we manage a portfolio of assets, we haven't disclosed exactly how much of that we use for our own account, but it's meaningful. It's enough where we can participate in the opportunities, but not so much to where we've got a lot of dead assets, so to speak, when there's not Contango opportunities. Beyond, just by the way, the Contango that you see out on the strip for the WTI, there's always been other opportunities on a grade basis or location issue.

Again, I would just recap by saying, I think we have 5% of our tankage in Cushing is really for our own account and the rest of it's for the customers' account. That's the way we want it. It's the way an MLP with steady-state, fee-based activities growing its distribution wants to have it.

Throughout the rest of the 90 million barrels that we have throughout the US and Canada, there are areas where we have strategically peeled off opportunities or amounts of tankage for our own account and we'll use that for these types of opportunities, because as you might expect, the Contango doesn't just exist in Cushing, we're able to access it in other parts of the US and Canada.

With this challenging environment for producers, are you getting any requests for discounts on, say, like transportation contracts? Under what circumstances might you discount?

I can think of 100 reasons why I shouldn't answer that and not one why I should. Just because our customers -- we're here to get the best value for the service that we provide. If I could respectfully decline to give our competitors or our customers a road map as to how they can get more money out of my pocket, I'll do that.

Fair enough. Lastly, with respect to the state line pipeline, what would you expect in terms of the mix between condensate and crude?

I think state line is probably going to be more of a crude-based line. That whole area is variable. You get areas where -- you get pockets where there's 40 gravity crude and not too far away, you get pockets where there is 50 gravity crude. So, we're set up, all those systems to segregate the condensate and crude or to batch condensate and crude into Blacktip and then we'll have two pipelines from Blacktip to Wink, and then we'll have multiple pipelines out of Wink, so we'll be able to segregate the condensate if there's market demand to have it segregated.

Thank you very much.

Thanks, Mark.

Our next question will come from Cory Garcia with Raymond James. Please go ahead.

Two quick ones for you, flipping back to your commentary on 2015 guidance and recognizing and appreciate, actually, the conservatism on that $50 price tag. Curious if there's any rule of thumb or any color you could provide on different oil price sensitivities or if we should just simply back into, it was $80, now it's $50 as the difference or is there a different price points in terms of every $5 or $10 move higher from here equates to x amount of cash flow. Is there a rule of thumb to back into sensitivity there?

No, there's not, Cory. The reason for that and I'm going to get you back to slide 8.

To some extent, we don't have any direct exposure to the commodity price of any significance at all. We are impacted by what producers have available to invest and that's tied to their cash flow. We've clearly run areas for example where, in the Permian for example, a project at $80 oil may have made them a 35% rate of return, and at $50 oil, it only makes them a 5% rate of return.

That's an area, then, that we would say, we don't expect a lot of volume growth. On the other hand, we run numbers that say in that area that only has 5% return, if the service and supply costs that they're paying go down 20%, that number may go back up to 15 to 18%. There's so many issues that are below the surface that are going on that are going to impact that.

So, we do have perspectives in our Company as to each area what we think it's going to take to move that, but there's no way that you could put that in any kind of nomograph and say, here is the impact on PAA because, again, we're not the ones directly exposed to the commodity prices, it's the producers. But again, there's a lot of factors that can affect their availability of capital and their willingness to drill in particular areas and you almost have to have all the information we have to be able to come up with that.

So, I do think we try to combat that so we don't keep you in the dark. I think we put the most detailed guidance out there on area by area, pipeline by pipeline than anybody in the business and we'll continue to do that.

Absolutely appreciate that. There are quite a few moving pieces to this whole equation. Changing focus, up in -- for Saskatchewan, how should we be thinking about the phase in of cash flow from these projects? There's obviously a nice uptick in capital over the next two years. Should this be similar to your other projects where the cash flow gestation period, call it a year or 18 months, or is there different sort of phases to look in over the next, maybe 12 or 18 months, where we can actually see some of that cash flow ramp sooner?

Those are projects that take a little longer time to develop. You're developing caverns and rail facilities and brine capacity. So, it's probably more like 18 to 24 months.

