Plains All American Pipeline LP (PAA) 2013 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the PAA and PNG second quarter results conference call. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session, with instructions being given at that time.

(Operator Instructions)

And as a reminder, today's conference is being recorded. I would now like to turn the conference over to our host, Director of Investor Relations, Roy Lamoreaux. Please go ahead.

Thanks, Paul. Good morning. We welcome you to Plains All American Pipeline, PAA Natural Gas Storage second quarter conference call. The slide presentation for today's call is available on the conference call tab of the Investor Relations sections of our websites at paalp.com and pnglp.com. I would mention that throughout the call, we will refer to the companies by their New York Stock Exchange ticker symbols of PAA and PNG, respectively.

As a reminder, Plains All American owns the 2% general partner interest, all the incentive distribution rights and approximately 61% of the limited partner interests in PNG, which accordingly, is consolidated into PAA's results. In addition to reviewing recent results, we will provide forward-looking comments on the Partnership's outlook for the future. In order to avail ourselves of Safe Harbor concepts, we encourage companies who provide this type of information, we direct you to the risks and warnings that are found in the Partnership's most recent and future filings with the Securities and Exchange Commission. Today's presentation will include references to certain non-GAAP financial measures, such as EBIT and EBITDA. The non-GAAP reconciliation sections of our websites 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 the Partnership's reported financial information.

References to adjusted financial metrics exclude the effect of these selected items. Also for PAA, all references to net income are references to net income attributable to Plains. Today's call will be chaired by Greg L. Armstrong, Chairman and CEO of PAA and PNG. Also participating in the call are Harry Pefanis, President and COO of PAA; Dean Liollio, President of PNG; and Al Swanson, Executive Vice President and Chief Financial Officer of PAA and PNG. In addition to these gentlemen and myself, we have several other members of our management team, present and available for the question-answer session. With that, I'll turn the call over to Greg.

Thanks, Roy. Good morning and welcome to everyone. Yesterday after market close, PAA reported second quarter 2013 results. Second quarter adjusted EBITDA totaled $478 million, which exceeded the midpoint of our guidance range by approximately 10% or $43 million. It is important to note that these results included an approximate $25 million adverse impact to our fee-based results for unforeseen operational issues in Canada that occurred during the second quarter of 2013. Despite the impact of these operational issues on our transportation segment, our second quarter performance overall was essentially right on top of the performance expectations we provided on May 29, which was immediately prior to our Analyst Day.

Compared to last year's second quarter, adjusted EBITDA, adjusted net income and adjusted net income per diluted unit decreased by 8%, 16% and 32%, respectively, primarily as a result of more favorable market conditions we experienced in the second quarter of 2012. The quarter-over-quarter decrease in adjusted EBITDA is composed of a 7% increase in PAA's fee-based businesses and a 30% decrease in the Supply and Logistics segment. Absent the operational issues in the second quarter of 2013, adjusted EBITDA for our fee-based businesses would have increased by approximately 15%. As expected, our supply and logistics results decreased primarily due to narrow crude oil differentials. A summary of our second quarter 2013 results is on slide 3.

As reflected on slide 4, these results mark the 46th consecutive quarter that PAA has delivered results in line with or above guidance. Additionally, for the second quarter of 2013, PAA declared a distribution of $0.5875 per common unit, or $2.35 per unit on an annualized basis. This distribution represents a 10.3% increase over the Partnership's distribution paid in August 2012, and a 2.2% increase over the Partnership's distribution paid in May 2013. Distribution coverage for the quarter was 120%. As reflected on slide 4, PAA has increased its distribution in each of the last 16 quarters, and in 35 out of the last 37 quarters.

Yesterday evening, we also furnished financial and operating guidance for the third quarter and full year of 2013. The midpoint of our 2013 full year adjusted EBITDA guidance of $2.19 billion reflects a $30 million increase over the full year guidance we issued last quarter, primarily as a result of our second quarter overperformance. I think it's worth pointing out that our full year guidance was not adversely impacted by the recent collapse in crude oil basis differentials and the major shift in the crude oil market structure from Contango and Backwardation, as the potential impact of many of those changes were already incorporated into our forward guidance. Before I turn the call over to Harry, let me take a few minutes to address the significant changes in market conditions that have taken place over the last several months, which I believe will help set the stage for Al's and Harry's comments on our future guidance.

Slide 5 contains excerpts from PAA's last three conference calls, which highlight that we have been anticipating that the debottlenecking and infrastructure expansions at PAA and many other crude oil midstream entities have been implemented would be effective at reducing the wide basis differentials and shift in the market from Contango to Backwardation. As these comments indicate, we have been incorporating this outlook into our guidance, as well as our longer-term planning models for quite some time, essentially forecasting that performance from our Supply and Logistics segments would return to baseline levels.

For reference on slide 6, we have included three graphs, showing basis differentials over the last 18 months for WTI and LLS, WTI and Brent, as well as the relationship of both WTI Midland and West Texas Sour to WTI Cushing pricing. As included on slide 6, in the lower right-hand corner, which can be also included is a graph showing the market structure for the [prop] month in the third month for the WTI Futures Contracts over the last nine months. We have noted the dates of each of our last three conference calls to highlight the changes that have taken place over that last nine month period. As a result, the PAA disciplined approach to forecasting results from our Supply and Logistics segment, the recent shift in basis differentials and market structure did not have a material impact on our forward guidance or on our long-term planning models, which are prepared assuming baseline performance.

Despite our cautious approach to forecasting baseline type performance, we do believe that the market will remain volatile. And while the majority of the focus over the last two years has been on geographic or bottleneck related issues, looking forward, we believe that quality related differentials will become more prevalent. We believe those conditions will result in meaningful upside opportunities for PAA from time to time. All that said, it's very difficult to predict the timing of any such future events with any accuracy. However, because PAA is active in substantially all aspects of the midstream crude oil value chain and has a major presence in substantially all the primary producing areas, as well as the demand-driven areas, we believe PAA is well positioned to deliver solid baseline performance in typical markets, and above baseline performance in attractive markets.

During the remainder of today's call, we will discuss the specifics of PAA 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. We will also address similar information for PNG. At the end of the call, I'll provide a brief recap, as well as some comments regarding our outlook for the future. With that, I'll turn the call over to Harry.

Thanks, Greg. During my section of the call, I'll review our second quarter operating results compared to the midpoint of our guidance, the operational assumptions used to generate our third quarter guidance, as well as provide an update on our capital program and acquisition activities. As shown on slide 7, Transportation adjusted segment profit was $167 million, $18 million below the midpoint of our guidance. Volumes of 3.6 million barrels per day, or approximately 80,000 barrels per day below the midpoint of our guidance. Adjusted segment profit per barrels was $0.51 or $0.04 below our midpoint guidance.

