Ladies and gentlemen, thank you for standing by, and welcome to the PAA and PNG Third Quarter Results Conference Call. [Operator Instructions] And later, we will conduct a question-and-answer session. [Operator Instructions] And as a reminder, today's conference is being recorded. I would now like to turn the conference over to 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 websites at paalp.com and pnglp.com. I would mention that throughout the call, we will refer to the company by their 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 of 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 partnerships' outlook for the future. In order to avail ourselves with Safe Harbor precepts that encourage companies to provide this type of information, we direct you to the risks and warnings set forth in the partnerships' 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 Reconciliations section 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 partnerships' 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 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-answer 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 wish all of you a speedy recovery. With respect to PAA's third quarter results, we continue the 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 exceed the midpoint of our guidance range by approximately $92 million, due principally to strong results in our Facilities and Supply and Logistics segments. Current year results also compared favorably to last year's third quarter, as adjusted EBITDA, adjusted net income and adjusted net income per diluted unit for the third quarter of 2012 increased by 21%, 18% and 3%, respectively. Although it did not impact our adjusted results, our third quarter reported results included the impact of a noncash -- of noncash impairment charges 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 in Slide 4, these third result -- third quarter results marked 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%…

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 this segment of 3.53 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 of items that impacted the quarter included the first, we have 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 out in certain areas of 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 guidance, and a number of factors contributed to their 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 overperformance at PNG contributed to overperformance for the segment. The quarter also benefited from lower-than-forecasted operating expenses on the recently acquired BP assets, primarily due to some true-up adjustments related to the second quarter of 2012. Adjusted segment profit for the Supply and 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…

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 share of $0.25. A portion of the overperformance 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 a 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 3.8x, 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…

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 fourth quarter and full year of 2012. As detailed on Slide 17, our financing activities since 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 ratable cash raised closely matches our organic growth capital investments, and it is much less disruptive on the trading of PAA's units than the traditional overnight or 1-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 2.9x, and our adjusted EBITDA-to-interest coverage ratio was 6.8x. As you can tell from our very strong capital metrics, as a result of the continuous equity offering program and repaying 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 includes $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…

Thanks, Al. The first 9 months of 2012 has 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 3 quarters of the year, PAA increased its fourth quarter and full year 2012 guidance and remains on track to deliver a record year of performance. Looking beyond 2012, we furnished 2013 preliminary guidance that forecasts 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, it clearly underpins the distribution growth target we have established for 2013, while maintaining healthy distribution coverage levels. Furthermore, there is clear upside potential through our guidance if favorable market conditions extend beyond the first quarter of 2013. Finally, as a result of the partnerships' solid asset position throughout the most-active North American crude oil resource plays and it's proven business model, attracted by 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 detailed 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.

[Operator Instructions] We'll go to the line of Dan Horowitz at Raymond James. Darren Horowitz - Raymond James & Associates, Inc., Research Division: 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 tight market conditions mean in terms of how you're thinking about regional pricing spreads and grade quality differentials? Whether or not its WTI to Brent or Midland to Cushing, or even variances around Louisiana light sweet? I'm trying get a sense for how you all are thinking about spreads as more production and more pipe capacity comes online next year.

Dan, I mean, you raised 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 will -- 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 kind of dialed into our forecast. I'd tell you, we probably haven't taken full advantage of what we think could happen, but we're starting to give them some credit. And in fact, beyond the first quarter, we've assumed things kind of 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-Cush differential or a 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 frankly, I know what you're kind of 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. Anytime an area appears to be getting imbalanced, where takeaway 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 of differentials. And of course, we've got pipelines, trucks, railcars, barges, and a significant amount of inventory that we carry as well as terminals to be able to store more inventory that enables 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.

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, rail, on your pipeline volumes?

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

This one's relatively modest in terms of your volumes. But I guess, going forward in '13 and '14, you'll be participating a little bit on 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 see 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 the load and manifest trains. As I said, we'll -- by the end of the year, we'll be up to unit trains out of the Bakken.

Yes, I think, Brian, over time, it's fair to say pipelines are going to be the most efficient way to move crudes. Rail will be a competitor for those pipelines in a given area when those pipelines are going to inferior markets. And by that, they're 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 this has been -- it 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 TAD/FI refineries?

