Plains All American Pipeline LP (PAA) 2013 Q4 法說會逐字稿

(Operator Instructions)

Welcome to the Plains All American Pipeline and Plains GP Holdings fourth-quarter and full-year 2013 results conference call.

(Operator Instructions)

I would like to turn the conference over to our host, Director of Investor Relations, Roy Lamoreaux. Please go ahead.

Thank you, Moses. Welcome to Plains All American Pipeline's fourth-quarter and full-year 2013 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 plainsallamerican.com. I would mention that throughout the call we will refer to Plains All American Pipeline by its New York Stock Exchange ticker symbol of PAA. In addition to reviewing recent results, we'll provide forward-looking comments on PAA's outlook for the future. In order to avail ourselves of the Safe Harbor precepts that encourage companies to provide this type of information, we will direct you to the risks and warnings set forth in the partnership's most recent and future filings with the Securities and Exchange Commission.

Today's presentation will also include references to certain non-GAAP financial measures such as EBITDA. The non-GAAP reconciliation sections of our website reconcile certain non-GAAP financial measures to the most directly comparable GAAP financial measures, and provide a table of selected items that impact comparability of PAA's reported financial information. References to adjusted financial metrics exclude the effect of these selected items. Also, all references to net income are references to net income attributable to PAA.

Today's presentation will also include selected financial information on Plains GP Holdings, which we will refer to by its New York Stock Exchange ticker symbol of PAGP. PAGP's only assets are its economic ownership in PAA's general partner and incentive distribution rights. As the control entity of PAA, PAGP consolidates 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 that reconciles PAGP's distributions from PAA's general partner with the distributions to PAGP's shareholders, as well as a summarized, consolidating balance sheet.

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

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

Thanks, Roy, and good morning to everyone.

PAA finished the year in a strong fashion, exceeding the midpoint of our beginning-of-the-year annual adjusted EBITDA guidance by $267 million, or 13%, as well as the updated annual guidance provided in early November by $50 million, or 2%. Before we compare our fourth-quarter performance to guidance in a few minutes, I want to first recap the year's activities and accomplishments.

Somewhat similar to prior years, the pace and volume of activity throughout 2013 was very high. However, unlike years past, these elevated activity levels were not driven by efforts to negotiate, close, finance and integrate multiple and/or large complex acquisitions. Instead, we invested significant efforts to execute our 2013 expansion capital program, advance our portfolio of future expansion projects, increase our understanding of our fundamentals analysis, and initiate and complete two strategic transactions. Our overall execution of our business plan during 2013 was at a high level.

As reflected on slide 3, PAA achieved or exceeded each of the goals we set at the beginning of the year. In addition to delivering results above mid-point guidance in each quarter of the year, we completed our 2013 organic capital growth program materially on-time and on-budget. We raised distributions in 2013 by 10.6% through November while generating distribution coverage of 143%, and set the stage for continued growth in 2014 and beyond by ending the year with a robust capital program, and a very solid balance sheet and healthy liquidity position.

During the year, we actively pursued and reviewed a large number of attractive acquisitions that would have complemented PAA's existing assets and business model. However, competition for these acquisition opportunities was extremely intense and in virtually every case we concluded that the amount of consideration required to outbid our competitors was meaningfully above our risk-adjusted value assessment.

As I noted earlier, we did complete two strategic transactions during the year. In October, we completed the initial public offering of approximately 20% economic interest in PAA's general partner, which is now trading on the New York Stock Exchange under the symbol PAGP.

The primary objective of this transaction was to provide the owners of our general partner with a targeted level of liquidity. Additionally, the structure used to affect this offering provides an avenue for future liquidity for our general partners that will substantially minimize any disruption on PAA's activities or governance structure.

Specifically, the overall governance structure ensures solid governance of PAGP as a new publicly traded entity, while also preserving the well-functioning governance of PAA, minimizing duplication of effort, and over time, providing for a transition to a one share, one vote structure at the PAGP level. Additionally, because PAGP has elected to be taxed as a corporation, we now have an acquisition tool that could enable the PAA organization to structure a tax-free transaction with a C-Corp under the right circumstances.

I would also like to point out that although PAGP is a taxable entity, the step-up in tax basis of the initial transaction and expected step-up in future transactions suggests that PAGP will not incur current income taxes for a number of years. We also closed the acquisition of all of PNG's outstanding publicly traded units. Although we believe the strategy to launch PNG in 2010 was sound, in hindsight it is clear that our timing was terrible given the challenging market conditions that followed.

Operationally, PNG executed its organic growth program largely as planned and also completed a significant complementary acquisition within the first year of the IPO. The combination of these growth activities has more than doubled PNG's storage capacity since the time of the IPO. However, the IPO was completed just months before the natural gas storage market became very weak with the impact of shale gas development collapsing seasonal spreads and storage rates plummeting as much as 70% over the ensuing three years.

This decrease in market rates nullified PNG's expected distribution growth despite achievement of the volumetric expansion objectives. Over the intermediate to long-term, we remain optimistic about the outlook for natural gas storage markets. However, given the challenges we see over the next several years for that market, contrasted to the significant growth opportunities for PAA's crude oil and NGL businesses, and the relative cost to capital advantage of PAA, maintaining PNG as a separate public entity simply no longer made sense.

The transaction was completed on December 31, and we want to take this opportunity to thank PNG's common unit holders for their support and also welcome them as PAA common unit holders. I'll address our 2014 goals for both PAA and PAGP, as well as our long-term outlook in my closing comments.

Moving on now to our most recent quarter's operating and financial results, let me briefly recap PAA's fourth-quarter and full-year results. Yesterday after market close, PAA reported fourth-quarter adjusted EBITDA of $595 million. These results exceeded the midpoint of our guidance range by $50 million or 9%.

In comparison to last year's fourth quarter, which included a fairly significant above-baseline contribution by our Supply and Logistics segment, adjusted EBITDA, adjusted net income, and adjusted net income per diluted unit decreased by 2%, 14%, and 25%, respectively. However, with regard to annual financial performance during 2013, we delivered year-over-year increases of 9% and 4% in adjusted EBITDA and adjusted net income, respectively, and a 7% year-over-year decrease in adjusted net income per diluted unit.

Highlights of PAA's fourth-quarter and full-year performance for 2013 are reflected on slide 4. PAGP also reported results for the fourth quarter of 2013 yesterday afternoon. As mentioned in the introductory remarks, and as discussed in our November conference call, we do not intend to cover the details of PAGP's GAAP results during this call, as they are substantially redundant with PAA's results. Instead, we have provided in the appendix of our slide presentation reconciliations of PAGP's cash distributions to those of PAA as well as a consolidating balance sheet for PAGP.

Yesterday evening, we furnished financial and operating guidance for the first quarter and full year of 2014. As reflected on slide 5, our guidance for 2014 forecasted adjusted EBITDA will decrease 6% relative to 2013 actual performance, due primarily to the assumption that market conditions for the Supply and Logistics segment will return to baseline-type conditions during 2014. The midpoint of our 2014 adjusted EBITDA guidance is $2.15 billion, which includes a 15%, or an approximate $200 million year-over-year increase in adjusted segment profit from our fee-based segments and an approximate $340 million year-over-year reduction in Supply and Logistics-adjusted segment profit.

Using these essentially baseline-type forecasts, we are targeting 10% distribution growth for PAA in 2014, while maintaining a healthy distribution coverage of approximately 110%, which will result in approximately $140 million of cash retained in excess of distributions. As a result, the PAA's distribution growth, as well as anticipated increases in the number of PAA common units outstanding, we estimate PAGP's distribution growth will be 25% or more in 2014, excluding the impact of meaningful acquisitions.

We also believe market dynamics are such that volatility in market structure and basis differentials could provide above-baseline performance opportunities during 2014 for our Supply and Logistics segment, which would increase the implied distribution coverage, and thus increase the amount of cash flow retained in excess of projected distributions.