The quarter was adversely impacted by approximately $25 million in two events. First, as a precautionary measure, we shut down certain pipeline segments in Western Canada, due to the high flow rates at water crossings, which caused revenues to be lower than forecasted. I'll note that we are replacing some of these water crossings, and these pipeline segments will continue to be out of service for portions of the balance of 2013. The impact of the second half of the year is estimated to be approximately $15 million, which has been taken into account in our guidance. Secondly, our operating costs were higher than anticipated, due to response from remediation efforts related to pipeline releases on our Kemp River pipeline in Northern Alberta.

Adjusted segment profit for the Facility segment was $153 million, $13 million above the midpoint of our guidance. Volume of 121 million barrels of oil equivalent per month was in line with the midpoint of our guidance, and adjusted segment profit per barrel was $0.42 or $0.04 above the midpoint of our guidance. Overperformance in this segment was primarily driven by processing gains at our Fort Saskatchewan facility and overperformance at PNG.

Adjusted segment profit for the Supply and Logistics segment was $154 million, $45 million above the midpoint of our guidance. Volumes of approximately 1 million barrels per day were in line with the midpoint of our guidance, and adjusted segment profit per barrel was $1.66 or $0.47 above the midpoint of our guidance. Overperformance in this segment was primarily due to higher NGL margins and favorable crude oil market conditions, particularly among various crude oil grade differentials in Canada. Maintenance capital expenditures for the first half of 2013 were $82 million, and we expect total 2013 maintenance capital expenditures to range between $175 million and $195 million.

Let me now move on to slide 8 and review the operational assumptions used to generate our third quarter 2013 guidance released yesterday. For the Transportation segment, we expect adjusted segment profit to be $204 million, volumes to be 3.76 million barrels per day, and adjusted segment profit to be $0.59 per barrel. Our third quarter Transportation guidance includes the benefit of capital projects coming into service, continued production growth in the Eagle Ford and Permian Basin areas, and the increase in the FERC Index, which became effective July 1 of this year. Our guidance also reflects the fact that we've sold the New Mexico refined product system, effective July 1 of this year.

For the Facilities segment, we expect adjusted segment profit to be $135 million, capacity to average 122 million barrels of oil equivalent per month and adjusted segment profit to be $0.37 per barrel. When compared to the second quarter, our third quarter forecast is lower, due to the timing of integrity expenses and seasonally lower net revenues from PNG.

For the Supply and Logistics segment, we expect adjusted segment profit to be $90 million, volumes to be approximately 1 million barrels per day and adjusted segment profit to be $0.99 per barrel. Although we continue to expect robust supply growth in North America, as Greg mentioned, recent supply capacity additions have narrowed crude oil price differentials. Our assumption for the quarter is that these differentials will remain compressed, relative to the last year or so.

I'll now move on to review our capital program, which is shown on slide 9. I note that primarily as a result of new projects and expansions of existing projects, we have increased our 2013 capital program by $200 million to $1.6 billion. Also, as a result of carryover activity, we expect to incur approximately $1.1 billion of capital, attributable to these approved projects in 2014 and beyond.

Slide 10 provides an update on the expected in service timing of some of our larger approved projects. I'll provide a quick update on some of these larger projects now. In the Eagle Ford, our joint venture pipeline from Gardendale to Corpus Christi is in service, and we expect to complete the connection to our dock facility and the pipeline expansion -- extension to Enterprise's line near [La Salle] in September. In the Permian Basin, we've completed several of our expansion projects, adding approximately 200,000 barrels a day of capacity to our gathering systems, and increasing flexibility by adding connections to the Longhorn pipeline at Crane and the Permian Express Pipeline at Wichita Falls. This still is very active area, and we have a number of new expansion projects underway. We're also advancing our recently announced Cactus pipeline and are targeting to have that line in service in early 2015.

In the Mid-Continent, Phase 1 of our Mississippian Lime pipeline was placed into service on August 1, and the Phase 2 extension to Coldwater, Kansas is expected to be in service in the fourth quarter of this year. Additionally, our Western Oklahoma extension is on schedule to be in service by the end of the first quarter 2014.

In Canada, we expect our Rainbow II diluent pipeline to be in service next month. This line will move diluent from Edmonton to Nipisi to the growing crude oil production in the Peace River area. As discussed at our analyst meeting, we're also advancing several growth projects at our Fort Saskatchewan facility, including the development of three additional propane caverns and the conversion of two of our larger existing caverns from propane service to condensate service. And then lastly, we had positive non-binding responses to our western region open season, and are continuing to advance discussions with interested parties.

Now, with regard to our rail expansions, the timing and capacity of our rail projects are shown on slide 7. Weather and permitting delays have caused -- weather and permitting caused delays relating to our in service dates related to both Yorktown and Tampa facilities. However, we expect both of these facilities to be in service in October. Expanding on some of Greg's earlier comments, I'd note that differentials on some grades of crude oil have made rail economics a little more difficult. However, third-party throughput commitments and the scale and scope of PAA's asset base and the structure of our business model provides us with a counterbalance for fluctuating rail volumes. As volumes move off rail, in many cases we see an uptick in volumes on some of our pipeline systems.

And before I move on, I would note that we're continuing to advance a multi-billion dollar project portfolio. Of course, not all these projects will come to fruition, but the opportunity set is very large. And at this point, we expect our 2014 capital program to be in the $1.3 billion to $1.5 billion range. Lastly, we completed the sale of our New Mexico products pipeline system, effective July 1. We are targeting the completion of the sale of our Rocky Mountain products pipeline system, subject to FTC approval, by the end of the third quarter. And I'll also note that we do not have any acquisitions during this quarter. With that, I'll turn the call over to Dean to discuss PNG's operating and financial results.

Thanks, Harry. In my part of the call, I will review PNG's second quarter 2013 operating and financial results, our financial position as of June 30, 2013, and our financing activities. I will also provide an update on PNG's capital program, discuss current market conditions, and review our third quarter and full year 2013 guidance. Let me begin by discussing the results we released yesterday.

As shown on slide 12, PNG reported second quarter adjusted EBITDA of $30.6 million, exceeding the midpoint of our guidance range by $4.1 million or 15%. This marks the twelfth consecutive quarter that PNG has delivered results in line with or above guidance. Our results were underpinned by our fee-based firm storage contract, with overperformance driven by acceleration of margins associated with merchant storage revenues previously expected later in the year, as well as higher than forecasted oil revenues associated with liquids removal activities at Bluewater. Compared to last year's second quarter, adjusted EBITDA increased 3%, adjusted net income decreased 3%, and adjusted net income per diluted unit decreased 4%. With respect to distributions for the second quarter of 2013, we declared a quarterly distribution of $0.3575 or $1.43 per unit on an annualized basis. This was equal to last quarter's distribution.

Financially, PNG's midyear credit metrics are solid. As shown on slide 13, as of June 30, 2013, PNG had a long-term debt to capitalization ratio of 28%, adjusted EBITDA to interest coverage of 11.2 times, a long-term debt to adjusted EBITDA ratio of 3.9 times, and $204 million of committed liquidity. Additionally, in the second quarter of 2013, PNG sold 1.4 million units through the Partnership's continuous equity offering program, raising approximately $30 million of equity capital. This amount includes the general partner's proportionate capital contribution. As mentioned on our previous conference call, we believe this program is the most cost-efficient and least disruptive way to raise equity funding for our ongoing capital investment and fine-tune our liquidity, balance sheet and credit metrics.

