Ladies and gentlemen, thank you for standing by. Welcome to the PAA PNG Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to our host, Mr. Greg Armstrong. Please go ahead.

Good morning. my name is Roy Lamoreaux, Director of Investor Relations. We welcome you to Plains All American Pipeline and PAA Natural Gas Storage's Fourth Quarter and Full Year 2011 Results Conference Call. The slide presentation for today's call is available under the Conference Call tab at the Investor Relations section of our website at www.paalp.com and www.pnglp.com. I would mention that throughout the call, we will refer to the company's by their New York Stock Exchange ticker symbols of PAA and PNG, respectively. As a reminder, Plains All American owns the 2% general partner interest, all of the incident distribution rights and approximately 62% of the limited partner interest in PNG, which accordingly is consolidated into PAA's results. In addition to reviewing results -- recent results, we will provide forward-looking comments on the partnership's 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 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 Reconciliations section of our website reconciles certain non-GAAP financial measures to the most directly and comparable GAAP financial measures and provide a table of selected items that impact comparability of the partnership's reported financial information. References to adjusted financial metrics exclude the effect of these selected items. Also for PAA, all references to net income are references to net income attributable to Plains. Today's call will be chaired by Greg L. Armstrong, Chairman and CEO of PAA and PNG. Also participating in the call are Harry Pefanis, President and COO of PAA; Dean Liollio, President of PNG; and Al Swanson, Executive Vice President and 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 will turn the call over to Greg.

Thanks, Roy. Good morning, and welcome to everyone. Let me start off today's call by briefly recapping PAA's fourth quarter and full year financial results. Yesterday after market close, Plains All American announced fourth quarter adjusted EBITDA of $471 million. These results exceeded the midpoint of our guidance range by $61 million or 15%, and we're $46 million above the high end of our guidance range. This performance is in line with the increased expectations we communicated in our December 1 press release. In comparison to last year's fourth quarter, adjusted EBITDA, adjusted net income and adjusted net income for diluted unit for the fourth quarter of 2011 increased 46%, 72% and 67%, respectively. These results and additional information are summarized on Slide 3. PAA's fourth quarter results were driven by solid performance in all 3 segments, with supply and logistics service being the largest contributor to overperformance. As shown on Slide 4, our fourth quarter results marked the 40th consecutive quarter that PAA's delivered results in line with or above guidance. As reflected on Slide 5, these results capped off a very strong year for PAA, as we delivered year-over-year increases of 44%, 72% and 73% for adjusted EBITDA, adjusted net income and adjusted net income per unit -- diluted unit, respectively. Additionally, last month, PAA declared a 7% year-over-year increase in our annualized run rate distribution to $4.10 per common unit. As shown on Slide 6, PAA has increased its distribution in each of the last 10 quarters and in 29 of the last 31 quarters. As reflected on Slide 7, during the remainder of today's call, we will discuss our segment performance relative to guidance, our expansion in capital program and acquisition activities, and our financial position. Throughout the call, we will address the drivers and major assumptions supporting our financial and operating guidance for the first quarter and full year of 2012. The financial and operating guidance for the full year of 2012 includes our estimate of the contribution from the pending acquisition of BP's Canadian-based NGL business based on an assumed closing date of April 1, 2012. We will make appropriate adjustments to our guidance, if the actual closing date varies materially from that assumption. At that end of the call, I will provide recap of 2011, a review of our goals for 2012 and our outlook for the future. We will also address similar information for PNG, as well as discuss the highlights of the modification and PAA's ownership of PNG. With that, I'll turn the call over to Harry.

Thanks, Greg. During my section of the call, I'll review our fourth quarter operating results compared to the midpoint of our guidance issued on November 2, discuss the operational assumptions in June to generate our 2012 guidance, and I'll discuss our capital program. Following my comments, Dean and Al will cover the PNG-specific information. Prior to discussing our results versus guidance. I want to point out that our fourth quarter results include the impact of $11 million equity-related cash compensation charge that was not included in our guidance. This charge is primarily associated with the increase in PAA's unit price and a modification in our outlook at the probability of achieving performance thresholds and outstanding equity awards. $11 million charge impacts the transportation, Facilities and Supply and Logistics segments by $6 million, $1 million and $4 million, respectively. As shown on Slide 8, adjusted segment profit for the Transportation segment was $160 million, which was $3 million or about 2% above the midpoint of our guidance. Volumes for the segment are a little more than 3.1 million barrels per day or approximately -- for 3.1 million barrels a day and were also approximately 2% above our guidance. On a per-unit basis, adjusted segment profit was $0.56 per barrel. Adjusted segment profit for the Facilities segment was $107 million or approximately $10 million above the midpoint of our guidance. Volumes of 86 million barrels were in line with guidance, generating adjusted segment profit per barrel of $0.41, which was above the midpoint of our guidance. Primary contributors to financial performance were strong performance at PNG, higher throughput fees and other ancillary fees at a couple of our terminals, as well as favorable performance to our gas processing assets. Adjusted segment profit for the Supply and Logistics segment was $200 million, approximately…