Well, in general, I think they're still focused in on potential for increased production from within California. And clearly, the resource plays, whether it -- in other areas outside of California that hadn't developed 4, 5 years ago when the project was started, and there's certainly been a focus in on the potential for increasing production in California both as a result of higher prices and also technology through the application of frac-ing and horizontal drilling in the 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, as providing an opportunity because right now, California is having to compete with Brent-based pricing on the Coast. Just the way -- the same way the East Coast is, and so rail becomes a part of the solution there. And as Harry mentioned in both in this call and prior calls, yes, we're increasing our participation in rail. We think, not only loading facilities are going to be important, but the most important part is going to be the unloading, the ability to get it off that unloading location to the market.

And then also in California, we've got Line 63 that we're -- we've got some work on that. So we got all the volumes for a portion of that corridor 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 L.A.

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

Just following up on the rail comments there. I guess, I realize you're not giving a lot of detail on the capital budget. But is there a lot of it for rail investments in there? And if there is, can you tell us kind of what areas you can get invested 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 got $1 billion of capital as kind of 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 I mean, they're just -- it's a build-out of existing facilities where we've got rail. Clearly, Yorktown, we're building -- increased the class there to go from manifest to unit trains. We've got additional work, we've got into Tampa and a few other areas, but...

But Tampa's in the DJ Basin. So we'll be able to load DJ Basin crude, taken to the East and West Coast, Manitou's right in smack in the middle of the Bakken, where it will 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 -- give out the details today.

For Christ's sake, he aggregated that, it's still kind of preliminary. So give him 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 is related rail.

Got it. That's helpful, thanks. And then, just thinking about the Permian takeaway capacity, I know you've talked before and sort of questioned about the sort of the need to go to the Gulf Coast. And we know it sounds like we have a maybe a potential project to get to the West Coast. I'm just kind of wondering how you're thinking about overall, the best solution for getting Permian crude out, and given that 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 on 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 then 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 BP assets. Can you maybe just 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 the third quarter combined, it's probably more reflective of annual run rate, probably the easiest way to say it.

As soon as we close, we got some true-ups and accruals and classifications, and so I think Harry's, kind of, it's probably best way to look at it.

Next, and 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 that now stand at 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, decade's a long time. If we'd had this discussion a decade ago, we wouldn't even be talking about the Bakken. So I think what's fair is that, of the kind of the big 3 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. And so, 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, I think if I call it 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 probably talking in the $13 to $14 range for rail depending on whether you're -- maybe $13 to $15 whether you're talking manifest or unit train. So we think rail probably has some legs with it. I think important is going to be -- it is -- with any industry, we tend to overbuild. So I think there's a potential for loading stations to get overbuilt. And the important thing is where you're going to take those once you get it loaded to, and the value will be in having unloading locations at the right markets.

I think if you just look broad picture at the Bakken, hard to imagine pipeline getting built to the West Coast. Probably, the only feasible offer of the East Coast is Enbridge's project, where they come into a superior and reverse Line 9, go to the Gulf Coast. It's hard to imagine the new pipe. There could be some pipeline conversions. And you're sitting here today with probably 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 move crude out of the Bakken area.

Yes, I think Harry's comment about converting existing pipe versus building new pipe is important. Because if you're building a new pipe, you're talking about trying to make a 10-year commitment that may not start for 2 or 3 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. Greg, I apologize for asking you to step all the way out in 10 years, but anyway, I think it was worth a try. Second of all, I mean, just where are you guys currently in terms of the number of rail cars that you do control? And that would be it for me.

In terms of well, I can kind of give you a neighborhood if you want...

Are we sharing that?

Certainly, it's around 6, halfway, through the -- by -- in 2013. Yes, well...

We should be, or 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 at about 700 to 800 more rail cars. I think it's 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.

We're going next to the line of John Edwards at the Crédit Suisse. John Edwards - Crédit Suisse AG, Research Division: Greg, some of my questions on rail have been answered, but I'm just curious on your outlook, what are you assuming for production, oil production next year?

I haven't added it up by year. We tend to look at it, John, more on region-by-region basis. John Edwards - Crédit Suisse AG, Research Division: Actually, it would be more helpful. I...