Operationally, we are on budget and on schedule with our 2013 cavern expansion activities, which are expected to total approximately 8 Bcf of incremental capacity, approximately one-half of which was placed into service in April. Before I discuss guidance, I want to first share some observations on market conditions for natural gas storage, to put PNG's performance to date and our outlook for the balance of 2013 in perspective. Over the last few months, seasonal spreads, which are a proxy for the intrinsic value of storage, have been pretty uninspiring, as they range between $0.27 and $0.35 and set new ten-year lows for this time of year. In addition, volatility levels, which have a meaningful impact on the value we are able to realize on a short-term basis from our hub service and merchant storage activity, have also been fairly anemic. Slide 14 illustrates these observations.

Fortunately, due to our highly contracted portfolio and the defensive posture we adopted some time back as market conditions eroded, these weakened conditions have not had a material adverse impact on our results thus far in 2013, or on our outlook for the balance of the year. As shown on slide 15, the midpoint of our full year adjusted EBITDA guidance, which we established at the beginning of the year, remains at $120 million. And we are forecasting midpoint adjusted EBITDA of $26.5 million and $31.4 million for the third quarter and fourth quarter, respectively. Depending on the realization of certain of our merchant activities, there could be some shifting of results between these two quarters. We expect distributable cash flow of $107.9 million for the full year of 2013.

Consistent with our discussions of guidance on our February conference call, due to the seasonality of our business, we project distribution coverage for the third quarter to dip below one-to-one on distributable cash flow of $23.6 million, while distribution coverage for the full year 2013 is forecasted at right around one-to-one. For more detailed information on our 2013 guidance, please refer to the Form 8-K that we furnished yesterday evening. As we have indicated in prior conference calls, and at our recent Analyst Day, we remain optimistic about the intermediate to long term outlook for natural gas storage. However, looking out at the future's curve, the seasonal spreads for the next few years reflect a directionally similar picture to those we are experiencing in 2013.

While it is early to attempt to reliably predict market conditions for 2014 and associated impacts on our projected 2014 performance, should current market conditions persist, they will likely have a negative impact on our 2014 outlook, relative to our 2013 guidance. Consistent with past practice, we plan to provide preliminary 2014 guidance in conjunction with our third quarter conference call in November. On balance, we are pleased with the performance that our assets and our teams are positioned to deliver for 2013 during challenging market conditions, and believe we are as well positioned as anyone in the industry to address the challenges and opportunities the future holds for natural gas storage. With that, I'll turn it over to Al.

Thanks, Dean. During my portion of the call, I will review our financing activities, our capitalization and liquidity, as well as our guidance for the third quarter and full year of 2013. Our financing activities this quarter were limited to our continuous equity offering program. PAA sold approximately 3.5 million units in the second quarter, raising approximately $200 million in equity capital. This amount includes the general partner's proportionate capital contribution. We are very pleased with this program, as the cost is attractive, execution is much less disruptive on the trading of PAA's units compared to the traditional overnight or one day market offerings, and its scalability enables us to increase or decrease the activity levels based on a variety of factors, including our expected needs, as well as overall market conditions.

As illustrated on slide 16, PAA ended the second quarter with strong capitalization and credit metrics that are favorable to our targets. At June 30, 2013, PAA had a long-term debt to capitalization ratio of 45%, a long-term debt to adjusted EBITDA ratio of 2.9 times, and adjusted EBITDA to interest coverage ratio of 6.4 times. Our committed liquidity at the end of the quarter was approximately $2.6 billion. Slide 17 compares PAA's scale and credit profile against PAA's MLP peers that have a credit rating at or above PAA's current rating level. Slide 18 summarizes information regarding our short-term debt, hedged inventory and linefill at quarter end.

Moving onto PAA's guidance. As summarized on slide 19, we are forecasting midpoint adjusted EBITDA of $430 million, and $2.19 billion for the third quarter and full year of 2013, respectively. As Greg and Harry both mentioned, our guidance for the second half of the year assumes less robust market conditions than we experienced in 2012 and in the first half of 2013. This specifically impacts guidance furnished for our Supply and Logistics segment, where we have assumed baseline profitability for the remainder of the year. Our second half 2013 guidance for the Transportation and Facilities segment has been reduced slightly, primarily as a result of a shift in timing of operating expenses, completion timing of certain capital products and some lingering effects of the Canadian floods. For more information, detailed information on our 2013 guidance, please refer to the Form 8-K that we furnished yesterday.

As represented on slide 20, based on the midpoint of our 2013 guidance for implied DCF and distributions to be paid throughout the year, our distribution coverage is forecast to be approximately 135%. This equates to PAA generating and reinvesting approximately $400 million of cash flow in excess of distributions in 2013. Given our strong capitalization at quarter end, proceeds from the refined products, pipeline sales and our projection for retained DCF for the balance of the year, we have funded the equity capital needs associated with our $1.6 billion 2013 expansion capital program, as well as a fair portion of our 2014 capital program. Given our visibility for 2014's preliminary capital plan and the potential for it to increase, we intend to continue to access the continuous equity offering program to prefund our equity needs, as well as position for potential acquisition activity. Accordingly, absent significant acquisition activity, we do not expect to execute an overnight or marketed equity offering due in 2013 or 2014. With that, I'll turn the call over to Greg.

Thanks, Al. The first half of 2013 has been a very active and very productive period for PAA, and we are pleased with our positioning for the remainder of the year and beyond. As discussed in detail during our analyst meeting at the end of May, PAA's significant asset presence in substantially all of the major North American crude oil resource plays positions the Partnership to meaningfully benefit from continued increases in crude production. The Partnership's proven business model, multi-billion dollar organic project portfolio and solid capital structure provides strong visibility for continued, attractive, multi-year distribution growth, without relying on potential acquisitions. That said, we believe all of these characteristics position PAA to capitalize on attractive acquisitions, especially if the industry or the capital markets weaken.

Prior to opening the call for questions, I would note that late last month, our general partner filed an S-1 registration statement with the Securities and Exchange Commission, with respect to a planned public offering of equity ownership in our general partner. Due to the regulatory restrictions involved with this process, we will not be able to answer any questions related to this filing, but would note that all 400 pages of which are available on the SEC website. We thank you for participating in today's call, for your investment in PAA and PNG. We are excited about our prospects for the future and look forward to updating you on our activities on our next call in November. Paul, at this point in time, we're ready to open the call up for questions.

(Operator Instructions)

Steve Sherowski, of Goldman Sachs.

Just trying to drill down a little bit on your preliminary 2014 CapEx forecast, the $1.3 billion to $1.5 billion. Is there any detail you can provide, by segment? And of this spending, can you characterize how much of these projects are going to come online next year, versus 2015 and beyond?