Thanks, Harry. My part of the call, I will review PNG's fourth quarter operating and financial results, provide an update on PNG's operations, and review our first quarter and full year 2012 guidance and our 2012 partnership goals. Let me begin by discussing the results we released last night. As shown on Slide 15, PNG announced solid fourth quarter 2011 results, including adjusted EBITDA of $33.4 million; adjusted net income of $22.8 million; and adjusted net income per diluted unit of $0.31. These adjusted EBITDA results were approximately $3 million above the midpoint of our fourth quarter guidance range. As shown on Slide 16, for the full year, PNG delivered adjusted EBITDA of $107.2 million, adjusted net income of $68.2 million and adjusted net income per diluted unit of $0.97. These full year results were $1.2 million above the high end of our November 2 guidance and approximately $1.2 million above the midpoint of our "beginning of the year" adjusted EBITDA guidance. Furthermore, we recovered our distributions paid during the year -- we covered our distributions paid during the year by 109%, retaining approximately $8 million of cash flow in excess of distribution. Distribution coverage for 2011 on a trailing or declared basis was approximately 101%. We are pleased with PNG's 2011 performance, especially considering these results were generated in market conditions that were much weaker than we forecasted at the beginning of 2011. I want to thank the entire PNG team for their contributions to these results. Operationally, we executed our overall 2011 capital program under budget and on schedule. Our capital expenditures during 2011 totaled $89 million, which was in line with the low end of our updated estimates last quarter. Among other things, these capital expenditures enabled PNG to place approximately 10 Bcf of working capacity in…

Thanks, Dean. Before I address PAA's financial information, I want to add some perspective from PAA's vantage point about the modification of PAA's holdings and PNG Series B subordinated units announced yesterday. I think the press release is fairly self-explanatory, and the details of the modification are included in the appendix to today's slide presentation. As summarized on Slide 23, this modification was made in recognition of the continued challenging market conditions that are facing the natural gas storage business, an evidence is PAA's long-term view for the natural gas storage sector. We believe the modification increases the value of the growth platform represented by PNG. It also benefits PNG's common unitholders by reducing the number of units on which distributions would otherwise be required to be paid in the case of distributions below the annualized level of $1.71 per unit. With fewer units getting distributions, lower aggregate levels of distributable cash flow or DCF, we'll be required to increase PNG's distribution up to the $1.71 level. For example, prior to the modification, approximately $4.7 million of incremental DCF of was required to increase the distribution by $0.01 from $1.43 to $1.44 per unit. After this modification, the amount of DCF required is approximately $840,000 or 83% less. Directionally, the same type of relative difference holds true at the pre-amendment Series B conversion benchmark levels of $1.53 per unit and $1.63 per unit as well. So while can't change the market conditions at PNG's basis, by implementing this modification, we are alleviating the potential structural impediment to PNG's distribution growth that enables PNG to translate any sustained improvement in operating results in the distribution growth visibility. I want to also point out that we have taken similar steps to modify the equity incentives that were awarded to PNG's dedicated management…