The potential for above-baseline performance in our Supply and Logistics segment exist due to PAA's meaningful presence in substantially all the primary North American producing areas, as well as our ability to participate in substantially all aspects of the midstream crude oil value chain. As a result, PAA is positioned to deliver solid baseline performance in typical markets, and above-baseline performance in markets characterized by volatile market structure and/or basis differential. The timing and impact of such market developments are beyond our control and difficult to predict, and thus are not incorporated into our 2014 guidance.

During the remainder of today's call, we will discuss the specifics of PAA's segment performance relative to guidance, our expansion capital program, our financial position, and the major drivers and assumptions supporting PAA's financial and operating guidance. At the end of the call, I will discuss our 2014 goals and our outlook for the future.

With that, I will turn the call over to Harry Pefanis.

Thanks, Greg.

During my section of the call, I will review our fourth-quarter operating results compared to the midpoint of our guidance, the operational assumptions used to generate our 2014 guidance, and our 2014 capital program. As shown on slide 6, adjusted segment profit for the Transportation segment was $214 million, which was approximately $4 million below the midpoint of our guidance. Volumes of 3.86 million barrels per day were approximately 36,000 barrels per day below the midpoint of our guidance.

Adjusted segment profit per barrel was $0.60, or $0.01 below the midpoint of out guidance. The lower-than-expected volumes and segment profit were primarily due to the timing of volume growth in the Eagle Ford area. And I'll note that our volumes in this area did grow by almost 50,000 barrels a day over the previous quarter.

Adjusted segment profit for the Facilities segment was $169 million or approximately $20 million above the midpoint of our guidance. Volumes of 120 million barrels of oil equivalent per month were 2 million barrels below the midpoint of our guidance and adjusted segment profit per barrel was $0.47, or $0.06 above the midpoint of our guidance.

Volumes were lower due to the timing of the in-service date of a new tank at our St. James facility, and slightly lower-than-forecasted rail unloading volumes. Although volumes were lower, segment profit was higher than forecasted due to a number of factors, including processing efficiencies at our Canadian facilities, higher-than-forecasted spot lease activity at some of our West Coast and Canadian facilities, higher throughput at a couple of our facilities, particularly our Cushing Terminal, and lower-than-expected operating expenses, as the lower operating expenses were primarily attributable to an annual true-up of operating costs at our joint venture processing facilities in Canada.

Adjusted segment profit for the Supply and Logistics segment was $209 million, or approximately $32 million higher than the midpoint of our guidance. Volumes of approximately 1.13 million barrels per day were in line with guidance. Adjusted segment profit per barrel was $1.99, or $0.29 above the midpoint of our guidance.

Overperformance was due to stronger volumes and segment profit in our NGL business, driven by increased propane demand from crop drying and the cold weather in North America. Volumes and segment profit were lower than forecast in our crude oil gathering business due to impacts from adverse weather and proration on some of the third-party pipelines in Yukon, Canada.

Before I discuss our 2014 guidance, I'd also like to point out that the combination of increased propane volumes and lower weighted average cost inventory pulls accelerated into fourth quarter of 2013 approximately $25 million to $30 million of earnings that were previously expected to be realized in 2014.

Let me now move to slide 7 and review the operational assumptions used to generate our full-year 2014 guidance. For our Transportation segment, we expect volumes to average approximately 4.1 million barrels per day, an increase of approximately 360,000 barrels per day or 10% over 2013.

We expect adjustment segment profit per barrel of $0.63 per barrel, an approximate 13% increase over 2013. The volume increase is primarily from forecasted increases of 190,000 barrels per day on our Permian Basin-area pipelines, and 150,000 barrels per day on our Eagle Ford-area pipelines. The adjusted segment profit per barrel increase in the segment is primarily the result of increased air freight, as well as the elimination of nonrecurring costs that impacted 2013 and are not forecasted to impact 2014.

For our Facilities segment, we expect an average capacity of 126 million barrels of oil equivalent per month, which is an increase of approximately 6 million barrels of oil equivalent per month, or 5% over 2013. Adjusted segment profit is expected to be $0.44 per barrel, or essentially flat to 2013. The volume increase in this segment is primarily due to increased rail capacity associated with projects placed into service in late 2013, and new projects that are expected to be placed into service in 2014.

For our Supply and Logistics segment, we expect volumes to average approximately 1.2 million barrels per day, an increase of approximately 100,000 barrels per day, or 9% over 2013. Adjusted segment profit is expected to be $1.29 per barrel, a 43% decrease from 2013 levels.

The volume increase in this segment is primarily due to anticipated increases in lease gathering activities. Margins are lower, as we do not expect to see the same type of crude oil location and quality differential that we saw in the first half of 2013, and because of the acceleration of earning in our NGL sales activity into 2013.

Let's now move on to our capital program. During 2013, we invested approximately $1.62 billion in organic growth projects, which is in line with the guidance range provided last quarter. As reflected on slide 8, our expansion capital expenditures for 2014 are expected to total about $1.7 billion, and as is typical with our capital program, this is composed primarily of a number of smaller- to medium-sized projects spread across most of the liquid-rich resource plays.

Our 2014 expansion capital number reflects our estimate of the amount of work we can complete throughout the year. Consistent with past practice, we will adjust our expected capital investment quarterly based on our progress on approved projects and the potential approval of additional projects within our multibillion-dollar portfolio. The expected in-service timing of the larger projects in our capital program is included on slide 9 and I'll provide a status update on a few of the larger investments.

I'll start with the Permian basin. We're expecting to invest about $430 million in 2014. Approximately $290 million relates to trunkline projects, including a new 20-inch pipeline from Midland to Colorado City, a line from our driver station in Spraberry to McCamey, a 12-inch line from Monahans station to Crane and a new 20-inch line from Jal to Hendrix that replaces existing lines and expands capacity from Jal. These lines are all expected to be in service in early 2015 and will enhance our ability to move a Permian Basin crude to multiple takeaway pipelines.

We also expect to invest approximately $90 million expanding our gathering system in the Delaware Basin and about $50 million expanding our Spraberry gathering system. We expect to start construction of our Cactus pipeline early in the second quarter of 2014, and we expect the line to be in the first quarter of 2015. This is a $440 million project and we expect to invest approximately $310 million of this amount in 2014.

We expect to invest approximately $185 million in 2014 expanding our rail loading and unloading capacity. This includes a new loading facility in Saskatchewan, Canada, a new unloading facility in Bakersfield, California, and the expansion of existing facilities in Van Hook, North Dakota and Carr, Colorado.

We are also evaluating a couple of other rail-loading opportunities in Alberta, Canada. At our Fort Saskatchewan facility in Canada we expect to invest approximately $180 million in 2014. Our capital program at Fort Sask includes the development of two high-delivery 350,000-barrel propane caverns, conversion of two existing 1 million-barrel caverns from propane service to an alternative service, and the development of 2.5 million barrels of a brine pond. We expect a small portion of these projects to be in service in the third quarter of 2014 with the balance of the investments coming into service throughout 2015 and into the second quarter of 2016.

Finally, maintenance capital expenditures for the fourth quarter were $52 million, resulting in 2013 total expenditures of $176 million. We expect maintenance capital expenditures for 2014 to be in the $185 million to $205 million range.

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

Thanks, Harry.

During my portion of the call, I will review our financing activities, capitalization, liquidity, and distribution coverage as well as our guidance for the first quarter and full year of 2014. In the fourth quarter through our continuous equity offering program, PAA issued 1.5 million units, raising $77 million in equity capital. For the full-year 2013, we issued 8.6 million units through this program, raising $477 million in equity capital, including our general partner's 2% capital contribution.