Steve, I can address parts of it, and I can direct you to some of the detail. First off, 99% of the capital is dedicated to both the Facilities and the Transportation segment, so it's substantially all fee-based activity. Second, if you'll kind of look at the two slides -- we change one of our slides that we had this year. If you look at the slide on the capital program, we provide the detail for the $1.6 billion that we're spending in 2013.

But the pie chart on the right actually reflects the total, roughly $3.6 billion, that is being spent on those activities. So we broke that down on this call because we did have some insight into what it's looking like for '14. You can see roughly $900 million of that is prior projects, spent prior to '13. $1.6 billion is in '13, and then $1.1 billion is carryover into 2014. And so, we did break it down by regions into the different areas. I'm sorry, what? Say what?

Yes. The $1.1 billion is 2014 and future.

And future I should say, but the preponderance of it is in '14. So when you look at that slide, in connection with the other slide where we showed the timeline for bringing those into service, you can kind of get a feel, I think, directionally for what you're looking for. I would point out that unique among our projects, again, they're smaller projects, but in somewhat integrated activities. But we're able to bring some of the cash flows on in sequence. So you'll see multiple check marks on some of the lines, because we're able to bring some of the revenue generated activities on earlier, while we're still working on other aspects of it.

Okay. Thanks.

I think slide 10 will you give you an idea of the in service dates, too.

Okay. Great. That's helpful, but just a quick follow up. Your S&L guidance implies a little bit of seasonality during the second half of the year. I was wondering, is this a reflection of more of a return to baseline earnings for the business? Or is there anything else going on?

Certainly, the baseline and the seasonality--if we did not have the favorable market conditions, and there's always been periods of time where it happens. It just happens at different times of the year sometimes. You would still see, in a typical baseline S&L forecast, a bit of a saddle. It'll start out--the first quarter and the fourth quarter are always our strongest quarters in a baseline condition. And then, obviously, it falls off a little bit in the second and the third quarter. So part of the ramp up that you're seeing in the fourth quarter is not that number times four to get you to an annualized number. It's really the effect of seasonality, especially in our NGL activity.

Got you. Understood. That's it for me. Thank you very much.

Brian Zarahn, from Barclays.

On the increased 2013 expansion CapEx, can you give a little color as to what projects drove the increase?

What projects drove the increase? Yes, we had a handful -- there are a lot of projects -- a handful of projects in West Texas that really drove most of the increase. It's a -- and a couple other expansion projects that probably a little premature to give the details on, right now.

But for example, I think we started off beginning of the year, the Mississippian Lime, we had one pin in Oklahoma. We had a project in there -- we later on announced that we had an extension on that. So that added to it. We added the Cactus project to it, a portion of that will be spent this year. The preponderance will be spent in the next year. So it's really no any one project. It's just the cumulative effect of a lot of activity.

Okay. So it's more the addition of projects, not cost escalation on existing projects.

No. I'd say cost escalations are, at this point in time, minor and manageable. Most of the time, they're within kind of the scope of what we had out there. That we certainly have had some incremental cost, associated with timing delays. So for example, if we're paying for crude out there, and right away, you're trying to stay ahead of everything. But sometimes, the crudes catch up with your right-of-way permitting.

But, in general, I would say, on balance, we've got a number of projects. $1.6 billion, we've probably got 100 projects. The largest one of which, I think, is probably in the $170 million range. But if you look at it on individual-by-individual, we've got some that are up and down. Overall, they've kind of on a cost expectation level, netted to probably up 3% or 4% overall. So it's some creep, but not much.

Brian, I'll give a little more detail also. Probably the largest single one is the Fort Sask facilities that I mentioned in my portion of the call. We also have an expansion of some of our gas processing assets in the Gulf Coast. So those two probably make up 50% to 60% of the growth. There is a little bit of cost increases in there, primarily with some of the rail facilities. But -- and then, a couple, I've said earlier, a couple expansion projects in West Texas.

That's helpful. I guess, turning to rail. Can you give a little more color as to the impact of narrower price differentials? And maybe, can you maybe frame how much of your -- give a rough idea of how much capacity you have that's protected by throughput commitments?

Really, the differentials impact Supply and Logistics segment a lot more than the rail facilities. It's just a narrowing of the differentials that both Greg and I have mentioned, which makes it a little more challenging. But the rail facilities, they're actually performing at the levels that we had anticipated. It's a combination -- I'll have to get back with you exactly on how much of it's contracted, but a good portion of our existing capacity is contracted.

For example, the facility we're bringing up in Tampa is substantially under contract, and those are fixed fees on the facility side of it. So again, where you're seeing the swing is to the extent we're actually participating by actually merchanting crude. Our margins, they are getting hit and they're reflected in the outlook for the Supply and Logistics guidance that we've given you.

Final one for me, also on rail. Probably a little early, but any anticipated impact from a cost perspective from the Quebec derailment on crude by rail potentially higher? Maybe retrofitting tanks for safety? Or was this more of just an unfortunate incident?

I don't think it's going to impact any of our assets. It may impact the rail infrastructure, itself. But I can't see it impacting our terminals or our loading and unloading facilities.

I think the jury's still out on all the issues on that one. It is an unfortunate accident. But I think the way the rail companies manage their assets, it may be affected more so than the shippers.

Or in terms of your Bakersfield project -- I'm not sure that's permitted yet. Would that -- could this potentially have a potential delay on permitting?

No. Bakersfield's already permitted. We've started construction. It will be in service-- For first quarter of 2014. And just getting back, just as a measuring stick on the percentage contracted, the USD acquisition, which we completed last year, about 75% of that capacity was contracted long-term.

And then, here in Tampa, how much is contracted?

Tampa's fully contracted.

Thank you.

Michael Blum, from Wells Fargo.

A couple questions for me. One, so your guidance obviously assumes locational spreads are down, and Supply and Logistics is more at a baseline level. When do you expect the quality differential you've been talking about recently at your analyst meetings? When do expect those to start to materialize in a significant way, that you might start seeing again a pick up in outperformance in the Supply and Logistics segment?

Well, part of the reason that we don't forecast, because we don't know when to tell you how that's going to happen. But I'd say within the time period. It's certainly within the next 12 to 18 months. And I think it'll show up through a combination of just as the volume builds and the refiners start to push back, when they're trying to balance their sources of supply, relative to refining efficiency and alternative cost. And I think you'll really see it show up when there's any kind of operational upset, if a refinery goes into turnaround and you start having to back a particular type of crude, as well as the volume, it can cause -- it can exacerbate what is already been a very volatile type of environment. So it's just one more variable in the normal equation, on an operational standpoint.

And then, over again, the next 12 to 18 months, if you just look at the forecast -- and I'm going back to our Analyst Day -- that we showed -- we expect volumes or quality issues to start showing up on a regional basis, where you're just going to end up with you're short volume of crude, but you're long in a particular quality of crude. Part of the reason for us building Cactus pipeline is to help balance that market. But again, we haven't -- construction never exactly goes hand-in-hand with your expected timing, with respect to trying to balance those markets. So I'd say, if you're looking for a time window, it's in that 12 to 18 month period.