Okay.

So it would probably start ticking in mid-2016.

Even there, Cory, you'll end up with like we had in Cactus where you're going to start off at one level and then the volumes will build up. That's why when we talk about a lot of the capital we're spending now really does not have any impact on 2015.

It'll start in 2016 and you'll probably see the full brunt of it in 2017, some of it even into early 2018.

Okay, great. Thanks for the color.

Our next question comes from Matthew Phillips with Clarkson. Please go ahead.

Good morning.

Hey, Matthew.

To really beat a dead horse on the M&A topic, in the past couple of years, you all have invested a lot of capital in the Eagle Ford and Permian, Mid-Continent in general. Do you expect M&A opportunities to mirror that, or do you see this as a chance to enter new basins, increase your footprint in Canada, things like that?

Again, I go back to we're looking for good deals. There's not an area that we're in right now we wouldn't want to be bigger and better in that. So, we're certainly looking in our own backyard. There's also areas that we believe that there's opportunity for volumetric growth where we don't have as big a footprint currently as we would like to have.

But I know you want to ask me on this call to tell our competitors where we're looking, so I don't have to worry about that. We're not looking for diversification for the sake of diversification. We are looking for good deals in areas where we can have synergies. I will say that there's an opportunity because of the way we have interconnected and would intend to interconnect any area that we branch out into geographically to capture incremental synergies.

You shouldn't assume that just because we're not there currently doesn't mean we wouldn't have synergies if we bought a footprint there. If anything, that's the kind of value we can bring to the table. It's more of the same.

Great, thank you.

Our next question is from Sunil Sibal with Global Hunter Securities.

Thanks for taking my question. My question is related really to the Facility segment and rail projects that you are bringing online in 2015. How should we be thinking about -- especially with higher volume commitments on those facilities and what kind of, in terms of percentages commitments are there and are the commitments sufficient to meet your hurdle rate of mid-teens returns on those projects?

Most of the projects that we're bringing on in 2015, in fact, are supported by commitments. Cactus, for example, is one, and it's got a lot of commitments and we also have some plumbing to do to be able to fully optimize the benefit of that. Even though we may have capacity the day we open that line up to do, to put 200,000 barrels a day in, we don't necessarily have the capacity at the other end of the pipe to take 200,000 barrels a day out if we move onto the system, that's why it's important for us to expand the JV.

Having said that, we have sufficient commitments on that and several of the other projects, Eagle Ford, et cetera, to support the expansion of those and meet our minimum rate of return. In some cases, the minimum rate of return is maybe 100 or 200 basis points over our cost of capital, which won't get you to the mid-teens, but then the optionality or the ability for spot barrels to fill up and space gets you there, which, again, is a function then of what the overall volume level is in the areas and what markets we serve versus others.

So, I think from a downside protection, we're in very good shape. From an upside opportunity, we've got room to run.

That's helpful.

On the M&A front, I think you previously talked about support from the GP, especially when bidding on assets in this very competitive environment. I was curious if there was updated parts there with regard to support from GP or IDR concessions?

We've been preparing them for this type of market for awhile. I can tell you we have no less tools than what we had coming into this and if anything, we probably have more desire to use the tools that we have. So, they're as supported today as they ever have been, and probably more so, especially when we see good deals.

Then just one last one from me, when you look at 2015 CapEx program in terms of the funding, you obviously did the $1 billion facility. How should we be thinking about supporting the 2015 program from a debt and equity perspective?

Our plan would be to continue to finance our growth capital with equity in long-term debt. The liquidity facility was designed to bolster our liquidity in what we think will be a fairly uncertain time. Again, the plan will be raising equity, either through our continuous equity offering program or through an underwritten offering and accessing the senior notes market at some point.

Sunil, the important thing is we'll continue to keep a balanced funding approach. We don't use the real low, slightly higher than free, short-term debt rates when we look at our analysis. We're using basically the10-year rate with our credit spread on top of it and we're using the equity, so it's about a 55/45; 55% equity, 45% debt and that's what we'll continue to do. No change there.

