Plains All American Pipeline LP (PAA) 2012 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the PAA and PNG third-quarter results conference call. At this time all participants are in a listen-only mode and later we will conduct a question-and-answer session.

(Operator Instructions)

As a reminder today's conference is being recorded. I would now like to turn the conference over your host, director of investor relations, Mr. Roy Lamoreaux. Please go ahead, sir.

Good morning, thank you. We welcome you to Plains All American Pipeline and PAA Natural Gas Storage's third-quarter 2012 results conference call. The slide presentation for today's call is available under the conference call tab of the investor relations sections of our website at paalp.com and pnglp.com. I would mention that throughout the call we will refer to the Company's New York Stock Exchange ticker symbols of PAA and PNG, respectively.

As a reminder, Plains All American owns a 2% general partner interest in all the incentive distribution rights and approximately 62% of the limited partner interest in PNG, which accordingly is consolidated into PAA's results. In addition to reviewing recent results, we'll provide forward-looking comments on the partnership's outlook for the future. In order to avail ourselves of Safe Harbor precepts that encourage companies to provide this type of information, we direct you to the risks and warnings 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 EBIT and EBITDA. The non-GAAP reconciliation section of our websites reconcile certain non-GAAP financial measures to the most directly comparable GAAP financial measures, and provides 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 and 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 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 CFO 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-and-answers session. With that I'll turn the call over to Greg.

Thanks, Roy. Good morning and welcome to everyone. To our friends in the northeast please know that our thoughts and prayers are with you and we wish all of you a speedy recovery. With respect to PAA's third-quarter results, we continued a multi-quarter trend where PAA once again delivered strong quarterly results.

After Market close yesterday Plains All American announced third-quarter adjusted EBITDA of $502 million, which exceeded the midpoint of our guidance range by approximately $92 million, due principally to strong results in our Facilities and Supply and Logistic segments. Current-year results also favored -- compared favorably to last-year's third quarter, as adjusted EBITDA, adjusted net income and adjusted net income per diluted unit of the third quarter of 2012 increased by 21%, 18% and 3%, respectively.

Although it did not impact our adjusted results, our third-quarter reporting results include the impact of a non-cash impair -- non-cash impairment charge totaling $125 million, the bulk of which is associated with our recent determination not to proceed with the development of the Pier 400 project in Los Angeles. Harry will provide some additional comments on the background for our decision during his portion of the call.

Highlights of PAA's third-quarter adjusted performance are reflected on slide 3. A detailed reconciliation between reported results and adjusted results is included in the appendix. As illustrated in the middle graph, PAA continues to generate strong distribution coverage, as total coverage in the third quarter of 2012 was 145%.

As shown in the top panel of slide 4, these third results -- third-quarter results mark the 43rd consecutive quarter that PAA has delivered results in line with or above guidance. I want to also note that early last month PAA completed a 2-for-1 unit split and subsequently declared a 9% year-over-year increase in our annualized run rate distribution to $2.17 per common unit.

As shown in the bottom panel of slide 4, PAA has increased its distribution in each of the last 13 quarters and in 32 of the last 34 quarters. Over nearly a 12-year period PAA has grown its distribution at a compound annual growth rate of approximately 7.5%.

Yesterday evening we furnished updated financial and operating guidance for the full year of 2012, increasing adjusted EBITDA guidance by $137 million. This represents an approximate 7% increase over the full-year guidance provided in August 6 and a 22% increase over the full-year guidance we provided at the beginning of the year. Clearly PAA is executing well in this environment and we are on track to meet or exceed our goals for 2012.

As shown on slide 5, yesterday evening we also furnished preliminary guidance for 2013, targeting a midpoint for adjusted EBITDA of $1.925 billion. Although the midpoint of this preliminary guidance reflects an approximate 5% decrease in year-to-year performance for total adjusted EBITDA, it is important to mention that it does not assume the continuation of favorable market conditions beyond the first quarter of 2013.

Importantly, our preliminary 2013 guidance reflects continued and meaningful improvement in PAA's baseline performance, with 2013 adjusted EBITDA forecast to increase 17% over the 2012 guidance provided in February 2012. Our preliminary 2013 guidance forecasts a year over year combined increase of 15% for our fee-based Transportation and Facilities segments.

This anticipated increase primarily relates to recent acquisitions or organic capital investments made in 2012 and prior years that are expected to come on stream in 2013, or will be contributing to our operating financial results for the full year.

On the other hand, our two -- preliminary 2013 guidance for our Supply and Logistics segment, perhaps conservatively, assumes a return to baseline-type market conditions after the first quarter of 2013 as opposed to the more robust favorable market conditions we experienced in 2011 and thus far in 2012. This prudent but somewhat conservative approach results in preliminary 2013 guidance for the Supply and Logistics segment that is more than $250 million below our 2012 midpoint guidance for this segment.

As a result, the midpoint of our preliminary guidance for 2013 reflects a very solid fee-based contribution of approximately 75% in relation to a near baseline level of performance. This compares to 2012's projected fee-based contribution of 61%, which include significant benefit from our Supply and Logistics segment from favorable market conditions. As in the past, if we see a continued favorable environment extending further into 2013 for our Supply and Logistics segment there is clear upside to our 2013 performance relative to our preliminary guidance.

With respect to distributions, we are targeting distribution growth during 2013 of approximately 7% to 8% over the 2012 distribution exit rate. As reflected on slide 6, based on the midpoint of our targeted distribution growth range and the midpoint of our 2013 guidance range we are forecasting very healthy distribution coverage of around 120%.

This level of coverage would enable PAA to retain over $200 million of cash flow in excess of distributions to be applied towards the financing of our 2013 capital expansion program. I would note that this distribution target excludes the impact of any material acquisitions. We will provide detailed 2013 guidance on our year-end earnings call in February.