Okay. Great. And then, my second question was just want to clarify your comments on rail versus pipe. I guess, are you saying that with spreads coming in and some of that volume moving off of rail onto pipe, from a PAA enterprise perspective, you're agnostic because you're capturing it one way or the other? Or are you just saying that because of commercial capability you have with your Supply and Logistics segment, you're able to effectively base load your own rail assets with volumes. So even though spreads are coming in, you're not as impacted as you expect?

Yes, not to be too cute, but the answer to your question is yes, on the either-or. For example, as we start to see certain rail economics, especially not only for PAA, but some of our competitors in the rail market, as those volumes start to back off the rail, they're going to go back, in some cases, on pipeline. If you recall, there was a period of time, probably 18 months ago, when all the pipelines out of the Bakken were full. There's a lot of excess capacity in those pipelines today, and we happen to own interest in some of those pipelines. So we're going to see some of those volumes shift back over to pipelines, such as Butte and other ones that we manage.

Manitou in Canada, [Koch] systems in --

Right. So you're going to see some of that show back up on the pipeline side of it. So I won't say we are agnostic, but we're certainly well-positioned, if not hedged. And then, in addition, because we look at the total value chain of not only the absolute cost to a third party, but also our variable cost, our S&L may have the ability to take up some of that excess capacity on our rail assets, loading, unloading, and rail cars and terminals to be able to basically carve out a margin where somebody that's only involved in one part of that value chain may not have that flexibility.

Okay. Great. Thank you, Greg.

Cory Garcia, of Raymond James.

I appreciate all the color, as usual. Kind of digging through your back half guidance for the year. Completely understand the S&L segment income drop-off, given the base differential outlook. But I was noticing that trucking volumes and just overall crude lease gathering is starting to flatline a bit. Hoping you guys can provide maybe a little color into what's underlying that trend. Are you guys actually capacity constrained? Is it the fact that pipeline gathering is actually starting to play catch up in areas like in the Permian? Or is it just simply competitive trucking pressure in some of these areas?

Trucking, that you see included in the Transportation segment, is really with respect to our Canadian activities. It's not reflective of the gathering business. Now in the US, in the gathering business, we are definitely seeing more volume get on the pipes, less on the trucks. We typically complement our asset base with use of third parties. So as those more temporary volumes are lowered, we back away from third-party providers. In Canada, it's really just a reflection of how much crude goes to rail, versus staying on the pipe. But it's mainly just a small volume that's impacted. It is really third-party business.

But, I think, Cory, you're correct to laser in on the fact that in the US, for example, as we build out some of the additional pipe that we're bringing online in the Eagle Ford, et cetera, that's the intent of it. We get it off the truck and onto the pipelines. And then, as Harry mentioned, we tend to manage then, our trucking fleet by having third-party vehicles that we're able to then back out of our system to keep ours active. So it's all about margin management. In some cases, the volumes that you see going down may have limited margin associated with them.

But overall, there's -- we talked about this, I think, probably about four or five quarters ago -- that as we bring on some of our systems, we'll be taking some of the margin away from our Supply and Logistics, and putting it over in Transportation. On a per barrel basis, the margins are actually a little bit slimmer on the transportation than they are on the gathering side. But we also fully acknowledge that if we don't do that, somebody else is going to build it. So it's all about managing the entire business over an extended period of time. And that was built into our long-term planning model.

Our volumes are trending up slightly in the lease gathering business. Third quarter is slightly over second quarter. Fourth quarter is about 20,000 barrels a day over the third quarter.

We're still seeing the fundamental growth in each of these areas that we're anticipating, in terms of drilling activity by producers.

That makes perfect sense. Appreciate the color, guys.

Mark Reichman, of Simmons.

I just have two questions. First, referencing the Contango Backwardation slide on page six of the presentation, I was wondering if you could discuss your expectations regarding the relationship between crude oil inventories at Cushing and the spread between the WTI crude oil futures. Clearly, you can see the market's become more heavily backwardated into the third quarter. So what are your expectations for Cushing inventories to forward curve and how that factors into your margin expectations for the balance of the year?

And Mark, I want to -- not trying to be too evasive, but we certainly don't want to turn our playbook over to all of our competitors. I would say the results of our views are reflected into our Supply and Logistics outlook. But clearly, we were willing to speak about it before we ran a pronounced Contango, and it was clear that we were seeing as the pipes freed up the bottleneck that existed in Cushing, we fully expected to see a situation where those tanks would at least get bled down or you'd have free access to the Gulf Coast, and we did see that. I would say that I think it would be wrong to assume that we're in permanent Backwardation, because there's a lot of activity going on in some projects that are announced, and there's several projects that haven't been announced that we're aware of work that will change the dynamics of that. So I think it's going to be volatile.

But for right now, clearly, we've got excess capacity right now. Additional capacity coming on, I should say, with the Keystone activation that should at least take away a lot of the pressure that forced it into the steep Contango that it was before. But I think you'll end up seeing -- we're talking about really pure market structure, where you've got WTI on a forward curve. Clear -- keep in mind, there's 100 different grades and varieties of crude that are really pushed through Cushing. And so you may end up where the market structure for WTI may be in Backwardation, but you actually may have certain grades of crude in Cushing that are in Contango. So it's a little more complex than it appears, and quite candidly, we like it that way.

And then second, could you just discuss in a little more detail your activities in Canada, just by providing an update on some of the projects, including Western region. And also, would you expect Canada's share of PAA's overall CapEx budget to grow? And if so, what opportunities are you seeing beyond those that you discussed at the analyst conference?

Well, beyond what we've said at the analyst conference and today, we can't really provide more color. I would say clearly, we've been very pleased with the level of capital projects that we've been able to develop through the integration of the acquisition of the BP assets with our existing activities up there. Harry's reference to Fort Sask and the key asset base that we have there, and a lot of the projects that we've added that are in the capital budget, that certainly by all means, not all of what we have out there. We're still working on several projects.

As far as the percentage relationship, that ebbs and flows. To some extent, for whatever reason, since we first got into Canada in 2001, the relationship has been kind of the same over the years. It may move a couple of percentage points. I would probably say, right now though, we're certainly expecting overall capital activity to pick up in Canada, relative to historical levels. But when you look at it on balance with what it's picking up in US on our capital activity, I'd say it's not a material change in the percentage composition at all.

And then, on Western region. It's not a whole lot more to say there, but -- except the comments, we had positive interest. They were non-binding. Okay. So there's enough interest for us to continue to advance discussions, regard it. And just the growth in the NGL volumes in Canada, they're going to drive the pipeline project and they're going to drive these expansions at Fort Sask. And we feel very comfortable with the expansion opportunity at Fort Sask. New projects like the Western region is going to require customer support, producer support, before we're able to finalize that type of an expansion.

Okay. Great. Thank you. I appreciate that.