As illustrated on slide 10, PAA ended 2013 with strong capitalization, credit metrics that are favorable to our targets, and $1.9 billion of committed liquidity. At December 31, PAA's long-term debt-to-capitalization ratio was 47%, our total debt-to-capitalization ratio was 50%, and our long-term debt-to-adjusted EBITDA ratio was 3.1 times. I would also note that slide 11 summarizes relevant information regarding our short-term debt, hedged inventory, and line fill as of year end.

As we have discussed previously, we target baseline distribution coverage of at least 105% to 110%. When our business outperforms baseline expectations, we can generate meaningfully higher distribution coverage. Our practice has been to retain this excess DCF to fund our growth. As reflected on slide 12, PAA has consistently delivered solid distribution growth and coverage, and in 2013 our coverage totaled approximately $500 million, or 143%.

Based on the midpoint of our guidance per DCF and distributions, our distribution coverage for 2014 is forecast to be 110%, which results in $140 million of retained DCF. Given our strong capitalization at year end, our projection for retained DCF, and our intention to opportunistically use the continuous equity offering program to prefund our equity needs, absent significant acquisition activities, we do not expect to execute an overnight or marketed equity offering during 2014.

Moving on to PAA's guidance for the first quarter and full year of 2014, as summarized on slide 13, we are forecasting midpoint-adjusted EBITDA first quarter to be $525 million, and $2.15 billion for the full year. The full-year guidance reflects a $25 million or 1% reduction from the preliminary guidance we provided in November, as it incorporates unfavorable impacts of $50 million to $60 million, associated with the acceleration of NGL inventory profits in the 2013 that Harry mentioned earlier, as well as an unfavorable movement in the Canadian to US dollar FX rate.

The FX rate portion is more of a reporting matter than a 2014 economic issue, as our investments in Canada are expected to exceed our cash flow. However, it does impact reported EBITDA, DCF, and distribution coverage.

Our 2014 guidance reflects an approximate 6% decrease in adjusted EBITDA relative to last year. As is our practice, we have assumed a return to baseline-type market conditions for our S&L segment. Accordingly, the S&L segment profit decreases $338 million, or 38% from 2013 results. This assumed decrease is partially offset by forecasted growth of $206 million, or 15% in our fee-based Transportation and Facilities segment, as compared to 2013, primarily reflecting the benefit of capital investments made over the last several years.

Additionally, the $1.7 billion that we expect to invest in 2014 is also focused on our fee-based segments and that the majority of the cash flow benefit from these investments will not be realized until 2015 and beyond. The cumulative effect of these capital investments provide us with good visibility for continued multiyear distribution growth.

We also wanted to share two other observations about guidance for 2014. The first relates to the seasonality that is primarily associated with our NGL business conducted in our Supply and Logistics segment. Our NGL volumes and margins are typically highest in the first and fourth quarters of each year.

The forecast for this seasonal impact to our Supply and Logistics adjusted segment profit is illustrated by the yellow portion of the bars on slide 14. And remember, the first quarter 2014 incorporates the acceleration of NGL profits into 2013 as we mentioned previously. The seasonality will result in stronger distribution coverage in the first and fourth quarters, with lower coverage during the second and third quarters.

The second observation relates to the quarter-over-quarter results we expect to generate during 2014. As illustrated on slide 14, throughout the year, we expect our fee-based Transportation and Facilities segment to generate favorable comparisons relative to the corresponding quarters of 2013.

However, in our Supply and Logistics segment, due to the relatively strong results delivered in 2013 in our guidance assumption for near-baseline market conditions throughout 2014, we have guided to negative quarter over quarter S&L segment comparisons for the first three quarters of 2014 relative to the corresponding quarters of 2013. While not illustrated on the slide, the forecasted negative S&L segment comparisons will also result in negative per-unit comparisons for 2014.

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

Thanks, Al.

As is apparent from Harry's, Al's, and my comments, we are pleased with PAA's overall performance in 2013 and believe we are very well-positioned for the future.

Let me now review PAA's 2014 goals which are highlighted on slide 15. Specifically, during 2014 we intend to deliver operating and financial performance in line with or above guidance, successfully execute our 2014 capital program and set the stage for continued growth in 2015 and beyond, increase our November 2014 annualized distribution level by 10% over our November 2013 distribution level, and then fourth, continue to selectively pursue strategic and accretive acquisitions.

PAGP's single goal for 2014 is also listed on slide 15, which is simply to achieve an increase in PAGP's November 2014 quarterly distribution rate of approximately 25% relative to the initial quarterly distribution included in PAGP's IPO prospectus. We are already off to a good start with respect to our distribution goals.

Next week, PAA will pay a distribution of $0.615 per common unit, or $2.46 per unit on an annualized basis, which represents a 9.3% year-over-year increase over the distribution paid last February, and a 2.5% increase in the distribution paid in November. As shown on slide 16, PAA has increased its distribution each of the last 18 quarters, and in 37 out of the last 39 quarters, delivering compound annual distribution growth of over 8% over the past 10 years, and over 9% over the past two years.

PAGP will pay a quarterly distribution next week of $0.125 or slightly over that per Class A share, which represents a prorated distribution for the period following closing of the IPO on October 21, 2013, through December 31, 2013. The annualized distribution per share of $0.63, almost $0.64, per unit represents a 7.2% increase over the annualized $0.60 per Class A share included in PAGP's IPO prospectus. We look forward to updating you on our progress toward all of our goals throughout the year.

From an overall energy industry perspective, we expect the next 24 to 36 months will be fairly eventful. On the positive side, crude oil production in many regions of the US and Canada is poised to continue to increase meaningfully. This growth in production should sustain an attractive level of utilization of existing midstream assets, as well as drive demand for construction of additional midstream infrastructure. We expect petroleum demand for the US and Canada will remain relatively unchanged with increasing crude oil production being balanced by reducing the level of waterborne crude oil imports.

As a result, a very important issue will be how much worldwide crude demand increases. The current outlook from various recognized resources suggests the growth in worldwide demand is expected to be around 1.2 million barrels per day to 1.3 million barrels per day, which is roughly equivalent to projected crude oil and NGL production growth in the US and Canada. What that suggests is that if there is any shortfall in projected demand, a material recovery in crude oil production levels in countries like Libya, Iran, or Iraq, and/or a meaningful reluctance from OPEC countries to decrease their production in the event of an overall supply excess, it could have an adverse impact on crude oil prices and exacerbate the overall level of price volatility.

Compounding that scenario is an expected supply and demand imbalance available in the quality of crude oil and condensate available in certain regions of the US. As discussed in our 2013 analysts' meeting and in our various presentations throughout the year, a building oversupply of domestic medium and light sweet crudes and condensates could very well impact regional differentials. With existing refineries and transportation infrastructure operating at or near capacity, and the potential for unexpected operating issues, it is difficult to imagine that these forces will self-correct without also introducing volatility in crude oil basis differentials.

On a related point, although our 2014 plan and extended financial forecast incorporate a steady growth outlook for US and Canadian crude oil production, we believe conditions are such that meaningful potential exists for disruption in the forecasted production progression. Potential disruption catalysts include a meaningful decrease in crude oil prices and/or access to capital availability and/or an overall increase in the cost of capital.

We believe PAA and PAGP are well-positioned for almost any development. Specifically, we have and continue to make investments to better position PAA to participate in providing solutions for potential volume and/or quality imbalances in various regions. These activities include constructing our Cactus pipeline, our Eagle Ford condensate stabilization and fractionation facilities, and rail facilities in both supply and demand areas.

Additionally, we have deliberately reduced our overall financial leverage, and maintained a high level of liquidity in distribution coverage. As a result we believe PAA will be able to withstand any reasonable industry headwinds, capitalize on volatile market conditions, and be positioned to move decisively on any resulting acquisition opportunities.