During the remainder of today's call we will discuss our segment performance relative to guidance, our expansion capital program, our acquisition and integration activities, and our financial position. We will also address the drivers and major assumptions supporting our financial and operating guidance for the fourth quarter of 2012. We will address similar information for PNG, and at the end of the call I'll provide a recap, as well as some comments regarding our outlook for the future. With that, I'd turn the call over to Harry.

Thanks, Greg. During my section of the call I'll discuss our third-quarter operating results compared to the midpoint of our guidance issued on August 6, the operational assumptions used to generate our fourth-quarter guidance, our capital program, as well as our acquisition and integration activities.

As shown on slide 7, adjusted segment profit for the Transportation segment was $190 million, or $0.58 per barrel, which is slightly higher than the midpoint guidance for both measures. Volumes for the segment of 3.5 million barrels per day were about 55,000 barrels a day lower than guidance.

Pipeline volumes were down about 37,000 barrels a day. And a couple items that impacted the quarter include, first, we had lower volumes on a couple of our Gulf Coast pipelines due to Hurricane Isaac; and then second, we're seeing some volumes being diverted to rail in certain areas in North Dakota and Canada.

Adjusted segment profit for the Facilities segment was $142 million, or $0.43 per barrel. The total was approximately $27 million above the midpoint of our guidance, volumes of 111 million barrels were generally in line with the guidance and a number of factors contributed to the performance in this segment.

On the revenue side, unforecasted volumetric gains at several NGL facilities, higher-than-forecast cost recovery for ethane sales from our Canadian NGL assets and over-performance at PNG contributed to over-performance for this segment. The quarter also benefited from lowe-than-forecasted operating expenses on a recently-acquired BP assets, primarily due to some true-up adjustments related to the second quarter 2012.

Adjusted segment profit for the Supply the Logistics segment was $169 million, or $63 million above the midpoint of guidance. Our total volumes were 995,000 barrels per day and included 811,000 barrels per day of lease gathering volumes and 179,000 barrels per day of NGL sales volumes. NGL sales volumes exceeded guidance by approximately 50,000 barrels per day.

Adjusted segment profit per barrel was $1.84, which was $0.62 a barrel above our midpoint guidance, and the over-performance was primarily due to stronger margins in our NGL business and crude oil differentials that were more favorable than anticipated.

Now let me move on to review the operational assumptions used to generate our quarter 2012 guidance, which was furnished in our Form 8-K last night. The fourth-quarter segment guidance compared to actual results for last quarter and the fourth quarter of last year are included on slide 8. For the Transportation segment we expect volumes to average approximately 3.6 million barrels per day. Adjusted segment profit is expected to be $193 million, or $0.58 per barrel. This forecast is in line with our third-quarter actual results.

The Facilities segment guidance assumes an average capacity of 113 million barrels equivalent. Adjusted segment profit is expected to be $133 million, or $0.39 per barrel in the fourth quarter. The forecast reflects the seasonality associated with our gas storage business.

Supply and Logistics segment volumes are projected to average approximately 1.1 million barrels per day for the fourth quarter of 2012 and adjusted segment profit is expected to be $193 million. The fourth-quarter forecast assumes that favorable crude oil differentials continue and also reflects an expected seasonal uplift in NGL sales volumes. Projected segment profit per barrel is $1.92 in the fourth quarter is in line with the third-quarter results.

Before discussing our current capital projects let me address our recent decision regarding Pier 400. As Greg mentioned earlier, in the period since our August 7 conference call we determined not to proceed with the development of our Pier 400 terminal project.

We inherited the Pier 400 project in connection with our acquisition of Pacific Energy Partners in late 2006. Since that time, we've invested significant time and capital working through the regulatory process and negotiating with a variety of potential customers, while also engineering the project to meet environmental requirements and adapt to the changing needs of potential customers.

A number of factors contributed to the uncertainties with respect to financial returns and determination not to proceed with the project, including project delays, economic downturn, regulatory and permitting hurdles, a challenging refining environment in California and an industry shift in the outlook of availability of domestic crude oil. PAA is and will remain a significant owner and operator of crude oil refined products and NGL infrastructure in California and we expect to continue to develop and execute growth projects in California.

With that, let me move on to our 2012 capital program. Through the third quarter we invested approximately $831 million. As detailed on slide 9, we expect our 2012 capital program to range from $1.1 billion to $1.25 billion. As you can see from the slide, PAA's capital program consists of a large number of smaller- to medium-sized projects. In all material respects, our projects are proceeding according to schedule and on budget.

The expected in-service timing of the larger projects in our capital program is included in on slide 10, and given the number of projects in our portfolio I'll limit my status update to a few of our larger projects and discuss our activities on the larger resource plays. In the Eagle Ford area, our joint venture pipeline system will be completed in phases. We expect to have the Gardendale to Three Rivers segment in service by December 1.

The Three Rivers and Corpus Christi segment in the first quarter of 2013 and the Three Rivers to Lyssy segment the service in the third quarter of 2013. Initial capacity will be limited to approximately 150,000 barrels a day, as electrical power capacity in the areas increase, which is expected to occur in 2014. We will be connectin a number of our production facilities to our Gardendale gathering system in the fourth quarter.

We also have a couple of additional laterals under construction that will be connected to our Gardendale terminal. Our northeast lateral will be completed in 2012 and our western lateral will be completed in the first half of 2013. We also constructing two condensate stabilizers at our Gardendale terminal. Each stabilizer will have the capacity to process up to 40,000 barrels a day of condensate. The first stabilizer will be in service in 2012 and the second stabilizer is expected to be in service in the first quarter of 2013.