But, again, keep in mind we entered into this opportunity in the fourth quarter of last year, prefunded with the opportunity to take advantage of acquisitions. And we did and we got additional funding on the capital program but, again, nothing that's going to be a significant hurdle.

Okay, very helpful. Thanks.

Our next question comes from Lynn Chen with Hite, please go ahead.

Good morning, thank you for taking my question. Can you comment a little bit more about your current Contango market and how long do you think will it last? You just mentioned that Cushing is filling up very quickly and you may be full in two months or so. How will it change your Contango market?

Part of it's going to be a function of what happens in the other markets. Once it gets full, obviously, then the differentials are going to change. To pull the barrels out of Cushing, you're going to have to have some differential that supports the movement because to get from Cushing, let's say, to the Gulf Coast is about a $3-plus tariff. Right now, the markets, Lynn, don't support that movement at the margin.

So I think the answer is, depending on what happens to demand and refinery turnarounds, et cetera, you're going see a little bit like, if you are familiar with that name, whack-a-mol ely. You're going to see certain things pop up and you're going to knock that down and something else is going to pop up. If we had the road map for what it looks like, we probably wouldn't share it on this phone call, just because it would be a competitive advantage.

We do think we have assets in all the right areas to be a meaningful participant in that type favorable market, favorable for our business model, maybe not so favorable for others.

One of the refinery talked about their Contango market yesterday or the day before yesterday on their conference call said that they expect to use Contango it in the first half of the year, less Contango in the second half of the year or so. Do you think that makes sense?

I'd have to know more what their fundamental assumptions are and again, it may be specific to their regions that they're in. I really couldn't comment on that without having more context.

You're either going to need more demand or less supply to change the dynamics of the Contango market. It will be Contango until supply and demand get in balance and the fundamentals start pulling crude out of storage.

There's some quality issues, Lynn, that also will affect the ability to bleed the storage down so that you don't have a continued Contango market, because a lot of what we're producing today that is not wanted by the market is the lighter sweet crude or lighter condensate. To the extent that's getting stored, you're not only going to have to have a change in market structure, but you're going to have to change in quality differentials to be able to balance that out.

So, I think we'd probably -- if we had to err, we'd err on the side of if it. Once it gets in full in Contango, it could stay here longer than we think unless -- obviously, if Saudi Arabia comes out July 1 and says they're going to cut production a significant amount, it may change the market almost immediately, more for perception than reality, but it's still changing.

I would say anybody that actually says they know what the market's going to do -- I'll just leave it at that. It'd be tough to really have that kind of vision.

Thank you very much. Appreciate it.

Our final question will come from Selman Akyol with Stifel. Please go ahead.

One quick question here just regarding Facility segment guidance, your per barrel profit goes from $0.41 to $0.38 for 2015, and I think in some of the previous comments you'd made that was due to more competitive rail rates. In the fourth quarter that you just reported Facilities, you really called out -- you referenced declining natural gas storage rates. The question I'm asking here is, has that abated in terms of natural gas storage rates, or is that still a fairly strong headwind going into 2015 and is reflected in the declining rates there, as well?

It's included, but natural gas storage is only 4% of total EBITDA or something like that. It's not huge. So the point being, it's not going to be the driver for that. It's other factors, but all that is wrapped up, I would say, the natural gas storage is still facing headwinds. We had indicated a year ago that we thought this was probably stay around for three years. Hopefully, it still only has two years left, but there's no question it hasn't abated from where it was.

That's not really a big driver between 2014 and 2015. Gas processing in the Gulf Coast is also included in the Facility segment. Those margins will be tighter in 2014 than they were in 2015.

Thanks very much.

Thank you, Selman.

We have no further questions.

All right. We really appreciate everybody dialing in. For those who are invested in Plains, we appreciate your confidence in us and we look to update you on our activities for the First Quarter in May. Thank you.

Ladies and gentlemen, that does conclude your conference for today. Thank you for your participation and for using AT&T teleconference service. You may now disconnect.