Certain of these potential developments are incorporated into our baseline guidance for 2014, while others, like extreme basis volatility, are not included. As a result of PAA's diversified footprint and our proactive efforts, we believe we are well-positioned to capitalize on volatile markets by utilizing our expansive asset network and financial flexibility.

Prior to opening up the call for questions, I do want to mention that Bobby Shackouls and Victor Burk were recently appointed as independent directors of PAGP's board of directors. These gentlemen have a strong understanding of our culture and bring decades of valuable experience to these positions. We look forward to working with them over the coming years.

Additionally, I want to mention that as a part of our leadership development plan at Plains, we are rotating and cross-training a number of leaders within our organization. Although many of these moves are not readily apparent from the outside, for many in the investment community that follow PAA and PAGP closely, one of these moves will be quite visible.

In that regard, Roy Lamoreaux, our current Director of Investor Relations, will be transitioning to a pipeline business development role within the Company. The target is to complete the transition around midyear, which will be shortly after our June 5th analysts' meeting. Roy has done an outstanding job in his role as Director of Investor Relations, and while he will certainly be missed in our Investor Relations activities, we look forward to having him involved in our commercial activities.

Ryan Smith will be assuming the position of Director of Investor Relations. Ryan has over eight years of experience at Plains in various accounting and finance roles, and will be working closely with Roy for the next several months to ensure a smooth transition and a successful analysts' meeting.

Finally, if you have not received an invitation to our analysts' meeting and would like to attend, please contact our Investor Relations team at 866-809-1291. That's 866-809-1291. Once again, we want to thank you for the participating in today's call and for your investment in PAA and PAGP, and we look forward to updating you on our activities in our first-quarter earnings conference call in May.

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

(Operator Instructions)

Brian Zarahn, Barclays.

Looking at 2014 guidance, your lease-gathering volumes are expected to have substantial growth to almost 1 million barrels a day. Can you give us a little color as to the geographic mix of those barrels? Is it more Permian, Eagle Ford, Bakken, Mid-Continent?

Brian, it's spread throughout, but the big growth is in Permian, where we have the very large footprint.

Okay, and as you -- maybe looking longer term, assuming, how do you view the lease-gathering growth over the next few years? And how does that impact your baseline Supply and Logistics EBITDA of about $500 million, $550 million?

I guess there's two issues there, one's volume and one's margin. And I think if you go back and listen to our calls several years ago, we obviously were enjoying and have continued recently to enjoy some pretty outsized overall aggregate margins. But we had also forecasted that as some of the bottlenecks get resolved we thought that and competition was going to cause the margins per barrel to decrease.

And we're certainly seeing that in what we would call our baseline business, and so to some extent our volumetric growth is being partially offset by the margin erosion as a result of those two factors. I don't think anything has happened really outside of the band of [refills] that we thought would occur so it's pretty much in line with what we expected.

I think as we go forward we'll still have this opportunity that we've seen in the past for volatility to allow us to capture incremental opportunities that will cause that margin, on a periodic basis, to increase above baseline. So effectively, we're in all the large producing areas.

We refer often to the big three or the big six. Depending on whether you're talking big three or the Permian, Bakken, and Eagle Ford and they make up a significant amount of the projected volume growth. We would certainly expect to continue to enjoy a percentage of our fair share of that growth as we look forward.

So, I think it will continue to be competitive. I think if we do see some disruptions that, for instance, some of the -- looks like price volatility or access to capital markets that could cause drilling to slow down, we think it probably works in our favor in the long-term, because a lot of these competitors are really counting on an assumption that everything moves up and to the right on a continuous basis, and really don't have the cushion in their financial flexibility or the distribution coverage to be able to absorb those interruptions while we do.

I'll just add a little bit to what Greg said.

Greg already mentioned as we see volume growth in North America we certainly expect to see our fair share of that growth reflected in our gathering and marketing volumes, and we sort of look at 2014 as kind of a base-level type of margin generation in our lease-gathering activities. So beyond 2014 we would expect to at least generate similar types of margins that we see in 2014. So the volume growth would create incremental EBITDA growth when you go beyond 2014.

So your baseline EBITDA for supply and logistics, you think, is very reasonable for the next few years, and if you have volume growth above the million barrels a day on the lease-gathering side, potentially that range could get raised a little bit?

Beyond 2014, yes.

I think what's happening is the expected erosion in unit margins on the pure lease-gathering has happened pretty much the way we expected.

Okay. And this last one for me, you're spending additional dollars on the Permian on crude infrastructure. Over the next few years do you see -- what type of needs do you see for additional infrastructure in the Permian?

We have our volume forecast through 2017 going up about 1.9 million to 2 million barrels a day. When you look at the combination of Cactus, our line to -- our new line from Midland to Colorado City that will help supply BridgeTex and the BridgeTex new line. I think you're getting -- you're pretty balanced in the Permian Basin.

Steve Sherowski, Goldman Sachs.

In your closing remarks you mentioned light oil saturation. I'm just wondering, are there any geographies in particular that you feel are sensitive to that environment? And just as a quick follow-up, if you wouldn't mind just commenting on any changes you've seen in your backlog over the past six months or so, as light oil saturation has been a growing concern. And the back log I'm referring to is not necessarily like your 2014 CapEx, but more of that $7 billion potential project portfolio you've spoken about before.

Taking them in reverse order. Effectively, as we've been knocking out -- last year we spent $1.6 billion. This year we're guiding to a midpoint of $1.7 billion. The overall size of the program has actually stayed stagnant to growing, and we're rolling off those projects but replacing them with visibility of future projects. And so we would expect that probably, Steve, to continue for the next couple of years.

I think there could be periods in time, again, if there's interruption in the well completion rate or the drilling count, however you choose to look at it, that would cause those to very slightly, but by and large it feels like it's going to continue to have a -- directionally up and to the right. We don't think it's going to be a linear progression. Therefore, there may be periods in time there where, takeaway capacity catches up with production capacity or gets ahead of it.

That slows things down, but we do think the resource base and the productive capacity is there to continue to move these volumes up and to the right. So in direct response to your question, even though we spent $1.6 billion last year, the size of the backlog, if you will, has really not gone down.

No, that's great. And my apologies if I missed this, but when you mentioned earlier on about the M&A opportunities you were looking at, were all of them at the PAA level?

They are, they are. Our preference is, in all cases, to execute them at the PAA. Structurally, there is some opportunity to do a C-Corp-type transaction at PAGP, but even there our goal would be to get the assets down into PAA as expeditiously as possible, if we're able to do one of those.

And then I want to circle back, you asked another question and I didn't get to it, which was the -- you asked about the imbalance, if you will, or the saturation point on the sweet crude, and it's generally pretty much everywhere. I mean, there's areas that are more pronounced from time to time. But we're seeing a lightening of the overall strain virtually across the board.

And there's, in some cases, Gulf Coast for example, to the extent that the stream's lightening up in general in the base production, in addition you've had a lot of transfer of crude down into that area, so it's kind of moved the congestion point from Cushing down to the Gulf Coast.

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

Gabe Moreen, Bank of America.

Questions on NGL markets, and I know Al commented on the accelerated inventory sales in the fourth quarter. I'm just wondering how you're positioned in the propane markets right now, whether you'll be able to realize upside relative to baseline in 1Q given those accelerated inventory sales? And then I'm wondering going forward, given the tightness of the propane market, how you're pricing your services now, and also what's embedded in your guidance as far as locational spreads? And where you think -- where you think they're headed, big question. So just wanted to ask about that.

I'll start off by answering the first part of it, Gabe. On the -- when you look at first-quarter performance relative to the guidance we have out there, really, when you think about it, most of our propane supply is hedged right now. We're sort of filling all of the contractual commitments we have.

When you see propane inventories, they're all-time lows -- so there's not a lot of spot volume available in the market. Certainly, we have some potential for additional buy-ins. But we've pretty much forecasted -- our guidance pretty much reflects where we think we're going to be for the first quarter.