Moving to the Permian Basin, several segments of our Spraberry system will be completed and in service by the end of the year with the entire project expected to be complete in the first quarter of 2013, and we also will have our connection to Longhorn pipeline system completed by the end of 2012.

In Oklahoma our Mississippi Lime pipeline is expected to go into partial service in the first quarter of 2013 and to full service by mid-2013. And last month, White Cliffs Pipeline announced a expansion underpinned by long-term shipper commitments. Pipeline capacity will increase from approximately 70,000 barrels a day to approximately 150,000 barrels a day. The cost associated with our 34% ownership interest is expected be about $100 million.

In the Bakken we expect to have our Bakken North pipeline completed by the end of the year; however, if you reference our last call we do not expect Enbridge to complete the connection to their line until the second quarter of 2013. And in Canada we have started construction on our Rainbow II pipeline. This is a 187-mile 10-inch pipeline that will deliver diluent to heavy oil producers out of Rainbow pipeline. It is expected to be in service by mid-2013.

With regard to our rail projects, our Manitou facility at Bakken is expected to be capable of handling the unit trains by the end of the year. Our Tampa, Colorado facility is expected to be in service in the third quarter of 2013. The expansion of our unloaded capacity at Yorktown is expected be in service in the first half of 2013.

Our preliminary 2013 capital program provided in our guidance last night is a range of $900 million to $1.1 billion and we'll discuss the specific projects included in this total during our February call. Our maintenance capital expenditures for the third quarter totaled $47 million.

We currently expect the maintenance capital expenditures for 2012 to be around $165 million, and that's an increase of approximately $15 million from last quarter and is primarily associated with the expansion of our integrity management program. The results are due to timing, as we currently expect to complete more work in 2012 than previously forecasted.

On the acquisition front, we remain active, but for competitive reasons and due to confidentiality restrictions we're unable to discuss any specifics with respect to those activities. However, with respect to our integration efforts we are on track with our integration milestones we established for the BP NGL assets we acquired. 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 third-quarter operating and financial results and our financial position as of September 30, 2012, provide an update on PNG's operations and capital program and review our fourth-quarter and full-year 2012 guidance, as well as provide some comments on our preliminary 2013 guidance.

Let me begin by discussing the results we released yesterday. As shown on slide 11, PNG delivered third-quarter results that were approximately $3 million above the midpoint of the guidance we provided in August. Adjusted EBITDA for the third quarter totaled $29.7 million and distributable cash flow totaled $27.8 million, resulting in adjusted net income of $18.3 million and adjusted net income per diluted unit of $0.25.

A portion of the over-performance relative to the midpoint of our guidance is timing-related, as we were able to accelerate the realization of profits associated with storage capacity that we manage for our own account into the third quarter. The results also reflect lower expenses and the benefit of higher-than-forecasted market volatility during the quarter. In comparison to last year's third-quarter results, adjusted EBITDA, adjusted net income and adjusted net income per diluted unit for the third quarter of 2012 increased 11%, 14%, and 14%, respectively.

As reflected on slide 12, PNG's third-quarter results marked the ninth consecutive quarter of delivering results in line with guidance. Financially, PNG continues to be well positioned. Included on slide 13 is a condensed capitalization table for PNG. As of September 30, 2012 PNG's long-term debt to capitalization ratio was 29%, our long-term debt to adjusted EBITDA ratio was 3.8 times and we had $173 million of committed liquidity.

Operationally, we are on track to complete our 2012 capital program on time and on budget. We currently estimate our capital program will total around $61 million. In September we placed our fourth cavern at Southern Pines into service. We have been creating and expect to continue to create additional capacity through our leeching activities at both Pine Prairie and Southern Pines.

Overall, we expect to exit 2012 with aggregate capacity of approximately 93 BCF, a 22% increase over the 76 BCF of capacity that we had entering into 2012. Our preliminary 2013 capital program calls for approximately $40 million of organic growth capital investment. This capital primarily relates to continued expansion via fill dewater and smugging of our existing caverns at Pine Prairie and Southern Pines.

As reflected on the right side of slide 14, we have increased in the midpoint of our 2012 guidance for adjusted EBITDA by approximately $1 million to $121 million. This midpoint is based on an updated range of $190 million to $123 million. This guidance represents a 13% increase over 2011 comparable results. For the fourth quarter we expect adjusted EBITDA to range from approximately $32 million to $36 million.

As depicted by the chart in the upper right corner of slide 14, this guidance is consistent with the anticipated seasonal increase in fourth-quarter profitability. With respect to distribution, last month we announced a quarterly distribution of $1.43 per unit on an annualized basis. This distribution, which was payable next week, is equal to the distribution that was paid in August 2012.

Overall, distributions paid in 2012 represent an increase of 2.7% over limited partner distributions paid in 2011. Our distribution coverage for the third quarter was 106%. Achieving the midpoint of our guidance for 2012 provides approximately 107% coverage of our existing distribution level.

Prior to discussing our 2013 guidance I think it would be beneficial to provide an update on our view of natural gas storage market conditions, which remain challenging. As reflected on slide 15, despite a recent uptick in volatility, seasonal spreads for the 2013-2014 and 2014-2015 seasons remain at low levels. It's approximately $0.40 per MMbtu.

On the positive side, natural gas demand continues to strengthen and significant industrial investments are being made to continue that trend. That said, the market may take several years to improve and as a result, our preliminary 2013 guidance assumes that market conditions will remain similar to those experienced in 2012. Our preliminary 2013 adjusted EBITDA guidance range is $117 million to $223 million with a midpoint of $120 million.

As shown on slide 16, this midpoint is the same as our initial 2012 forecast and just slightly below the midpoint of our current 2012 guidance. In total, incremental revenues from our recent and planned low-cost capacity additions are expected to effectively offset the impact of higher-price contract expirations on existing capacity. If market conditions improve, or volatility increases we believe that there is upside to our forecast.