No, but we're not sharing that competitive reasons. But yes, I think it's fair to say we've 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 probably got more bullish about here recently has been the Eagle Ford area. I think, and I gave a presentation a while back to an Industry Day. I think our original estimate was we thought we might hit 1.2 million barrels by 2018. And I think we've 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, is 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 would 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 3. And so we think you can see some slowdown there. So we kind of 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 U.S. Gulf Coast area, in particular, light sweet crude by a significant amount. And so that's going to widen differentials out. So I realized I've totally avoided your question, but I assure you it's in our unitholders' best interest. John Edwards - Crédit Suisse AG, Research Division: No worries. Well, maybe if you could just add a bit of detail. What's your thoughts regarding production in the Bakken area? Can you share that?

Well, 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 think it's going to ebb and flow. I think if you just said, "What can we produce out of the Bakken based upon an assumed constant rig count and continued performance improvement?" Because they cut a lot of drilling time out of that area. They 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 mean, 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, it's a function of what the market conditions are, allow you to have the economics to allocate capital between basins. John Edwards - Crédit Suisse AG, Research Division: Okay, fair enough. The -- I guess, just kind of -- the look I was thinking on rail versus pipeline. I guess it was kind of asking Brian's question in different ways. When do you see pipeline pressuring rail, I guess? And I know you've already made a lot of comments on that. But I'm thinking, in particular, in the Bakken area.

Well, I said, we don't think in the near term, it's going to pressure rail a whole lot dependent upon what happens with the timing of those pipeline projects. I mean, there are several projects that are talked about but probably in the next 2 years, I mean, rail is going to be a critical part of that. That's why I kind of kept the decade comment down to a half decade. As you get to the end of that 4 or 5 years, it's just going to be a function of whether or not some of these pipeline projects haven't gotten built or not.

We'll go next to the line of James Jampo at Hype [ph].

Can you talk a little bit about the recent Rangelands transaction? You guys surely had a look at it. And would you have considered it not strategic or not priced well? Or any other reason why it might not fit with Plains?

James, I appreciate your comment there. You can assume 2 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 you at this point. I know you wouldn't want us to break a confidentiality agreement.

No, no. But is it the kind of asset that you would have liked to have had?

Keep in mind, we're building facilities out there already. So I mean, we've got our own infrastructure. We don't need to [indiscernible] infrastructures out there. And again, as I pointed out, it's -- loading's important. Unloading is probably more important.

We go next to the line of Michael Bloom at Wells Fargo.

Just 2 quick ones for me. One, I'm just trying to reconcile, I believe, Al, in his prepared comments, said that for your baseline, do you think a 1.1 coverage is sort of 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 sort of what I'm getting at is, is there upside to that distribution growth forecast even excluding -- yes.

No. I think a very operative word in Al's discussion was minimum in terms of coverage. And the way we look at it, when we price our cost of capital, et cetera, is we recognize is -- I'm preaching to the choir here, I realize. I mean, there's floors and ceilings on distribution growth. If you don't have any distribution growth, there's a yield ceiling since [ph] to show up. And if you have distribution growth, you're not going to necessarily get dollar per dollar benefit or point for 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 a great visibility from organic, not needing acquisitions, to basically being a 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 to where we think we're going to be able to grow our distribution, too. And I think we've calculated, the last time I looked at, I had to think we're just pre-split and 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 clearly, we have the ability to grow it faster. But would it actually translate into a better-trading yield or simply just increase the total return for that period of time? And on balance right now, we're comfortable in basically saying we would rather give you an extended view of a very attractive distribution growth than a 1-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 market. 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 sort of saying, uncle, and are more willing to transact? It 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'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, it's strategic to what they have in their go-forward position. But it's pretty quiet on that front right now, really no change.

Yes, I think it's -- to answer your question, I think there's a wide bid to ask on the asset side. I think if you own the asset, you share the view that we have that it's going to get better in the future. But as we mentioned, we think it's probably 3 years of tough sledding, and then one that -- let's say, we're right, it doesn't go like the hockey stick in that third year. And so there's a recovery period where things get priced back to where we think are more intrinsic value-oriented to what the value of storage is. And then it, also matters where your storage assets are. So at this point in time, I'd say we still continue to look at acquisitions as Dean said, but we're not being overwhelmed with opportunities with realistic prices.