There certainly were upsides, if you will, in the winter period in what's happened to some extent on an inventory costing basis. If you sell barrels like we did in December that were basically purchased but originally scheduled to be sold in January, you're matching up the lower-cost inventory with the higher-cost sale, and that just simply causes a shift.

The overall winter is very healthy, in fact, it's going to be well above baseline because of the market conditions you mentioned. But I don't know that I would say in the NGL part of it, there's a lot of room for significant upside.

As we sit here today we're at the beginning of February, so whatever was built into the January and our February business is reflected in our forecast for the first quarter.

And as a follow-up to that, Greg, I assume you're going to be cautious in terms of filling up higher-priced inventory that going into the off-season are much higher-priced inventory, and that you're probably going to be pretty fully hedged going into next year, is that fair?

Yes, you can write this down. We're fully hedged every year. We, certainly, when we acquired the business from BP, they took a different view and we said we'll give up the upside because we're not willing to expose ourself to the downside. So when we purchase barrels, we have it matched with the sale.

Clearly we make decisions as to when we want to engage in that because in some cases you want to go early to make sure that you're ratably filling up. And in some cases you want to keep some of your capacity because if margins widen out we can match a purchase and a sale with a wider margin.

So we have to make those judgments, and because other than people in the financial community listening to the phone calls, we don't give them our game plan as to how we're going to do that. We do have a significant volume of inventory and we're a big part of that market. And so, we certainly have our own game plan as to how we think we'll do best to optimize 2014.

Directionally, I would tell you there is the conditions that for 2014, and I have to bleed that into the 2015 winter, in other words, it's really a seasonal period. We start filling up in the summer but we take it out, most of it, in the winter periods, which includes not only this year but early part of next year. There's certainly an opportunity for that overall trend, given the way the market has shaped up, for us to capture incremental opportunities. It's just too early to say where those will be and what year they'll fall in.

Another question in terms of the, I guess, rail safe car safety debate that's sort of taking place right now. I just was curious, in terms of the railcar ownership at the PAA level, how many cars you feel qualify or not, and just how you think the market dynamic evolved, could they come down with these retrofit rules, and whether that will have impacts to your business?

All our cars meet the new standards, the post-2011 standards both in crude and NGL. There'll probably be some changes in the rail car specifications. The question is going to be, is it phased in over two or three years or phased in over 10 years? And, you know, if it phased in over a shorter time, you've got a lot of rail cars. It's going to be hard to retrofit rail cars in a shorter time period, just because you have limited capacity at the facilities that can retrofit rail cars.

I would say that it's a fair statement because of our existing footprint there and the fact that, as Harry mentioned, all of our current cars qualify, that we should be as well, if not better positioned than most anybody else in the crude oil side of that equation because of the scale and scope that we have and the fact we had cars on preorder that give us kind of the early preference, if you will, on priority in any retrofit that would happen.

And then, just last question from me, it's a little bit of a soap box question, Greg. Just in terms of the debate on crude oil exports that's surfaced here in the last couple months, where you think it's going, whether you think we'll see action in terms of more permitting on the crude oil export side, and I guess, whether you guys are starting to position for that.

Well, in general, if you gave me a choice, between trying to predict what our government is going to do and what our weather is going to do, I'd rather predict the weather. It's erratic but it's more logical.

So it's just really hard to say. We've seen even the inference of export capability can have an influence on the market. I think this announcement that happened yesterday or the day before was simultaneous with about a dollar tightening on the WTI Brent. It doesn't have to make fundamental sense for it to have an impact on the market.

Ultimately, we're positioned, we think, well for either answer if they allow blanket exports. We have assets in the right places that can help fill that market niche. If they allow it on a delayed blanket basis, in the meantime, we're going to have -- continue to see facilities that are constructed to try and help balance the market.

If you look back at our analysts' day, I think in 2013, we had a slide on there as to how we thought -- what the menu was, if you view it that way, of solutions that it was going to take to balance the quality imbalance in the US. And our conclusion then was, it's going to take an all-of-the-above combination of splitters, combination of more aggressive blending of heavy crudes with the lighter domestic crudes to be able to meet the refinery slate, refinery modifications on the front end of the refinery to be able to knock out the really light ends, and then leave more of a meaty barrel to process. And of course, then you can export the light-ends once you've gone through the processing.

And part of it is going to be an interpretation of what really qualifies for an exportable barrel. And our view today is not really unchanged. I don't think we've gotten any guidance from the government as to where they're going.

It's encouraging that they're taking up the debate earlier in the process than what we probably would have otherwise thought. That does not necessarily, as some of their other actions have indicated, that they'll do something on an expedited basis to address it.

Also just to add to that, if there was export, if you had the ability to export or re-export, we've got a couple locations that we could load ocean going vessels. Yorktown is a location where we can rail in and load out on ocean going vessels. We've got the ability to do that at St. James and we're developing export capacity at Corpus Christi as well.

Michael Blum, Wells Fargo.

Two quick questions for me. One, could you expand a little bit on your comments on the quarter? You talked about, in the pipeline segment, seeing lower Eagle Ford volumes. Can you talk about, from your perspective, is something changing in the basin, is it just a timing issue? A little more color there.

It's mainly timing. I think actually, Michael, our outlook for the overall Eagle Ford volumes has increased. I think we moved back up. I think our 2017 rate for the Eagle Ford is back up to around 1.6 million barrels a day now. We'd had it down just a little bit, but it appears that most of the issues are just timing of the ramp-up as opposed to performance levels.

There are certainly areas and pockets. Eagle Ford covers a big, big area and we're seeing areas where the performance is not, perhaps, as good as maybe, in that area, as we might have thought. So we've adjusted for that but we've seen then the rig shift to a different location. And they pick up better volumes in other places. Because of our footprint is everywhere in the western part of it, we seem positioned to benefit from that. So it's more of a delay than it is an overall performance factor.

And we have pretty meaningful growth on our Eagle Ford systems forecasted for 2014 also, in the 150,000 barrel a day neighborhood.

Okay. Great. That's helpful. And then my second question is, naturally, now that you've bought in PNG we're seeing volatility in that market. Can you talk about, conceptually, with (inaudible) prices spiking, but the seasonal spreads actually look like they're getting worse, are you benefiting from that in that business today, and how do you see those spreads? And will this volatility translate into wider spreads going forward?

Well, sorry it hasn't shown up in the market yet. I think the volatility is certainly helpful, that and the overall significant draws to reinforce to people that storage is a necessary component of balancing the market.

I think there's -- we've gone through a fairly good period of time where people have been content that storage was not as important in the overall physical balancing as they have proven historically. And, I think, when we have these long cold spells and some of the storage providers in a business perhaps having difficulty meeting some of their contractual objectives, it just helps to reinforce that. So I think it's going to take us a while to figure out, longer-term, whether it will show up in the spreads.

I do think we'll see better selectivity through the customers and willingness to pay a higher rate for those facilities that can make sure that when you need it, you have it. You know, it's no different than really, insurance. You don't always go buy the cheapest insurance if you're actually going to use it, because if you have to go draw on that and they don't cover the claim, it doesn't help. That's really what natural gas storage is for this type of market; it's the shock absorber that helps you balance, physically, the market.

I think at one point in time, just to give you a point of reference, we at the peak withdrawal day in the winter so far, we -- our three facilities added together were about 5% of the total volume, and yet as a percentage of storage, we're much smaller than 5%. Our deliverability has been very good.

I think the other thing to consider, Michael, most of our withdrawal capacity in the peak withdrawal months is really dedicated towards our firm shippers, our firm storage customers. So you don't really have the flexibility in these months to capture some of the arbitrages that exist here from our standpoint. So our opportunities usually come in the shorter months.