Based on achievement of our preliminary 2013 midpoint guidance, coverage of our current distribution level is forecasted to be approximately 103%. We will provide more specific details with regard to our 2013 guidance on our year-end earnings call in February. In conclusion, although we continue to face challenging market conditions, we are executing well on what we can control and believe we are well-positioned to pursue -- participate in market improvements. 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 first-quarter and full-year 2012. As detailed on slide 17, our financing activity since the last conference call were limited to our continuous equity offering program. We began executing our original $300 million program in May. In mid-September we completed that program and initiated an additional $500 million program.

During the quarter we raised approximately $255 million of incremental equity capital, including the general partner's matching contribution, by selling approximately 5.8 million common units on a split adjusted basis. We are very pleased with this program, as the cost is attractive, the rateable cash raise closely matches our organic growth capital investments and it is much less disruptive on the trading of PAA's units then the traditional overnight, or one-day marketed offerings.

As illustrated on slide 18, PAA ended the third quarter with strong capitalization, credit metrics that are favorable to our targets and approximately $2.4 billion of committed liquidity. At September 30, 2012 PAA's long-term debt-to-capitalization ratio was 46%, total debt-to-capitalization ratio was 49%, long-term debt-to-adjusted EBITDA ratio was 2.9 times, and our adjusted EBITDA to interest coverage ratio was 6.8 times.

As you can tell from our very strong capital metrics, as a result of the continuous equity offering program and retained DCF we have effectively prefunded our 2013 expansion capital program and are well-positioned to finance moderately sized acquisitions. As a result, absent significant acquisition activity we do not expect to execute an overnight or marketed offering during 2013.

Our total debt ratio $834 million of short-term debt that primarily supports our hedged inventory. This debt is essentially self-liquidating from the cash proceeds when we sell the inventory. For reference, our short-term hedged inventory at September 30, 2012 consisted of approximately 25 million barrels equivalent with an aggregate value of approximately $1.3 billion.

These amounts do not include approximately 20 million barrels equivalent of line fill and base gas in PAA's and third-party pipelines and terminals that are classified as a long-term asset on our balance sheet with a book value of approximately $1 billion and a market value over $1.2 billion.

Moving onto PAA's guidance for the fourth quarter and full year of 2012 as summarized on slide 19, we are forecasting midpoint adjusted EBITDA for the fourth quarter of 2012 of $520 million and slightly over $2 billion for all of 2012. This updated 2012 guidance reflects a 7% increase in adjusted EBITDA since our guidance in August and a 22% increase since our beginning of the year guidance provided in February. For more detailed information on our 2012 guidance please refer to the guidance 8-K that we furnished yesterday.

As we have discussed in previous meetings, we target minimum distribution coverage of at least 105% to 110% on baseline distributable cash flow, or DCF. During periods of strong performance, our coverage can run meaningfully higher as we retain the excess DCF to fund our growth. In this regard, PAA's continue to deliver solid discussion growth and coverage.

As represented on slide 20, based on the midpoint of our 2012 guidance for DCF and distributions to be paid throughout the year, our distribution coverage is forecast to be approximately 150%, enabling PAA to retain approximately $500 million of excess DCF, or equity capital. Not only is this our least expensive source of equity capital, it is a meaningful source of capital and it enables us to convert market-related over-performance into enduring fee-based cash flow stream. With that, I'll turn the call over to Greg.

Thanks, Al. The first nine months of 2012 have been a very active and productive period for the partnership. As recapped on slide 21, in addition to delivering strong performance in each of the first three quarters of the year, PAA increased its fourth-quarter and full-year 2012 guidance and remains on track to deliver a record-year performance.

Looking beyond 2012, we furnished 2013 preliminary guidance that forecast continued growth in our fee-based Transportation and Facilities businesses and defines our view of the near-baseline performance we expect for our Supply and Logistics segment. From this point of this 2013 preliminary guidance clearly underpins the distribution growth target we have established for 2013 while maintaining healthy distribution coverage levels.

Furthermore, there is clear upside potential to our guidance if favorable market conditions extend beyond the first quarter of 2013. Finally, as a result of the partnership's solid asset position throughout the most active North American crude oil resource plays and it's proven business model, attractive expansion project portfolio and solid capital structure, PAA's poised to deliver solid performance beyond 2013.

We thank you for participating in today's call and 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 and providing details of 2013 guidance during our fourth-quarter and full-year results call in February. Keeley, we're now ready to open the call up for questions.

Thank you.

(Operator Instructions)

We'll go to the line of Darren Horowitz at Raymond James. Please go ahead.

Thanks for taking my question. I actually only have one and it's in regard to the Supply and Logistics segment guidance that you outlined, and I know this is a tough question to answer, but can you give us a little bit more color on what the baseline-type market conditions mean in terms of how you're thinking about regional pricing spreads and [grey] quality differentials? Whether or not it's WTI to Brent or Midland to Cushing or even variances around Louisiana light sweet, I'm just trying to get a sense for how you all are thinking about spreads as more production and more pipe capacity comes online next year?

Darren, you raise a great question and there's a lot of art to the science of forecasting in our business model. I think probably the best way I could summarize it is, we run a number of iterations about what could happen in the future, and we look at our tool chest of resources that we have, both assets and hedging opportunities to lock in opportunities when they show up, and after numerous iterations we come up with what we feel like is a pretty baseline performance that we'll be able to hit almost no matter what happens in the future. What we don't take into account in that forecast are situations that we think are likely to occur but are very difficult to predict when they will occur, and so we leave that really as upside and we exclude that from our baseline. Over time I would tell you we would be disappointed if we didn't have performance above that baseline because we do think there will be volatility and we think we have the tools and the business model and the assets to be able to capitalize on that. So we've got a fairly robust outlook for the third -- fourth quarter and also for the first quarter of 2013 that we've dialed into our forecast. I can tell you probably haven't taken full advantage of what we think could happen, but we've certainly given some credit.