Thanks, Al. PAA delivered record performance for the fourth quarter and full year of 2011 and meaningfully exceeded our public guidance ranges, extending our track record, delivering results in line with guidance to 40 consecutive quarters or a total of 10 years. These results are a testament to the strength of PAA's business model and strategic asset base and the outstanding execution of PAA's employees during a period of strong fundamentals and favorable market conditions. As this type of performance would imply, PAA met or exceeded all of its 2011 goals. A report card comparing these goals with the appropriate performance metrics is provided on Slide 29. In summary, we delivered operating and financial results above the midpoint of guidance at all 4 quarters, delivering a total adjusted EBITDA that was $373 million above beginning-of-the year guidance. We executed a $530 million capital program on time and within budget and set the stage to invest $850 million or more in 2012. We completed $1.3 billion of acquisitions during 2011 and entered into a definitive agreement to acquire BP's Canadian-based NGL business for $1.67 billion. We delivered year-over-year distribution growth of 4.7%, while generating distribution coverage of approximately 145% and retaining approximately $365 million of cash in excess of distributions. It's quite a year. As we look forward, we believe industry fundamentals are favorable for PAA's business model and asset base. As represented on Slide 30, attractive crude oil and liquids prices, advances in drilling and completion techniques and the application of these techniques to various shale and resource plays have driven an increase in domestic production in multiple regions. In particular, nearly 50% of the U.S. rig count is directed towards going in 3 areas. The West Texas and New Mexico area, the Rockies and the Eagle Ford in South…

[Operator Instructions] The first question comes from the line of Brian Zarahn with Barclays Capital.

On your 2012 guidance for lease gathering volumes, you have about 108,000 barrel per day increase. Can you talk a little bit about where -- what regions you're seeing that growth? Is it mostly the Eagle Ford or...

Yes, it's Eagle Ford, Permian Basin, primarily. Western Oklahoma, a little bit.

Okay. Is the biggest driver the Eagle Ford, you assume?

Pretty well spread out. Permian Basin is a pretty good chunk of it, too. But yes, between the Eagle Ford and Permian Basin, those are the 2 larger areas.

Okay. And then on the new Mississippian lime project, can you talk a little bit about the cost you're assuming behind that? And is any of that capacity under contract?

It was -- there's not any contracted capacity on the line. It is supported by an area dedication with SandRidge. We'll actually be the first [indiscernible] of that crude and ship the crude on the line ourselves. We haven't disclosed the expected cost yet, Brian. We're still working on finalizing the laterals, but we have $60 million included in our capital program for 2012 on that line.

And are you planning to run this is as a proprietary pipeline?

No, it will be a common-carrier line.

Common carrier. Okay. Turning to distributions at PNG, if market conditions continue, what's your general view of potential increases in 2013? Is there potential for any modest increase or you anticipate being more conservative?

Yes, I think as Dean summarized in his comments, Brian, we feel very strongly about where we're positioned, certainly on a relative basis. But also on absolute, we're showing at the midpoint of our guidance, that we'd show 105% coverage. That basically means that we're basically around $5.5 million of excess coverage. And I think at the high point of our guidance, we're right at 110%, so you just double that. And then on the low-end, we'd be right at about 1:1. I think we're going to be cautious. I know we're going to be cautious as we move forward because again, this is a market that's been -- while we called early that it would get difficult, I assure you, we didn't forecast it to be as difficult as it actually has been, and there's still a lot of unknowns out there. Clearly, we could potentially get a benefit if production continues to increase and storage capacity doesn't expand. As Dean said, we'll probably test the limits of capacity, and that creates opportunities. But unfortunately, it creates opportunities on a low-price environment. What we really need is basically a demand increase ultimately to take some of that excess gas off the market. And you'll probably see some producer discipline, but if you decrease gas drilling and you increase oil drilling with associated gas, it's not as dynamic as you might expect. In closing, I would guess, I would just say, we tried to remove the structural impediment. As Al went through the math, it would have taken almost $5 million to raise it a $0.01, and now it only takes about less than $1 million to raise it a $0.01. So we certainly positioned PNG to be able to have distribution growth. The numbers that were forecasting would suggest that if we deliver and it's sustainable in the market environment that we see, that we have that capacity. We're just not providing any guidance because quite candidly, this is a market that's tough to call. So I would hate to turn around and do something that sounds wonderful for everybody. We raise the distribution the first or second quarter and then market conditions deteriorate worse, and that your next question on next phone call is, "Why you're doing below a one-to-one?" So I think where we're positioned right now is -- I think everybody should feel very good about our current distribution. They should feel good about the potential for increases either as the market conditions improve or we generate sustainable results. But I wouldn't want to guide you to a number I'm going to be explaining to you at the end of the year why in the prudent judgment that we used and that you will probably agree with, we didn't hit the target.

Fair enough. A final one for me and turning to PAA, given your expanding asset base and then a favorable backdrop with a rising crude production, do you think farther out, sort of mid-single digits or high-single digits or something that's a reasonable assumption for distribution growth?