But again, it gets back to, our customers have that ability, and what's frustrating for them is if they think they've contracted for it and they go to pull on it and they can't capture it, that causes them, the next year, to say it doesn't do me any good to have storage at XYZ facility if I can't actually access the market. So it ultimately translates into a better long-term customer base for those that can, and we would put PAA's facilities in that higher-grade category.

John Edwards, Credit Suisse.

I'm just curious, obviously, you've been talking about your segment margins in your Supply and Logistics, you're taking it down to a more normalized level, so you're guiding to $1.29 for the year. And then, of course, you have the disclaimer, lots of volatility. If you were able to put, say, a range on what you think those would be, I mean, could you give us a little more detail or thought about that?

I think if you just look at the last couple of years, John, I don't think it's deteriorated as to what the upside potential is. We've been guiding people to a baseline level, again, associated with margins that we thought would stabilize out, as Harry mentioned, to what we currently are forecasting for 2014.

And that aggregate roll-up was about $500 million to $550 million of what we call baseline for Supply and Logistics. So if you take the midpoint of that at $525 million, we're forecasting this year $555 million, I believe it is. And yet last year we were in the $800 million plus, and the year before that, the $800 million plus, so you're in the $250 million to $300 million, $350 million incremental opportunity range.

What's important to note is that none of the opportunities, though, that have happened in 2012 and 2013 were exactly comparable. It happens in different places. In some cases it's a volumetric bottleneck, in some cases, because of takeaway capacity not keeping up with production capacity. And in some cases it kept up, but it was so tight that when there was an operational interruption on, let's say, a refinery or a delay in a just-in-time pipeline capacity coming onstream, it causes that to trigger an imbalance, and that imbalance then reprices all the marginal barrels.

We don't think -- personally, I don't think that those situations have gone away, we just can't tell you what quarter they're going to happen in, or if it's even going to happen in the next 12 months. But it's hard to believe it doesn't happen in the next 24 months, because that would mean that everything had to go perfect, everybody was on time, refineries don't have any problems, weather doesn't cause an interference. The more and more volume that goes on rail, for example, the increased congestion alone, forget all the government rules and concerns, becomes an issue and then you have weather in the middle of that and it backs things up in the system.

At the end of the day that causes volatility and causes pressure on volumes and regions, and that's where PAA, because of its participation in the full part of the value chain and its strong balance sheet, and its knowledge, can capture on that. So again, we definitely think there's an upward bias to our projected results if we see volatility. And we do believe we will see volatility, we just can't tell you when it's going to happen or exactly where it's going to occur. It's just really hard to believe that the conditions are such that they won't occur.

Okay. That's really helpful. And then you raised your CapEx outlook for the year to $1.7 billion from the previous -- what you were discussing. I'm just curious, on the projects that you're considering that are not on the backlog list at this time, are you continuing to see the backlog or the products under consideration? Are they continuing to rise? Is it staying relatively flat? If you could give a little detail on that.

It's still very healthy. I think we have an upward bias on that, as well, as we have in the prior year. If you recall, last year we ended up at $1.6 billion; I think we started the year at $1.2 billion.

And so as we mature projects we add them to the current year. We're very comfortable that what we currently have going on without regard to future events, we're going to be in that $1.6 billion to $1.8 billion range. So call it $1.7 billion.

We continue to have a lot of projects that we work on behind the scenes that we're having discussions with customers on, currently, about moving those things forward. Because we have such a large footprint in the crude oil space and we know who needs the service, to move it from the production areas, we know who needs to acquire it on the refinery areas.

We really don't need to go through massive open seasons to determine where the interest is. So we really don't broadcast that and it doesn't help us to put our game plan out there and show where we're thinking about building something.

So I would hope that we would see two things happen over the next 12 months. We would see the 2014 program, at least be in the middle of that range, with a bias toward, probably, at the upper end of the range, if not through it. And then we would see a better definition for the 2015 program as we get through the year as those projects that you're mentioning that we are, indeed, working on basically crystallize into something that's coming to an announcement. I think, if you think about it in November, early November, we reiterated that our guidance -- capital guidance for 2014 was in the $1.3 billion to $1.5 billion range, so call it $1.4 billion.

Within the next 30 to 45 days after that conference call, several of the projects we were working on crystallized and I think we announced in the Permian, for example, $400 million to $500 million of projects, some of which were in the original estimate range and some of which were incremental. And then we announced some other stuff in the Eagle Ford, and so now here we are today less than 90 days later, and it went from a $1.4 million midpoint to a $1.7 million.

And we're -- it's that dynamic. So I think it's exactly what you would hope for, which is, things continue to bubble up to the top, crystallize, and then get implemented.

Ethan Bellamy, Baird.

A couple modeling questions to start with.

Is $1.7 billion a good CapEx number in 2015 and 2016 as well, or are we off-mark modeling that?

We're not extending our guidance to that level. I think we have said, Ethan, that we felt comfortable that the minimum amount we'd spend would probably be in the $1 billion to $1.5 billion range in -- over the two years succeeding our current year. And again, we hope to ramp that up.

But I don't want to guide you to a number and then have to talk you down from it, realizing that as a practical matter, and I know you're trying to do multiyear models and we applaud that, is, what we're spending in 2014 is going to have very minimal impact on 2014 cash flow. It's going to have more of an impact on 2015 and 2016. So when you start talking about the 2015, 2016 capital programs, they're really going to have an impact on 2017 and 2018 results.

I think we're bold enough to forecast in more detail and more granularity than many of our peers out farther about how we're going to get there. We're not so bold as to go out four years on the CapEx side. Because things do change. Realizing my earlier comments was that we think somewhere in the next 24 months, we think the up and to the right may have to take at least one breather if not two.

That would change that outlook, and so I'd hate to talk you back down from a number. But I think if you were trying to model in the neighborhood in 2015 and 2016, somewhere between $1 billion and $1.5 billion is probably not an uncomfortable number. You may be wrong in one year and right for an average of the two, depending on what happens there.

What kind of ATM issuance should we assume per quarter?

We don't provide that level of guidance, just because we want to be opportunistic. If you do look at our average units outstanding in the 8-K, you can back into a number of unit's growth and then use your judgment as to how to model them out. We're fairly opportunistic depending on what we see and our price and that type of thing.

We're so far ahead of the cap because we're not trying to pressure the market. We're just trying to, basically, take advantage of it and help level it. And I think it's probably a fair statement, last year, Al, we raised a total of $475 million-ish and we basically sat out one quarter. So there's quite a bit of capability there. Just, again, we wouldn't have been able to tell you at the beginning of the year when we were going to be in the market or when were going to be out.

To some extent it's been a function of capital inflows. Some of these funds get formed and they go into the market to acquire some of the bigger cap, there's an opportunity to provide supply, if you will, for their demand without disrupting the market, and that's in everybody's best interests and so, to some extent, tell us the [bunt] flow is and I'll tell you what our answer is.

With respect to the tax outlook for PAGP, any changes there since the IPO?

None.

Okay. Greg, one big-picture question. You had to take a mulligan on gas storage. What's the next gas storage that you're either avoiding right now or have suspicions about?

You mean in terms of decision?

Yes, just other stuff in midstream that might be overbaked or oversold?

You know, I think today there's not one necessarily on the horizon -- on the plate. I think on the horizon if the longer that we go without either a price correction or visible volume -- demand growth, it just tells you if we continue to add a million barrels a day of productive capacity in the US and Canada and that neighborhood, and we ignore the fact that you've got Iraq, Iran, Sudan, Egypt, Libya, Syria, all that capacity out there, it just tells you that, ultimately, it's getting more brittle as you go out that far.

Again, for PAA's business model that's not necessarily bad, because it creates volatility, and we have assets in all the right places, most of the right places, we believe we do. So, you know, in gas storage, again I think volumetrically we called it right.