And then back beyond the first quarter we've assumed things return to more of a normalized margin per barrel. And unfortunately, we can't break that margin per barrel down into what that translates into a Midland/Cushing differential or WTI/Brent differential because it's the result of an amalgamation of a number of different forecasts we run to get to that baseline. So effect -- I know what -- you're looking forward where do we think there's likely to be opportunities out there and the answer is we think they'll be just about everywhere. Any time an area appears to be getting in balance where take away capacity equals production capacity that needs to move out of that area, if you have a refinery downtime or you have a pipeline project that's delayed, et cetera, that creates volatility, backs up differentials and, of course, we've got pipelines, trucks, rail cars, barges and a significant amount of inventory that we carry, as well as terminals, to be able to store more inventory that enable us to capture that market. So, if you believe the future is going to be volatile, we think PAA's probably the best place to pay attention to.

I appreciate it, Greg, thanks.

Thank you. Our next question will come from the line of Brian Zarahn with Barclays.

I think Harry mentioned that pipeline volumes in the third quarter faced some increasing competition from rail and I know you have some rail projects coming online next year, but can you talk a little more about that competitive dynamic of rail on your pipeline volumes?

It's probably in the neighborhood of 10,000 barrels a day if that's what you're looking for, but there's some areas in North Dakota and some areas in Canada where you're starting to see little bit of volume be diverted to rail so it can get to a higher value [day] markets.

It was relatively modest in terms of your volumes, but I guess going forward in '13, '14 you'll be participating a little bit in this, but do you see any type of pressure on your pipeline volumes from rail?

I think we're probably seeing the pressure that we've seen. I don't think you'll meaningful increases in volumes being diverted from our pipelines to rail and we are currently railing some volumes out of the Bakken right now. We have loaded manifest trains. Like I said, we'll -- by the end of the year we'll be up to unit trains out of the Bakken.

I think, Brian, over time it's fair to say pipelines are going to be the most efficient way to move crude. Rail will be a competitor for those pipelines in a given area when those pipelines are going to inferior markets. And by that I'm -- not necessarily bad markets, just markets that aren't as good as some of the other areas and that can be somewhat event driven. So I think the amount of crude oil or condensate that will be transported by rail in preference over pipeline is going to be by definition pretty small. It's going to be when differentials widen out in that particular area and you get backed up a little bit, or it's going to be where there's just a screaming demand for crude somewhere else that they can find a way to use that wide differential and you can't get there by pipeline.

Okay. And then in terms of Pier 400, I know it's been -- faced a lot of uncertainty for many years. With the withdrawal of the project, can you talk a little bit about what growth opportunities do you see serving pad [by] refiners?

Well, in general I think they're still focusing on potential for increased production from within California. Clearly the resource plays, whether in other areas outside of California, hadn't been developed four or five years ago when the project was started and there's certainly been a focusing on the potential for increasing production in California, both as a result of higher prices and also technology through the application of fracking and horizontal drilling to Monterey shale. So I think we stand a good chance of seeing some pleasant surprises in volumes within California. In addition, I think you're going to see rail clearly into California is providing an opportunity, because right now California's having to compete with Brent-based pricing on the coast, just the same way the East Coast is, and so rail becomes a part of the solution there. And as Harry mentioned in both this call and prior calls, we're increasing our participation in rail. We think not only loading facilities are going to be important, but the most important part of it will be the unloading and the ability to get it off that unloading location to the market.

And then also California we've got Line 63 that we're -- we've got some work on now, so we've got all the volumes for a portion of that quarter moving on line 2000, so as we get Line 63 back into service we'll have additional pipeline capacity from the San Joaquin Valley into LA.

Thank you.

Next we'll go to the line of Ted Durbin with Goldman Sachs.

Just following up on the rail comments there. I realize you're not giving a lot of detail on the capital budget, but is there a lot of rail investments in there and if there is, can you tell us what areas you'd be investing in there?

There's no large concentration in any one particular area in rail. A rail loading facility really doesn't cost that much. We've got $1 billion of capital is our midpoint for next year in early guidance. To do about $1 billion this year took about 200 projects, and so we're really not looking for any one single large project out there and none of the larger projects really are rail-related. So they're just -- it's a build out of existing facilities where we've got rail. Clearly Yorktown, we're building increased capacity as we go from manifest to unit trains. We've got additional work we've got in the Tampa and a few other areas, but --

Tampa's in the DJ Basin so we'll be able load DJ Basin crude and take it to the East and West Coast. Manitou's right smack in the middle of the Bakken, it'll have pipeline receipt capacity and truck receipt capacity. And as you can imagine we've got a couple of other projects on the drawing board, probably just not advanced far enough to provide the details today.

I'd probably say if you aggregated it's still preliminary so give me a little bit of a hall pass on this, but I would probably say of the roughly $1 billion it's less than 15%, probably even less than 10% of the capital on that's related to rail.

Got it, that's helpful. Thanks. And then just thinking about the Permian takeaways capacity. You've talked before and questioned about this -- the need to go to the Gulf Coast and we now -- it sounds like we have a potential project to get to the West Coast. I'm just thinking -- wondering how you're thinking about overall the best solution for getting Permian crude out given there's a bullish supply outlook there?

For competitive reasons I'm going to dodge your question. I think we have as good a handle as anybody as to what the supply/demand balance is out there and we think we have a pretty good perspective on where the best markets are and what the costs are to get it there, so I'd just tell you to stay tuned.