We'll go to the line of Becca Followill with U.S. Capital Advisors.

You guys have built up a really nice crude and condensate position at 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 opportunity from the Eagle Ford?

I think we're tracking -- I mean, clearly, when we raised our production forecast from 1.2 million kind of outlook to 1.6 million, we're pretty bullish on the area obviously, and we had entered it with the view that it was going to be very attractive. I think it's going 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 hookup. There's other issues. Rebecca, as you can imagine, because you got a process, the gas, the amount of gas that's being 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 3 or 4 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, to 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.

In fact, Rebecca, we're also -- if you look at our capital forecast for next year, there is a fair amount of capital being dedicated towards gathering volumes into our main line pipeline system. As Greg said, we think it probably has the mainline capacity. But there are certainly opportunities to bring crude through that -- crude and condensate through that system.

Great, and then 2 minor questions. On your Supply and Logistics segment, the volumes are way up in fourth quarter for guidance on NGL sales. Is that just a seasonal thing?

It's largely seasonal.

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

Well, the -- I think the capital true-up was probably in that -- just like in the neighborhood, 10 to 15. And then some of the non-repetitive sort of volumetric 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 overperformance for the quarter. So it's probably 15 to 20 in the aggregate, and on the operating expenses, as we mentioned the other deal, you can kind of average the 2 between the 2 quarters, because clearly, we were trying to, as we integrate, we're always going to be a little bit conservative. We basically over-accrued expenses and probably under-accrued on some of the capital stuff, and we trued that up in the third quarter.

We'll go next to the line of Mark Reichman at Simmons. Mark L. Reichman - Simmons & Company International, Research Division: Most of the discussion is rightfully centered on the crude oil markets, but I just wanted to ask you, within this Facilities group, I know I got a little bit of a help from the additional capacity from the NGL business. Could you just kind of 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're still formulating those projects. Like I said, we've given a range between $900 million and $1.1 billion, and what I 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 and -- or post-acquisition. Mark, I'd say right now, we're pretty optimistic that, that number is going to be substantially higher in terms of capital project opportunities. How fast some of those can get implemented, whether it's in '13 or '14 or '15 is still being determined. Part of that is about, logistically, what can we do and part of it is just commercially what can we support with commitments, whether it be a from our own activities or from those of others. But I'd say we're pretty bullish on our ability to find a high return capital project to build off of the asset infrastructure that we just completed. But we're not giving specific guidance on how much that represents of the 2013 where I just -- candidly, but we just don't know. I mean, we got a bunch o projects and we always try to figure out how do we put -- we always have 12 pounds of potatoes we're trying to fit in a 8-pound sack. Because end the of the day, some of the potatoes fall on the floor. Mark L. Reichman - Simmons & Company International, Research Division: Right, well, just as you kind of completed through or wrapped up your integration plans, I mean, where do you think you see the greatest opportunities in the NGLs and LPGs?

Well, I mean, clearly, we've got -- I don't know how to best answer that one.

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

Or most -- are there -- do 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. I mean, we're doing 2 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 2. But we're not necessary having a game plan to go out and make major NGL acquisitions to grow a business. We can do it organically from this point.

And we'll go to the line of Selman Akyol with Stifel. Selman Akyol - Stifel, Nicolaus & Co., Inc., Research Division: You had 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. The -- we still import waterborne crude around the U.S. 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 light sweet, about 750,000 comes into the Gulf Coast, and that's down, Selman, from probably 24 months ago, probably 1.2 to 1.3 million barrels. So we've already just sliced quite a bit of light sweet crude out of the Gulf Coast. And just to put that 750,000 barrels in perspective, that's relative to total imports into the Gulf Coast area, probably about 4.8 million. So that means, 4.1 million barrels of it is in the intermediate heavy-type range. And our belief is, is that with increased volumes coming out of Cushing through pipeline connection Seaway, et cetera, Keystone, and through increased capacity in the Eagle Ford and in the Permian, all trying 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 that where people had 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, I guess, alternative transportation costs out of that area, unless we end up with some relief on exports, a natural seque 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 refiners to run the light sweet even though it's not as efficient for their refinery set-up.

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

There are no further questions in queue from the phone.

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.

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

Thanks, Keeley.