We're -- we feel really good about where we're at. And as you look at the numbers and the sustainability of it, again, we're going to get the benefit in 2012 and 2013 of the capital we've already spent in 2010 and '11. And then we've got a lot of capital that we're spending in 2012 that should benefit 2013 and '14. So what we said last time is we're giving the specific guidance for 2012. We're saying we'll grow at 8% to 9% and still maintain a very high coverage ratio. And what we said is, is that you can abandon the 3% to 5% long-term guidance that we've given, but we haven't provided any specific guidance other than say that you should safely assume it's above 5%. I think capital market conditions -- and clearly, we've seen a market that can change rather dynamically. We went from a $27 Brent, WTI differential to $11 in about -- I think it was about 14 days. And so what I'd say is we've got plenty of cushion going out to sustainably increase the distribution at very attractive levels, above 5%. And as we continue to get our projects executed timely and get more visibility into how much momentum is really in this market, we'll provide additional guidance as we go through. But we think we're -- I'll say this. I think we're at least as competitive as the other large-caps, if not more so, both in terms of coverage and distribution growth potential.

The next question comes from the line of Darren Horowitz with Raymond James. Darren Horowitz - Raymond James & Associates, Inc., Research Division: I got a couple of questions for you on the Bakken. And first, just looking at the present Bakken crude prices right now, how much of an opportunity does that present for you guys?

Well, we've got a rail facility at Ross. We've got an unloading facility at St. James, so obviously, we are trying to rail as much crude out of the area as we can. I think that differentials are very favorable for our Bakken North project, which will ultimately be able to bring that crude back into the Patoka area at a much lower cost than a rail alternative, so it's definitely positive for us. Darren Horowitz - Raymond James & Associates, Inc., Research Division: Harry, does it ever make sense to move crude south, possibly down to Fort Laramie and then even further south? Or when you think about it, is the move really to get it to Patoka and then access that Northeast market? I mean, I guess it would seem to me that it as, kind of, pad utilization rises, refiners are seemingly forced to bid up Bakken barrel, so that's where you want to be, but I'd just love your perspective on that.

Yes. When we look at all the growth in Oklahoma and West Texas, we think that Bakken crude is going to have a higher value in Patoka than coming back down into Cushing. That makes sense? Darren Horowitz - Raymond James & Associates, Inc., Research Division: Yes. So in the spirit of being a bit more vertically integrated, looking at your assets kind of being between competitors 2 pipelines, how are you guys thinking about getting long-haul transport into that Patoka area and leveraging your storage footprint and greater optionality to really give producers more market options longer-term?

Our Bakken North connects them to Wascana, our Wascana pipeline, which is being reversed, and that connects them to Enbridge at Regina. So part of that project, we've got some modifications with Enbridge. That location at Regina is -- we come off Enbridge, so now we're going back in. So we'll go through Enbridge over to Patoka. Was that your question, Darren. Darren Horowitz - Raymond James & Associates, Inc., Research Division: Yes, it is. It would just seem to me that longer-term, you probably wouldn't want to continue doing that.

Yes. Darren, I think it's -- we're trying to get, in a perfect world, 5 to 6 years out, when we're making our decisions, as to not only what's going to take advantage of an opportunity maybe for the next 12 months, but what's going to be a sustainable opportunity for a number of years. I think the fact that we took a larger presence on East Coast with the Yorktown facility, the fact that we've expanded our rail facilities does probably address directionally your question of do we believe that there's new markets that need to be developed for that crude. When you compound that with -- and you got to look at multiple regions at a time because there's -- it's pretty dynamic. I mean, there's a pipeline reversal. Seaway, obviously, it's going to take some crude out of Cushing, take it into the Houston market, just about the same time that a fairly big amount of crude's going to come out of the Eagle Ford into that area. All of that crude or substantially all of it, at least that's been talked about certainly out the Eagle Ford and out of Bakken, is light -- very light crude, and so that limits your ability, quite candidly, to back out some of the foreign imports. I think there's, Harry, 5.3 million barrels of foreign imports into the Gulf of Mexico. But if you total up the light crude -- light sweet crude, the condensate even the medium sweet, that you – our candidates to be backed out then, it's only 1 million barrels a day of that 5.3 million. So unless you cancel long-term contracts for heavy sour and heavy sweet crude or you change the refinery configuration, you could end up with too much light sweet crude in the Gulf of Mexico. And quite candidly, since you can't export crude out of the United States, it's illegal, you may end up having to move that around to the East Coast on barge, and that sets a different bar, if you will, that you need to cover to then make rail competitive going in the back door. So I think when you look at our assets, I think you would see we're very aware of the dynamics you're talking about near term, but I think we're also well positioned to take advantage of it long-term as some of these things settle out. Darren Horowitz - Raymond James & Associates, Inc., Research Division: Yes. I appreciate the color.