We just, on the market clearing price was impacted by a lot of events, and just was terrible timing so we're just taking our lumps. Let me put it in perspective, if somebody invested in PNG -- for our biggest mistake they made an 8% compound annual return over a three-year period -- If the worst we do is that, we're happy campers.

Do you have any interest in Jones Act tankers?

At the right price. The big issue with Jones Act tankers is if they -- they have significant value if you don't have export capability today. If you had export capability or if they basically waive the Jones Act requirement. That wouldn't be a fun factor.

Cory Garcia, Raymond James.

One quick housekeeping item. We saw that crude by rail volumes were pretty flat this past quarter, recognizing that there's obviously some weather impacts there. Have you seen any real weakness in flows down to the Gulf Coast yet, given the pricing weakness this past quarter? And again I recognize that you have a majority of your volumes committed down there. Just wondering what the customer reaction has been to the disconnect we've seen down in that market.

I think volumes have been slightly lower into the Gulf Coast. And the combination of weather and, probably, the weaker differentials into the Gulf Coast. Probably higher values at the East and West Coast and the Gulf Coast, occasionally.

Okay. That makes sense.

I think one of the things that would be important to realize, I mean, with the development of our Bakersfield facility and the completion of what we've got at Yorktown, we've got all the markets and so we may not be running full-out in any picture at all three of those facilities, but we'll be able to capture the best markets for any market.

Yes, I absolutely agree. In this evolving market diversity is definitely going to play in your favor.

Ross Payne, Wells Fargo.

Greg, obviously, acquisitions were pretty richly priced out there this last year. But, you know, as you look at that marketplace, do you think most of the opportunities over the next two to three years are going to be on the C Corp side? And secondarily, there have been mergers within MLP space, stock mergers. What do you expect there in terms of opportunities here?

Thanks.

I think those are hard to predict which one's going to occur in what sequence. I think we feel directionally, that it's going to be hard for us to get through the next two or three years without seeing some really good opportunities, which is why we're lowering our leverage so that we have the ability to take a bold step without having to, one, rely on access to the capital markets, to be able to allow us to execute that transaction, or have to strain our balance sheet, neither one of which we want to do.

And so we're prepared now with PAGP for really all three asset acquisitions. We think there's still a lot of decent assets to come to market.

If the capital markets become stingy with capital, that means we'll have the ability to have less competition and be able to use our synergies as our distinguishing characteristic as opposed to everybody having cheap cost of capital and access. And then, certainly, there's several MLP entities that we think fit strategically very complementary, that have a lot of synergies. But it's difficult at current valuations.

So tell me when the market's going to have a major correction and I'll tell you which is going to come first. We just think we're well-positioned for all three because we have the financial strength, the operating synergies, that can add value and make a transaction fundamentally sound, and we have the skill sets proven in the past.

So we're going to continue to be disciplined. We're not going to blow our balance sheet apart trying to make one of those happen. We have -- we effectively lowered -- if you take our 3.5x to 4x debt to EBITDA target range and use the midpoint of that as your anchor at 3.75x, we've lowered our leverage roughly by 6/10 to 7/10 of a turn. Put that on $2.2 billion of EBITDA and that means we could write a check tomorrow for $1.5 billion cash, be it 3.75x, even if we had no EBITDA. If we did that, I'd probably fire me as CEO, but we have that capability. What it says is that we can go out there and buy something at a high multiple, and still stay well within that range, and allow our synergies to catch up with it to lower the multiple.

We can do that even if the capital markets for equity are not available. And that's a very comfortable position to be in, and we do think there will be opportunities. We think some of the prior transactions that have happened have been fully priced.

But not to say they can't achieve good returns if the market stays up and to the right on those volume forecasts. But if there's an interruption in that, we think those deals could have trouble. And whether we look at purchasing the asset from the buyer -- purchaser, or purchasing the entity, either one of those are attractive to us.

Elvira Scotto, RBC Capital Markets.

I just wanted to follow up on a couple other comments that were made. If the US were to allow exports, how do you see that potentially impacting your growth project backlog? I know you talked about potentially expanding export capabilities at some of your facilities, but how do you think the opportunity set would change longer term?

Kind of, if you're looking at all the potential projects that you're looking at now, would you see an increase in opportunity set? Or do you think some of these projects would grow off if we remove some of that congestion out of the Gulf Coast?

Elvira, I think, to be very honest with you, I think what it would do is take away some of the potential for our capital program to grow from what we've already put out there. I don't think it affects it in terms -- at all, in terms of reducing it. But it may mean that if we think there's a potential for $1.7 billion to grow to $2 billion if all these projects come to pass, it may mean that it only goes to $1.85 billion as a potential or $1.9 billion, realizing that these projects -- a splitter project, for example, from the time you say go is probably a year and a half to get it online and it takes -- you're going to split that investment over, whatever you started, over at least a two-year period.

But depending on what year you start in it, it may affect this year's very minimally and next year's potential more significantly so. And then part of it is, what are the conditions on the export capability that the government puts in place? Is it a blanket on all crude? Or is it only on certain condensates? Is it on, you know, minimal processing of certain crude where you can -- splitter qualifies or doesn't qualify? It really depends on the details.

But from our perspective, our future is not hinging on whether it's imports are permitted or not permitted. We've got a game plan for either one of them and we benefit from either one. It just probably depends on when they to it as to how it impacts the capital program.

If they wait two years, certain things will get built and you're able to compete at the margin to maintain volumes versus exports. If they do it today, it probably means some of the things don't ever get built, but it allows us to build more infrastructure to out export facilities or refine our plumbing, if you will, to the points that we have.

So again, part of this is to tell our story at PAA. We don't think there's another midstream crude oil entity that's as well-positioned to benefit from almost no matter what happens.

There are certainly certain scenarios where we benefit even more, but having said that we also know that if it looks to too good to be true we'll get a lot of competition in there. Even though we had the best position some people kind of, will wallet-whip us into the market. So this uncertainty probably doesn't hurt us right now.

Noah Lerner, Hartz Capital.

A follow-up question to what Gabe Moreen was talking about with the rail cars. Just curious, with the changes that seem to have been approved so far with potential rerouting and other things other than the retrofitting of the cars, what impact does it have on the profitability of the various rail facilities that you either put in service or are currently building? And does it change your outlook as far as wanting to expand that possibility going forward?

I think if you talk about some of the alternatives that are being discussed like rerouting, slowing down speeds, it probably affects turnaround time. It doesn't affect the locations that we have in general. In fact, if you look at Yorktown versus Philadelphia, it makes Yorktown a more attractive alternative than going directly into Philadelphia. So we like our facility.

There's not as much congestion at Yorktown versus Philadelphia. If you think about it in terms of margin equivalents, Noah, what it probably does -- if you've got, let's say your average cost is $1,000 per car for a lease, and you're calling in the 700-barrel range plus or minus in that car, you're $1.50 if you turn it one time a month, and you're $0.75 a barrel if you turn it two times a month. So if they slow it down wherever you're at in one turn or two turns, it's going to add that incremental cost to the barrel.

If you're like us and you've got scale and scope and the ability to wield to the best markets, and you've got a little bit of volume weight, we're not quite at Walmart, but we're a pretty good sized player in the market. We probably have less adverse impact on us then we could push that cost back to the wellhead or the refinery, depending on how they set it up.

Really, all the rail-loading terminal owners aren't going to be in the same boat. It's really going to impact, sort of, would there be instances where pipelines might make more sense than rail in some areas? And most of the loading areas we have pipeline alternatives, as well as rail. So as Greg mentioned earlier we think we're well-positioned, regardless of what the outcome is.

Okay. And then I think, I guess, the other biggest issue that I saw, or outcome of the recent negotiations, was basically to tighten up the testing and labeling of what goes in the cars, they're saying that things were improperly done up in the Bakken and too volatile of products in cars that couldn't handle them.