Okay, and last one for me, a little more detail there. It looks like the Facilities segment operating costs were pretty light this quarter. I think you mentioned something about the BPS, can you give us a little more detail there and how we should be thinking about those costs going forward?

I think if you look at the second quarter and third quarter combined it's probably more reflective of annual run rate, probably is the easiest way to say it.

As soon as we close we've got some true-ups on accruals and classifications and so I think Harry's comment's probably the best way to look at it.

Fair enough, That's it for me, guys, thanks.

Thank you. And next we'll go to the line of Ross Payne at Wells Fargo.

I guess my first question is going to be, Greg, given the substantial number of pipeline projects announced out of the Bakken, how many do you feel will actually be built? And second, how meaningful is rail, maybe a decade out, out of the Bakken, in particular?

Well, a decade's a long time. (laughter) If we'd have had this discussion a decade ago we wouldn't even be talking about the Bakken. I think what's fair is that of the big three shale areas, Ross -- Eagle Ford, Permian and Bakken. Bakken is probably the one that's on the economic bubble more so if -- both because of higher cost and distance to market, and so I think it's difficult right now if you're a producer, to make 10-year commitments to support some of the pipeline projects. I think we're watching very closely and we'll be interested to see what develops out of there. But we think, at least in our model, for -- if I can talk about a half a decade, we think rail is probably the most likely scenario to handle the excess volumes out of the Bakken, simply because you don't have to make 10-year commitments. And yes, the transportation costs are higher, but if you add the cost to get from the Bakken to Cushing and all the way to the Gulf Coast you're talking about probably in the $10 range for pipeline and you're talking in the $13 to $14 range for rail, dependent on whether you're -- maybe $13 to $15 whether you're talking manifest or unit trains. So we think rail probably has some legs with it. I think important is going to be -- because it is -- within the industry we tend to over-build and so I think there's a potential for loading stations to get over built and the important thing is where are you going to take those once you get loaded to and the value will be in having unloading locations at the right markets.

I think if you just broad picture it at the Bakken it's hard to imagine a pipeline built to the West Coast, probably only feasible alternative to go to the East Coast is Enbridge's project where they come into Superior and reverse line 9. And going to the Gulf Coast it's hard to imagine new pipe, there could be some pipeline conversions. And you're sitting here today with probably a fairly meaningful amount of capacity on rail, probably more capacity than production today, but we think rail is going to be part of a longer-term solution to moving crude out of the Bakken area.

Yes, I think Harry's comment about converting existing pipe versus building new pipes is important because if you're building new pipe you're talking about trying to make a 10-year commitment that may not start for two or three years from now by the time you get it built, so you're really talking about a 13-year period, whereas conversions can happen faster than that and shortens that. And that's what people want right now, they want near-term relief.

Sure. Thanks, Greg, I apologize for asking you to step all the way out 10 years but anyway (laughter) I thought I would try. Second of all, where are you guys currently in terms of number of rail cars that you do control? And that'll be it for me, thanks.

In terms of -- well, I can give you a neighborhood if you want to -- are sharing that?

I wouldn't -- certainly it's around (inaudible).

We should be somewhere around 6,000 by the end of 2013. And Ross, by the way that includes NGL and crude probably about 50/50 neighborhood.

Okay.

So we already had a fairly big presence. I think we were in the 1,500 rail cars prior to the acquisition of BP. When we acquired the BP we picked up about 700, 800 more rail cars so that took us to about 2,300. We've increased the amount of rail cars we need for NGL probably to the -- almost 3,000 and we're working our way up on the crude side probably to approach 2,500 to 3,000 there, as well. So it's a total of about 6,000 but split about 50/50 between NGL and oil.

Super. Okay, great color, guys. Thanks.

We'll go next to the line of John Edwards at Credit Suisse.

Hi. Greg, some of my questions on rail have been answered but I was curious, in your outlook what do you are assuming for production, oil production next year?

I haven't added it up by year, we tend look at it, John, more on a region-by-region basis.

That'll actually be more helpful. I --

Were not sharing that for (inaudible), but I think it's fair to say we recently retooled -- I won't say we're always conservative, but we're probably always trying not to be wrong on the high end and an area that we've probably gotten more bullish about here recently has been Eagle Ford area. I think -- and I gave a presentation a while back to an industry group where I think our original estimate was we thought might hit 1.2 million barrels by 2018, and I think revised that up to about 1.6 million barrels and so -- and to some extent the reason we have to look at it on a region-by-region basis, John, if some of these areas that are closer to markets like the Permian and the Eagle Ford are as successful as we think they can be we're probably, by definition, going to saturate the market for light sweet crude, which will be widen differentials, which will hurt areas like the Bakken, which as I mentioned in my earlier comments is probably the third most economic of the big three. And so we think you could see some slowdown there.

So we define in each area what we think the potential is in the absence of interference between other supply areas, realizing that the more and more we supply the more pressure we put on the differentials associated not only with that region but also with that quality. And we do think, and we've been outspoken, that we think ultimately we're going to be long in the US Gulf Coast area, in particular light sweet crude, by a significant amount and so that's going to widen differentials out. So I realize I've totally avoided your question, but I assure you it's within our unitholders best interest.

No worries, or maybe if you could add a bit of detail. What's your thoughts regarding production in the Bakken area? Can you share that?

We think it continues to increase. I think that the rate of increase can be terribly influenced by rig counts and again, if you're a producer that's just in the Bakken it's economic to continue drilling. If you're a producer that's in the Bakken, the Permian and the Eagle Ford, and you have a limited amount of capital, you're probably going to allocate more capital emphasis on the Eagle Ford and the Permian area just because of the economics and so that slows the rate of drilling in the Bakken. So that's why I say I think it's going to ebb and flow. I think if you said what can we produce out of the Bakken based upon an assumed constant rig count and continued performance improvement -- because they've cut a lot of drilling time out of that area, they've probably knocked already 20% off the drilling time, so one rig can do 20% more in the same time period. But at the same time, the people are reallocating capital so they're moving some of those rigs around. So that's why it's pretty much a dynamic issue but I think, we think there's probably -- John, help me out, but I think probably 30%, 40% more upside to volume in the Bakken. It's just when you get there is a function of what the market additions are to allow you to have economics to allocate capital between basins.