Just to expand a little bit on what Greg said about rail. We'll have rail unloading at Yorktown. We'll also have a rail onloading facility that connects into our California infrastructure. So I think we'll have a lot of flexibility with the types of crude that we gather, and we'll have access to rail.

The next question comes from the line of Steve Maresca with Morgan Stanley.

My first question is on the Mississippian Lime. So it will be a common-carrier line, but initially, you don't have the commitments right now and that -- I guess, what's the plan going forward to get those timing? And are you guys still moving forward with or without shippers on that, I guess?

Well, keep in mind, we already have a lot of assets in Oklahoma and trucks and everything else. So we're going to be able to basically move certain of the crude we already touched over to our pipeline. We just reversed the Medford pipeline, reversed and converted it, and we're going to have 25,000 barrels a day of capacity. And also, I think we're 4 right now is what we currently have, so -- because we actually take some of the crude oil from the wellhead down to the best markets, we can put it on the pipeline. The other thing is I think it's a fair statement that while SandRidge does not have a volume metric commitment, they are committed to the pipeline with their acreage, and they're one of the largest acreage holders up there, and they're drilling like crazy. And so the volume may vary dependent upon the success of those results. But when we run our economics -- and recall that we used to be in the E&P business, so we can understand where minimum rates of return and "breakeven" economics are, we're pretty comfortable that if all stays in the $75 to $100 a barrel range, we're going to have no problem putting our crude oil in that pipeline. So you should know we're committed to building the pipeline, and we're not too worried about the volumes.

And just to expand a little bit on what Greg said with our existing pipes. Our existing pipes in Oklahoma and Kansas are full. We can't take crude today that's available for transportation. So this will help debottleneck some of our existing pipes as well.

And the advantage that we have with the Medford pipeline is that we're going to -- there's other completed projects out there, certainly, that we've heard of. We can be faster to market for a number of reasons. One, because we have about 2/3 of the right of way already would be parallel to our existing line. And then when it gets to Cushing, I'll just represent here, there's nobody better positioned to handle multiple grades varieties of crude oil there. And so as a practical matter, we think we are the transporter of choice. If somebody chooses to go a different way, they've got a different crystal ball than we have.

So following up there, so what does this mean for Cushing? You obviously have a line. It's in the process of getting reversed and to bring things down to the Gulf? What does this mean for Cushing market, whether it's respect to more takeaway potential needed and opportunities or I guess more storage needed?

Storage is a tough color, and I think there's plenty up there either constructed or under construction, but clearly, between the joint venture between Enterprise and Enbridge and the reversal of Seaway, they're going to be able to take a lot of pressure off of Cushing. And I think Cushing becomes again the preferred market and, its a conduit for different types of crude to go in different directions. There's just so much flexibility once you get it to Cushing. I think there is just going to be a kind of a breakthrough once we get the Seaway reversal. Do you agree?

Yes, well, there's so many dynamics at work here. You've got pipelines in the Permian Basin that are expanding capacity to the Gulf Coast directly. Like Greg mentioned, you've got Seaway to provide access to the Gulf Coast, so I certainly don't think there's any more tankage needed at Cushing. But due to this pipeline project growth in the midcontinent, I think most of the pipeline out there are in the process of being developed.

Yes, I think you'll see some additional tankage being built, and some of it is already is, in the Gulf area, the coastal area. And I think the issue may not be a volume issue when you talk about some of these bottlenecks. It may be a quality issue.

Okay. Do you worry at all about rates becoming pressured at Cushing?

We always worry about everything. But yes, I think there's been a significant number of tanks that were built in Cushing, in some cases, not necessarily driven by anticipated wave of volumes but simply contango possibilities. Some of those leases will come back to market in the next 4 or 5 years. And dependent upon what the market is when those leases all come up for renewal, it could put pressure on the market. I do think we take great comfort -- and I've used the word "great" -- comfort in the fact that our assets are operationally the best positioned in Cushing, and we're not a contango play facility. We are a facility that you can do anything you want to, including contango play. And I think that the true users that we like to have as customers understand that, so I think we'll always have an advantage. But if too much tankage is up there, will it put pressure on rates? Absolutely. Will it hurt us as bad as somebody else? Not a chance.