Is that going to raise any costs, either operating, or within the facilities themselves as CapEx to adopt and bring those on? Or are you guys pretty much already doing all that so it's really not going to have a material impact to you at all?

Well, first, on the labelling. Whether it's a pack group 1, 2, or 3, it can still go on the same rail car. So while there were some labelling deficiencies, they could have -- it didn't impact the railcar that that product could have moved in. So we are as careful as anyone at trying to properly label the product that goes out on rail cars. We have a testing program at all our facilities.

As far as the cost to retrofit, I think that ties back to the question earlier. What's the retrofit period going to be? Is it going to be a shorter time frame or a reasonable time frame because the shops that can retrofit, there's a limited amount of shops that can retrofit rail cars.

But if I understood your question correctly, your question was, is the incremental testing or the minimum testing that they're going to require going to add to our cost? We already do everything that we need to be doing, probably a step beyond that. So the answer to that question is no.

The question really is, is the rail car issue that Harry mentioned is, is when are they going to -- are they going to grandfather it in or how are they going to phase it in, realizing that if they go the, kind of, the double tanker dual-hold concept. I don't think retrofit works with the existing cars because they're already built to the wide scale, so you really can't add another layer on to it.

Do you see any risk at all out there in the marketplace that they'll curtail the utilization of unit trains for rail, saying it's too much crude in one rail? Better to split it up in smaller batches so it's less hazardous? Or do you think unit trains are pretty solid and here to stay?

Noah, you're talking to me, I see risk everywhere.

That's why I was asking you, Greg.

I do think there is. But again, as long as it's across the board, then it really affects everybody, and I'm going to come back to, I think, the people that have the better scale and the most market flexibility are going to have the best benefit.

If it affects it in such a way that it just makes it uneconomic to move it by rail, remember we've got 18,000 miles of pipeline that we're more than happy to move and expand on. So we're like everybody else. We just want to get it right and we want to do it to make sure we come up with the safest way. But I think our peak forecast for moving crude by rail, John, was it 1.7 million barrels a day total? (Multiple speakers) Peak, over the next four years?

Close, yes.

So, you know, probably in 1.5 million range. That's a huge volume, if you couldn't move that by rail, and right now it's probably in the million barrel range, you can imagine what that would do to the system so it's going to create, Noah, I think, volatility.

But yes, we do see the risk that sometimes there'll be a reaction to do something and mistake motion for action. And it may make illogical sense, but it may be, headline-wise, politically, they might consider it a wise thing to do. But I think it's just, the system still has to work. You still have to balance it. So whatever happens either has to increase cost and get pushed down or decrease volume and it creates price impact on the commodity itself.

James Jampel, HITE.

Crude by rail is certainly an important part of being able to respond to potential dislocations in the crude market. However, how do you know when enough rail capacity is enough? What signals will you be looking for that suggest that rail facilities could be overbuilt given the peak that you see of, what did you say? 1.4 million barrels?

I think, James, it's actually, probably, in certain areas it may well be overbuilt right now on the loading side of it. The unloading is where we're short right now. And so, the loading, I mean, there's already areas where you've got less than fully-utilized facilities in a geographic area.

And in some cases, you may end up with a rail loading facility that was built where it was because somebody had a view for what that area's production in the immediate area was going to do, and you find out that may not be one of the sweet spots, and so another facility not too far down the road but strategically positioned close to a sweet spot within one of these major producing areas is at a much better advantage. So I think your answer is you're going to have that.

Keep in mind that the cost to build the rail loading facilities is -- I won't say it's nominal, but it's not huge, it's, you know, $30 million to $50 million depending upon where you're at. You can go up from there. But, so, it's, that's not going to be hugely fatal there.

The other side of it, though, is that the unloading facilities, which is where we're short right now, and provides the flexibility to get to different markets. There I don't think we're close to being overbuilt at all.

The coast probably has enough capacity. It's hard to see a lot of additional unloading capacity in the Gulf Coast.

When we look at P1, or pad 1 and pad 5, we were really trying to say we backed out all of the medium and light sweet imports. Okay? And it looks like, in particular, in pad 1, that the capacity is consistent with what the original light imports were. Okay? We're still behind the curve out in the West Coast. We just have not gotten the capacity -- the unloading capacity built yet. So it actually feels in P1 and P5 like it's either right at the right level, or a little bit behind the curve in terms of unloading capacity.

The review has said that no more unloading capacity is necessary on the East Coast, but there might be room for Spectra's projects in California.

There's more room in California. Or excuse me, the West Coast. Probably right now up farther north. It feels about right unless we start displacing some of the heavies on the East Coast.

So when you start looking at specific locations on the West Coast, then you have to look at other logistics.

You have the pipeline capacity to move from the rail facility to ripe markets that want the product, and can you get permitted in some locations to develop rail unloading capacity? So I don't think we're really trying to address any one specific project. We're just saying in total, we could add real unloading capacity in the West Coast.

If you unload head rail unloading capacity at a point destination such as a refinery, that's a different way to handicap things, whereas what we're trying to build in California is, we're having an unloading facility built that is the headwaters of our pipeline system that allows us to get into multiple markets.

Because if you think about it, if you're shipping rail into a point destination, just a refinery, and they either find a better alternative crude or they have operational issues that doesn't allow them to continue to unload, you've got excess capacity just because of an operational issue. Where we're trying to build ours in California is at the headwaters of our pipeline so that when we bring it in we can go to three different markets and then distribute it within each of those markets to multiple refineries.

So your rail capital expenditures going forward are focused entirely on California?

No, we have an unloading facility at Bakersfield, which we're developing. We have a small -- a little expansion in Niobrara, a car. We have a little expansion in North Dakota, expanding the facility from 30,000 barrels to -- from 35,000 barrels a day to a full unit train. And then we have one project that we've committed to in Canada. And then another project that we're evaluating in Alberta, Canada.

And James, I would point out that where we're building these incremental loading capacity, we have pipeline alternatives in the neighborhood so we have the ability to swing volumes between it. Because as Noah's question points out, there may be times when, either because of differentials or regulation, that it's not as economic to move it by rail. That means it's more economic to move it on the pipeline.

So if you just had just the loading and that was the only business you had, and they changed the rules on you that's not going to be very fun. The answer is if you have the pipeline and the rail, you have the ability to continue to move the barrels and collect a fee. And you have to view your aggregate investment that way and the aggregate return of the slack capacities, and we do approach it that way.

So I wouldn't give you any comments about anybody else's facilities. We don't know enough about their economics. So, if you're trying to go through the back door to get an opinion on that we'll just close that door. On PAA's we feel comfortable with what we have going forward.

Last one from me, on the NGL side, given the recent volatility there, do you think shippers may be less likely to commit to pipeline solutions and therefore benefiting your NGL rail solutions in a longer-run way?

Our NGL rail is -- they're just small demand centers where there's not pipeline capacity, and you're never going to develop pipeline capacity into some of these areas. So it's small rail unload the trucks to small markets in the upper Midwest.

Do you see any opportunity for rail logistics, you know, operating out of, say, the Marcellus, given the recent volatility in the NGL markets where, perhaps, this product's going to go?

You have so many pipeline projects in the Marcellus. You've got Mariner East, Mariner West, the Kinder Morgan project to go into Sarnia. We've got pipelien that could actually move into Sarnia. You've got a couple pipelines going from the Marcellus and Utica into the Gulf Coast. It's hard to see how rail, really --.

It might be a short-term pressure relief valve issue, but not a long-term solution.

No further questions in queue. Please continue.

That was the call we were looking for.

If there are no other questions we'll go ahead and conclude this call, and we want to thanks everybody for participating, and we'd like to update you in May.

That does conclude your conference for today.

(Operator Instructions)