Okay, fair enough. I guess just -- the look I was thinking on rail versus pipeline I was going to -- I guess was asking Brian's question in different ways. When do you see pipeline pressuring rail, and I know you've already made a lot comments on that but I'm in particular in the Bakken area?

Well, actually we don't think in the near term it's going to pressure rail a whole lot, depending upon what happens with the timing of those pipeline projects. There's several projects that are talked about, but probably the next two years rail's going to be a critical part of that. That's why I cut the decade comment down to a half decade because you get to the end of that four or five years it's going to be a function of whether or not some of these pipeline projects have gotten built or not.

Okay, fair enough. All right, thank you, that's all my questions.

Thank you. We'll go next to the line of James Sample at [Hyatt]. Please go ahead.

Can you talk a little bit about the recent Rangelands transaction? You guys surely had a look at it and would you consider it not strategic or not price well or any other reason why it might not fit with Plains?

James, I appreciate your comment there. You can assume two things. One, if we looked at it we had to sign a CA and if we did we couldn't talk about it, so the best thing I can do is no comment to you at this point. I know you wouldn't want us to break a confidentiality agreement.

No, but is it the kind of asset that you would've liked to have had?

Keep in mind, we're building facilities out there already so we've got our own infrastructure, we don't need duplicative infrastructures out there. And, again, as I pointed out it's -- loading's important, unloading's probably more important.

Okay, thank you.

We'll go next to the line of Michael Blum at Wells Fargo.

Just two quick ones for me. One, trying to reconcile. I believe Al in his prepared comments said that for your baseline you think a 1.1 coverage is appropriate, and yet your guidance, which I believe is essentially a baseline kind of guidance for 2013, suggests a 1.2 coverage with 7% to 8% growth, so what I'm getting at, is there upside to that distribution growth forecast even excluding --?

I think a very operative word in Al's discussion was minimum in terms of coverage and the way we look at it we price our cost of capital, et cetera, is we recognize -- I'm preaching to the choir here, I realize -- there's floors and ceilings on distribution growth. If you don't have any distribution growth there's a yield ceiling that sent to show up and you have distribution growth you're not going to necessarily going to get dollar-for-dollar benefit, or point-to-point benefit in your cost of capital. So at this point in time we're comfortable at thinking we're probably in the 7% to 8% with great visibility from organic, not needing acquisitions, to basically being category-leading distribution growth on a risk basis, certainly, and we're using an excess cash flow that would otherwise cost us significant dilution to -- because the unit prices aren't priced at where we think we're going to be able to grow our distribution to. And I think we had calculated last time I looked at -- and I have to think whether it was pre split or post split -- but effectively I think for every $100 million of capital that we retain we basically pick up accretion per unit of roughly $0.015 to $0.02 per unit. So clear that we have the ability to grow it faster but would it actually translate into a better trading yield or simply increase the total return for that period of time and on balance right now we're comfortable basically saying we would rather give you an extended view of a very attractive distribution growth than a one-year hump and then come back down and have to go back out and raise capital to fund our growth.

Okay, I appreciate that. The other question I had is actually on PNG and the natural gas storage markets. It seems like there's pretty much at this point a view coalescing in the market that things are going to be weak for some period of time, multiple years potentially. Have you seen any change, given that view in the M&A market. Are there folks out there that are finally saying uncle and are more willing to transact, is there anything that looks interesting?

Well, Michael, I think -- again commenting on that, I think most of the folks out there have decided to hunker down through this period. If there is -- if there's anything out there, we'd certainly look at it, but it's a pretty quiet period right now. I think others out there are probably deciding, given the view of how long this is going to last and ultimately is it strategic to what they have in their go-forward position. But it's pretty quiet on that front right now, really no change.

I think it's -- to answer your question. I think there's still a wide bit of ask on the asset side. I think if you own the assets, you share the view that we have that it's going to get better in the future. But as we mention, we think it's probably three years of tough sledding and then when that -- let's say we're right, it doesn't go like a hockey stick in the third year and so there's a recovery period where things get priced back to what we think are more intrinsic value-oriented to what the value of storages and then it also matters where your storage assets are. So at this point in time I'd say we will continue to look at acquisitions, as Dean said, but we're not being overwhelmed with opportunities with realistic prices.

Great. Thank you very much, guys.

Thank you. We'll go to the line of Becca Followill with US Capital Advisors.

You guys have a built up a really nice crude and condensate position in the Eagle Ford and at the same time we keep seeing industry and your forecast continuing to increase on growth expectations for crude and condensate. Are you guys where you want to be, or do you see more opportunities in the Eagle Ford?

I think we're tracking -- clearly, when we raised our production forecast from 1.2 million outlook to 1.6 million we're pretty bullish on the area, obviously, and we had entered it with a view that it was going to be very attractive. I think it's going to take a settling-out period. Right now the infrastructure that's already being constructed or is constructed is trying to -- producers are trying to catch up with it from a hook up. There's other issues, Rebecca, as you imagine, because you've got it to process the gas. The amount of gas that's been flared or vented out there right now is fairly significant and there's a lot of liquids associated with that. So I think it's -- right now if you just simply look at the projects under construction versus the near-term forecast -- near term being next three or four years -- there's probably more than enough pipeline capacity either built or under construction to handle that. And we'll get a few more cards. It doesn't really benefit anybody to go ahead and assume that the ramp-up continues at the same pace without interruption. Historically it's just never done that. So I think what we'll do is continue -- we've got, I think, one of the best if not the best position out there that we'll continue to build off of and we're connected to the right markets -- Three Rivers, Corpus, as well as Houston -- through our joint venture with Enterprise. So I'd say we're going to stay very active, but it's hard to say exactly right now what the best next step is.