Bradley Olsen, with Tudor Pickering.

You all did a very good job of forecasting the moderation in differentials. But the Backwardation we've seen, combined with strength in LLS and ANS in relation to Brent, it all seems kind of like a blast from 2007 or 2008. Do think that the current market dynamics persist long-term? And more specifically, is saturation in the Gulf Coast LLS market potentially the catalyst that brings the domestic market back to earth and moves the overall market back into Contango?

Great question. I'd probably say, in terms of -- again, we've used a pressure cooker analogy around here. If you can envision a boiling pot, with a lid sitting on it. Every once in a while, you see a steam vent escape, and every once in a while, the top may blow off, and trying to predict that is pretty challenging. I think what we tried to do, instead of predicting what and when, is prepare for everything, both from our capital structure to our asset base and our positioning. So we are not going to share any predictions. As much as we think we can basically tell you, almost no matter what happens, PAA will be in a position to capture some of those opportunities. And in certain situations, I think we can capture more than our fair share.

Great. And with Pioneer talking about potentially having found 500 million barrels of oil in the Wolfcamp alone, this is probably a pretty easy one. But do you see your opportunity set around the Basin and Mesa assets, as well as around the gathering assets, as increasing with that?

I wouldn't trade our position out there with anybody.

That Permian Basin is so active. It's hard to keep ahead of the infrastructure out there. We've been pretty proactive in the area, developing some of the infrastructure upfront. But the producers are doing a pretty good job of keeping the pipes full.

Great. Thanks. As far as the persistent strength we've seen in the LLS market, any -- you're obviously exposed to that in a variety of ways. Storage, rail, et cetera. How does the strength in the LLS market impact your future development plans around St. James? Does it make you potentially incrementally more bullish on rail, even with the proposed pipeline projects into the area?

I think rail's going to be a permanent part of the logistical answer in the US. And what we've really tried to do, Brad, is put ourselves in a position where we can -- we have a network of rail assets where we can move rail to various locations. The areas we think you're going to see movement through are Gulf Coast, East Coast and West Coast. So we've developed our unloading facilities there, and then we think the Niobrara, the Bakken, and the Canadian are going to be looking for outlets in addition to pipe. There's not going to be enough pipe to handle all the volumes in those areas. It's not going to make sense to develop pipeline solutions for all that production. So overall, we're very -- we like the asset position we have in the rail segment. There's going to be some ups and downs, if you can look at individual facilities. But overall, we are certainly expect to generate the types of returns we forecasted when we got into the rail infrastructure business.

Two other issues, Brad, I mentioned is one embedded in Harry's answer. Is not only the volumetric issues about the [more build] pipe to relieve all the pressure in an area, is the quality issue and the ability to take the right quality crude to the right area. In some cases, just like we've seen before, where you have certain crude oil moving one direction on the pipeline and another type of crude oil moving the other direction on the pipeline, you're going to see the same thing happen, with respect to rail.

And then finally, I just point out that, again, I get back to PAA's integrated system. We can provide the producers with more flexibility. They probably today have figured out they don't want 100% commitment to any one pipeline or any one avenue out of town, be it rail or pipeline. What they really want to know is who can get me to the best markets, wherever that market is? That's why I think PAA's investment in rail combined with pipeline, combined with terminals, combined with our ability to merchant on the Supply and Logistics, and provide the blending services to actually help improve the quality of crude, not only for the producers, but the refiners, is, I just think it's unparalleled in the business right now.

Just add one other comment. We try to locate our facilities on the market side, on the unloading side, where we have access to multiple markets, not just one refiner. And likewise on the supply side. We try to situate our loading facilities in areas where we can aggregate crude from a number of different sources. So not particularly tied to one producer or one refiner on the loading or unloading side, but tied to market fundamentals.

Great. Just two questions that are more operational in nature. As we think about Capline utilization, in light of on one hand, strong LLS pricing, but on the other hand, increased utilization at the BP Whiting refinery. How has Capline utilization moved around in the last quarter? And then, finally, is there a significant benefit to the Facilities segment from higher utilization, as storage turns increase during the steep Backwardation that we've seen?

Let me take Capline first. Capline is a pipeline that is -- actually, it operates like it's three different pipelines within the same pipeline. So BP owns an interest in Capline. So anything that goes to Whiting is going to be on the BP space. It doesn't necessarily impact our lines. Our lines have actually been pretty steady through the year, and forecasting steady through the remainder of 2013. So we're not really expecting BP's activity or most of the other interest owners' activity at the refineries to impact our capacity on Capline.

And then, with respect to Backwardation of the facilities, it depends on -- it's sort of varies by facility. Obviously, at Cushing you're seeing quite a bit of volume decline. And a lot of that does translate into additional throughput business at our terminal at Cushing. But what I would distinguish our facility from most, from some of the other facilities at Cushing, it really was designed as an operational facility to start with. It really wasn't designed as a Contango storage facility. We like seeing the higher volumes. We like thing the different crudes coming in. It does add incremental activity at our terminal.

Great. Thanks.

Ethan Bellamy, from Baird.

Two questions. First, on gas storage. What's the -- I'm probably going to ask this every call until we see something, but what's the outlook for M&A?

Ethan, it's pretty flat right now. I think most out there have chosen to weather through this period near term. I don't -- at least right now, don't see it any activity and probably not picking up until we start to see a recovery.

Okay. Thanks, Dean. And with respect to the maintenance CapEx at PNG, there's basically none in the guidance, or de minimis. Where should that number normalize over say, a three to five year period?

About $600,000 a year.

Okay. And then, Greg, big picture. It looks like Mexico might -- had the chance to change their constitution, which could turnaround oil and gas development there. Are there any direct or indirect opportunities for you in Mexico? And what would you expect the impact of potentially increased crude supplies coming out of Mexico, do to the Northern American market as a whole?

Well, the latter part, I'd probably just add one more variable of volatility to it, which is not unwelcome. It's pretty early to be trying to predict what impact anything they might do in Mexico would have on either our opportunity set. I will say that when we acquired Velocity, which is now our Gardendale gathering system, we basically are well-positioned, I think better positioned than anybody else, to service volumes across the border. The Eagle Ford doesn't stop at the international border. Clearly, there's not activity going on the other side, and we would be the best market to be able to handle any development over there.

So I'd say, there's -- it's potential upside if they do encourage active investment, because again, clearly the Eagle Ford is one of the best plays out there that we're aware of. So I think we're well-positioned to see some benefit, just in that one isolated area. As far as kind of a big picture question, as to what role we'd play in Mexico, it depends on what part of Mexico it is and really what happens. But safety for our people will be number one. And right now, it's kind of scary down that part of the country. So I'd just as soon send it to us by pipeline, and we'll take care of it.

Just one idea for you. Next Analyst Day, Cabo.

(laughter) There's a long story there, but Harry kind of voted against that. (laughter)

Thanks, guys.

Shneur Gershuni from UBS Securities.