Becca, we're also -- if you look at our capital forecast for next year, there's a fair amount of capital being dedicated towards gathering volumes into our mainline pipeline system. As Greg said, we think we probably have the mainline capacity but there's certainly opportunities to bring crude to that -- crude and condensate to that system.

Great, thank you, and then two minor questions. On your Supply and Logistics segment, the volumes are way up in fourth quarter for guidance on NGL sales, is that a just a seasonal thing?

It's largely seasonal.

Thanks. And lastly on the Facilities segment, you talked pretty quickly on some items in there, the volumetric gains in revenue and then a true-up for operating expenses, in total what do those items sum up to the benefit in the quarter?

Well, I think the capital true-up was probably met in the neighborhood, $10 million to $15 million, and then some of the non-repetitive volumetrical gains are probably in the $5 million to $8 million range, as well.

The aggregate of the items Harry mentioned was the bulk of the over-performance for the quarter.

So probably $15 million to $20 million in the aggregate. And on the operating expenses, as we mentioned other, if you average the two between the two quarters because, clearly, we were trying to -- as we integrate we're always going to be a little bit conservative and we basically over-accrued expenses and probably under-accrued on some of the capital stuff and we trued that up in the third quarter.

Great, thank you, guys.

We'll go next to Mark Reichman at Simmons. Please go ahead.

Thank you. Most of the discussion is rightfully centered on the crude oil markets but I wanted to ask you, within the Facilities group I know it got a little bit of a help from the additional capacity from the NGL business. Could you provide an update on the NGL business and how does that factor into your growth plans and your spending in '13?

Well, on the growth plans we are still formulating those projects. Like I said, we've given a range between $900 million and $1.1 billion and what think is fair to say is, obviously, when we acquired BP I think we only included about $200 million or less -- maybe even closer to $150 million -- of capital in our forecast for post-integration -- or post-acquisition. Mark, I'd say right now we're pretty optimistic that that number's going to be substantially higher in terms of capital project opportunities. How fast some of those can get implemented, whether it's of '13 or '14 or '15, is still being determined. Part of that's both logistically what can we do and part of it's commercially what can we support with commitments, whether it be from our own activities or from those of others. But I'd say we're pretty bullish on our ability to find high-return capital projects to build off of the asset infrastructure that we just completed, but we're not giving a specific guidance on how much that represents of the 2013 [rack] because candidly, we just don't know. We've got a bunch of projects and we always figure out how do you -- we always have 12 pounds of potatoes we're tying to fit in an eight pound sack because at the end of the day some of the potatoes fall on the floor.

Right. Well, just as you completed through or wrapped up your integration plans, where do you think you see the greatest opportunities in the NGLs and LPG's?

Well, clearly we've got -- I don't have the best answer to that one.

Well, I think if you look at where our assets are -- the bulk of our assets are, they're in Canada, in the [Fort Fast] area, Sarnia, those seem to be logical places where to develop our infrastructure capabilities.

Well, most -- are there most -- do you see most of the opportunity on the organic side, or do you think that would likely be investments made for acquisitions, bolt-on type acquisitions?

We're talking about organic right here. We're doing two things. One, we'll extract, we think, more value from the existing assets that we bought and then we'll actually have more organic opportunities around those assets. And in some cases that may stimulate a bolt-on acquisition or two, but we're not necessarily having a game plan to go out and make major NGL acquisitions to grow the business. We can do it organically from this point.

Right. Well, great, thank you so much.

And we'll go to the line of Selman Akyol with Stifel.

You'd made some comments regarding light sweet crude and saturation in the Gulf Coast and I was wondering, can you expand on that a little bit and maybe put that in terms of refinery capacity and the ability to consume light sweet crude?

I can try. We still import waterborne crude round the US of about, call it 6.5 million barrels a day. Of that amount about 2.3 million barrels a day is light sweet. Of that 2.3 million light sweet about 750,000 comes into the Gulf Coast, and that's down, Selman, from probably 24 months ago probably 1.2 million to 1.3 million barrels so we've already displaced quite a bit of light sweet crude out of the Gulf Coast. And just to put that 750,000 barrels per day in perspective, that's relative to total imports into the Gulf Coast area, probably about 4.8 million, so that leaves 4.1 million barrels of it is in the intermediate, heavy-type range. And our belief is that with increased volumes coming out of Cushing through pipeline connections, seaway, et cetera, Keystone, and through increased capacity in the Eagle Ford and in the Permian all trying to get to Houston that it won't take long before we'll actually have light sweet volumes in the Gulf Coast exceed that 750,000 import. And once you've done that now you've got an excess of light sweet crude in an area where people have spent billions of dollars trying to run intermediate to heavy crude. And so that's going to basically create a disruption in the market and you're going to be pricing against alternative transportation cost out of that area unless we end up with some relief on exports. The natural segue would be to go ahead and export the light sweet and continue to import the heavy that the refineries want, or to discount the crude such that it makes sense for the refineries to run the light sweet even though it's not as efficient for their refineries set up.

We have a fair amount of light sweet being railed into the Gulf Coast, as well, in addition to all the pipeline projects that Greg discussed.

All right, thanks for the color.

There are no further questions in queue from the phones.

If there are no further questions we'll go ahead and conclude the call. And again, we want to thank everybody for attending, especially those in the Northeast that have a lot of other issues they're facing, as well. So again, thank you very much.

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