Don't want to beat a dead horse here, but I was just wondering if we can just return to the S&L guidance that you've presented. You mentioned in the past that you're expecting margins to contract and so forth, and sort of expect to return to baseline levels. I was wondering if you could sort of remind us what baseline levels are, and what the variability would be with respect to seasonality? Is the number that you're guiding for 3Q basically the bottom of a typical range? And what would be the high end and so forth? I was wondering if you could give us color around that.

Al, you want to weigh in?

Yes, what I would tell you is that what you're seeing for third quarter is pretty representative of a baseline environment for third quarter, and the same for our fourth quarter. And there's a pretty meaningful amount of seasonality, as Greg and Harry mentioned earlier, between the summer quarters and the two winter quarters. What you've seen is just a slight uptick in second half forecast versus what we forecast last time. But our numbers are effectively on a baseline forecast than what you're looking at.

Yes, I would -- if you're looking for a neighborhood of what the annualized -- not annualized -- an annual number would be, we're probably in the 500 to 525, maybe 550 of what we would call a baseline type S&L margin. Over time, that number could actually creep up as we expand our asset base and we have continued growth in the resource base that we service. I think it's not necessarily a stagnant number. Now there's other variables in the equation, like competition, et cetera, that we really can't factor in. But we've been running here recently in the $800 million a year range, and again, we would have guided you back and said baseline is probably -- if you look at the relative overperformance versus our beginning of the year guidance, in most cases, that's going to put you in an adjusted number in that $500 million range.

Again, as we expand the asset base, I think you see that number creep up a little bit. If you're trying to break that 500 number down, and I think we're showing this year for third quarter, what?[$4 million]? Effectively assume the second and the third quarter kind of in the same neighborhood, then the first and the fourth quarter will make up the difference on that. So you're effectively looking at -- again, these are very round numbers -- call it neighborhood of $150 million a quarter in the first and the fourth, and $100 million a quarter in the second and the third. And again, intending to have those numbers be round. Does that help?

Yes, it definitely does. Definitely appreciate that. Just one last quick follow up. You sort of mention at the beginning of your prepared remarks about some challenges in the fee-based results during the quarter. I was wondering if you can expand on that a little bit? Is the impact completely just volume related? Are the volumes high margin volumes, or is it sort of a temporary spike in OpEx? Just wondering if you could expand on the impact on the results from a volume and a margin perspective?

Yes. And actually, as I was reading those, I realized I could of done a better job of trying to tie it in. If you actually look, they dovetail directly with Harry's comments. The challenges in the quarter were really related to the operational issues, that $25 million. A part of that was simply with the high water in the rivers, and we've got, basically, river crossings that go underneath it. And the concern, quite candidly, was that as that high velocity of water washes out, we may end up with pipe that's exposed. And so, you didn't want a lot of volume going through that, if in fact, at these record flood levels, that that was a possibility. So we basically shut down the pipes, and in some cases, we actually evacuated the pipes, so we didn't have product exposed. And so, that was a loss of revenue for the quarter.

Those floods happened, if you recall, in Calgary, late in the second quarter. We've given our guidance, I think in May. End of May, our updated guidance. And then, the floods happened after that, so a portion of that was lost revenue. In many cases, we're actually going in and doing what we call high directional drills to actually lower the pipe underneath those rivers, to make sure we don't have the issue in the future and to protect the environment, quite candidly. That's actually going to carry over into the second half of the year, because we still have some of those pipes shut in. I think Harry's estimate was about $15 million impact on the second half of the year, in terms of reduced revenue.

The other issue again, that I was referring to and Harry talked about in his, in the second quarter, was we had a release on one of our pipelines. There was expenses associated with that. And then, there was -- actually a third-party hit the pipeline, again. And so, the expenses there, those were accrued, as of the second quarter, should not associate with that event affect the rest of the year.

Great. And one last question on PNG, if I may. Great commentary, just in terms of how depressed the market has been, and where it's at and so forth. Have you seen or do expect to see any distressed assets coming onto the market? And if so, would you take a look at that? Or given the amount of the environment, probably not?

No, we would take a look at them. And, you know, at our May Analyst Day, I mentioned, it's just going to come down to how patient folks want to be through this, and I think you could have some one-off facilities that are either embedded in larger corps that you could see come out. We'll just have to wait and see. But we're definitely interested in any and all that come out, and we will be taking a look at them.

Great. Thank you very much, guys.

John Edwards, of Credit Suisse.

If I could follow Michael's question, with respect to differentials from grade differentials, are those -- are you expecting those to be more than what you've seen on basis? Or less? Or if you can give us a feel for magnitude on that?

I think the challenge -- well, first of, we've clearly seen some of these differentials come way in. When you've got Brent TI going from 27 down to 3, and in one case, a couple days, I think it actually traded at a premium. So I don't think we've seen the last of the volatility in those types of relationships. I think the other issues that we'll have is that as we continue to produce more and more light product -- and if you recall the handout from our Analyst Day showed kind of the range of the qualities of crude and condensate that we're seeing. In many cases, some of the condensate is 50, 60, 70 degree.

And I think there's going to become a point where there's just too much of it in the market. And if we don't have an alternative market, whether it's international, or the ability to put it onto a vessel or onto rail and get it to the other market, you're going to see discounts show up in that. So we're expecting it to be a vibrant dynamic, volatile, whatever you want to call it, market. It's just trying to predict when it's going to hit its saturation point on a regional basis is difficult. We also know that the refiners are aware of the same situation.

And they're working hard behind the scenes to try and position themselves to be able to take advantage of that surplus amount of volume, and see if they can't replace a heavier barrel. And then, you've got some that are basically saying, I can't do that, but I can blend the heavier barrels with light barrels. So, John, it's just going really be volatile here for a while, we think. And again, it'll probably start to show up in the next 12 to 18 month period. If you add operational upsets to that, it could show up next month.

Okay, so not. Okay, so I guess the answer is, we're just going to have to wait. I mean, it's just too hard, too volatile to tell. I was wondering, because we've seen, obviously, WTI Brent go from 24 to 2, in just six months. So I was thinking, with all this light crude coming on, are we going to see a more similarly volatile dynamic? Or that's what I was trying to get to, I guess.

Yes, and not to make it even more complicated, but part of the reason Brent trade was as wide as it was, was because of an international imbalance and you had a shortage of light crude out there. So tell me what China's going to do, and I can give you a more informed answer. But again, as a take away, I'd like for you and everybody on this call is that if there's any company out there that's well positioned to take advantage of the opportunities that provided by an unknown market, it's PAA.

Yes. No question there. It's just more for trying to look down the road, try to maybe figure out what margins to assume, that kind of thing. That's all. But, anyway, okay, just one other thing. You did guide a little higher on your capital spend. And then, you give us some preliminary for '14. So I'm just wondering, in terms of your overall opportunities that you're looking at, are you in the outer years, say, a little bit beyond '14, say '15, are you still seeing more opportunities come your way? Are you seeing it taper off a bit? If you could give us any insight you may have there.

When you say lower, right now, we certainly don't have the same level of cap expenditures in our long-term model for 2015 as we have in 2014. But that's true every year that we do our model. Our best visibility's in the near term. I would say we feel pretty good about the outlook for continuing to have demand for capital projects that we can play a role in, and have some either competitive advantage because we're asset positioning, or simply because of our knowledge in the ability to work with our relationships with the producers.

I think an important note here is that if we quit spending capital after '14, other than --John, just the tail off of projects -- the velocity of growth we would expect to see, all of things being held constant in our EBITDA and our DCF is still very positive for a couple of years beyond that. Simply because, for example, we're not yet harvesting from the capital that we've already spent in 2013. You'll start to see it in '14. And that's why, we have kind of guided people to say, look, focus in on the Transportation and Facilities segments, that's where all the capital's being spent. These are very attractive double-digit, in many cases, mid-teens kind of returns. And when you compare that against our cost of capital, you can -- the math really starts to sing.

So we feel very good about our distribution growth for many years, just based on organic growth that we've already got in the hopper. When you start asking me about '15, '16 and '17, we're focused on it. We're certainly trying to develop it, but you would expect to see a falloff, maybe 30% or 40% of the capital expenditures, based on what we can see today. If we get out into the future, and we continue to see, not only the known areas develop at the way we forecasted. We're forecasting volumes in the US and Canada to increase from 2012 levels by 3.4 million barrels a day. I can promise you our capital program of $1.6 billion this year and $1.4 billion next year doesn't address that kind of volume growth.

And so, the question really is, are we going to build capture some of those opportunities? Who our competition's going to be? Quite candidly, we position our balance sheet and our guidance, and you can call it sandbagging, whatever you want to call it. But we basically position ourselves to underpromise and overperform. And we wouldn't mind seeing softness in the industry or the capital markets, because it kind of levels the playing field. Right now, just capital is very cheap for everybody.

Yes. I'm looking at it, I'm just thinking, just a couple years back, the trajectory of spend was maybe $500 million to $700 million. And we're obviously, more than double that. And so, I'm just thinking, is that -- is this sort of more or less a new baseline? Sort of a $1.5 billion spend, is that the way to think about it?

I don't know if I'd call it a baseline, but it's certainly the neighborhood we'd expect to be in for the next couple of years.

Okay. All right. That's helpful. Thank you.

Matthew Phillips, of Clarksons.

You have already elaborated on this a bit, with regard to John's question and whatnot. But with regard to quality differentials, what are some of the signposts you all expect to see, as this starts to happen? Obviously, regional basis is fairly easy to sort out, especially as it's strapped behind a desk. What are we expect to see on--see that the quality differentials are widening. Is it mostly going to be a result of refinery runs, like in pad three and pad two?

I think it's going to be more of a function of production volumes exceeding what the baseline refinery runs are. So for example is -- we're forecasting in the Eagle Ford, Matt, for production right now, call it in the 800,000, 900,000 barrels a day, going up to 1.6 million to 1.8 million barrels a day. A large part of that may be in the over 30% to 40%, that's going to be very light product. And if you look at the markets that are available to that -- to service that, which would be not only the South Texas market, but certainly the ability to go to Houston, but you've also got a lot of other volumes coming down from Cushing with the Keystone pipeline and the Seaway pipeline. That's going to -- what we think is going to cause an imbalance. And so, you'll be looking for those volumes to start to find their way, in some cases, on the water, to go out of Corpus Christi, around the St. James, perhaps all the way around to northeastern part of Canada. And then, you've also got developments with respect to what qualifies for export whether that has to be split into different products. But there's certainly a need for more diluent in South America.

And so, I think it's just going to be something you're going to have to monitor pretty actively and see what people are doing, versus what they're saying. And if you start to see some of more of that volume hit the water, going to alternative markets, that's going to communicate to you that there's really a fundamental reason why there's a basis differential, why it's widening out there. And that's the way you move it, is you basically find a better market to offset a differential that you can access through transportation. So transportation plays a role in setting that differential. What does it cost to get to a different market?

A lot of the refineries have limitations on the amount of light ends they can handle. Crude is -- well, new production is lighter. Crudes have more NGLs, more light ends in them. And I think you'll start to see some pricing differentiation between a medium sweet and a light sweet, or a condensate, that you haven't seen in a long time in the US.

And you also see the seasonality that we see happen. We've somewhat tongue-in-cheek around here said that that various points in time with the amount of ethanol that's being forced into the system and the demand for diesel elsewhere, is that gasoline could be viewed at a certain portions of the year as a bit of a byproduct. So that kind of sets the value for the light end of the barrel, when you've got excess amount of gasoline that comes out of a naturally light barrel. So it's going to vary throughout the year, because of that.

Okay. That make sense. I know in Phillips 66's call last week, they had mentioned that they could add some light capacity to their Sweeny refinery. Do you think other refinerers down in the Gulf Coast are in that position, as well? Do you expect that to be a meaningful expansion down there, in the light crude run capacity?

I think every refinery out there right now is trying to figure out, behind the scenes, what they can do to increase their ability to run incremental volumes of light sweet and condensate. Whether they choose to share that with the public for negotiating purposes -- what they'd love to be able to tell you is we have no room at the inn, unless you discount really big and then they'll run it. So there's a constant amount of healthy tension between the producers and the refineries, with respect to trying to strike that balance.

I think the issue's going to be how much of that can be done without permitting, and how much of it can be done -- or how much of it needs permits? So to the extent refiners have the flexibility to tweak their inputs without paying permits, it's going to be a pretty good solution. If they need a permit, that's where you're going to see potential timing delays in being able to handle some of the light ends.

Okay. Thanks for the color, guys. That's all I have.

James Jampel, of HITE

Looking at crude by rail, in general, looking at the whole market, I realize that your guys' facilities are largely contracted. But with the collapse in spreads, are you seeing fewer railcars being loaded? Are you seeing railcars being turn back? And if so, what would -- who among the players will this be hurting most?

Great question. It would be beneficial to us to try to really spike those out. I would say, we feel very comfortable about our inventory of opportunities and assets in railcars. But clearly, there are some parties out there that don't have the diversity of balance in the value chain, and will -- it's probably just a matter of time before there's some additional pain out there, and they realize that leaving those barrels is a break even, perhaps, to a money-losing proposition. But really wouldn't want to engage in trying to pick out who those are.

What kind of activity decline are you noting out there, in general?

I think we're starting to see some transition back onto some of our pipelines, and we've seen some activity pickup, back and forth. And you'll see it, James, I think you can monitor their month delay, but the pipeline volumes that are reported by different pipelines. Enbridge clearly have seen a reduction in their activity on their pipeline, and forecasted that when rail economics became difficult, they'd see an increase in that. I would expect that to be true.

Okay. Thank you.

There are no further questions.

All right. Well, listen. Thanks everybody for dialing into the call, and we look forward to updating you in November. Thank you.

And that does conclude our conference for today. Thank you for your participation and for using AT&T Executive Teleconference. You may now disconnect.