Okay. Final question. You -- Greg, you talked about 2012 guidance incorporating favorable market fundamentals not as favorable as 2011. How do we think about that in terms of quantifying what that means in terms of what you're thinking? Is that just margin per barrel? Is it something you're thinking about from a WTI-Brent discount? Like, what is favorable but not as favorable on a -- if you can quantify?

Yes. As you might expect, we don't do this extemporaneously, so I was reading a little bit from my script and I even screwed that up. But there's really 2 issues: one, the favorable market fundamentals -- and we're talking about volume [indiscernible] push-driven, supply-driven markets. We think that's going to be as favorable or more favorable in 2012 than it was in 2011. That's what I call the fundamentals part of it. The second part of that issue was in 2011, we had very favorable market conditions, which was a combination of, in certain areas, very attractive basis differentials and, early in the year, very attractive contango market opportunities. And those are things that can become very transient. As you recall, we talked about the WTI-Brent differential being $27 at the end of October. They took Gaddafi out and then Seaway was announced and in a very short period of time, we went from $27 down to $11. Today, I think we're back out around $18. So I don't know how to predict those. I can't -- we can't put that into our model and say, "Let's forecast this is going to stay $11," or "It's going to stay $18," or "It's going to stay $27." But if it shows a lot of volatility and it shows that range going from $11 to $18 or $11 to $27, we'll make more money in 2012 than we're forecasting. But we don't forecast those types of what I call favorable market conditions. We are forecasting and believe in the favorable fundamentals are going to continue throughout 2012, '13 and '14. So I think I mangled my own script when I tried to describe those 2 differing conditions.

The next question comes from the line of John Edwards with Morgan Keegan. John D. Edwards - Morgan Keegan & Company, Inc., Research Division: Just following up on Steve's question regarding the margins here going forward, I mean, we were wondering, you guided in November $1.91 then you reported $2.43 on the margin. And to your point, we were looking at the spreads how -- they went down quite a bit each month. Now was -- that volatility, was that what was enabling you to achieve that margin? Because we were thinking, with the spreads going down, it actually might come in a little bit less. But in fact, you beat it by quite a bit. So just a little more detail on that would be helpful.

Keep in mind, we benefit from volatility when it goes, really, either direction. We have to allocate our assets right. And again, we've got some of the best guys that do that. But there are a lot of things that happen in our business model. We talked about the counter cyclical balancing and things like that and our supply and logistics, but I think, as Harry mentioned, we had very favorable butane margins that showed up. And again, many times, we -- what happens in the current month is not as important to the current quarter as it is probably to the next quarter. So a lot of that, we're going from, I think, fourth quarter EBITDA was $471 million. We're guiding to a midpoint of $400 million. So I think what you expected to see happen is happening, but it's happening now in the January, February, March market because we're basically transacting multiple months ahead of time. So we had probably already locked in the margins in the months that you were expecting to see impacted, but we didn't have -- there wasn't enough debt to market to take it all away through the first quarter. John D. Edwards - Morgan Keegan & Company, Inc., Research Division: Okay. And as far as capital spend going forward, you raised it from the last guidance by around $100 million to $150 million. And how much is that -- how much of that is BP and how much of that is other things?

Well, I think I can be pretty specific there. It's probably less than $50 million of it is BP and the rest of it is just other projects that had basically come to fruition since that point in time where clearly we didn't have -- when we had this call in November, we didn't have the Mississippian Lime line to a point where we could do that. We just signed that last week, Harry?

Yes.

Over the weekend. And so, John, some of this is just simply things that -- this is back to that portfolio of projects we were talking about when we said, "Look, some of them are going to make it, some of them are going to not, but we try to make our best guess as what will pull out." We've been pretty lucky here to ring the bell on a few, so we just increased our, basically, our budget to be able to accommodate that which we were able to land on the bay.

And we advanced a number of projects in the Permian Basin as well, too. John D. Edwards - Morgan Keegan & Company, Inc., Research Division: Okay. And then is that --- given how it looks like a lot of opportunities are opening up and, I guess, to Darren's question, a lot of things up in the Bakken, would 800 or 900 or so, is that a reasonable run rate here for the next few years, do you think?

I don't think we're ready to go much beyond the next year. I think several years ago, we made the comment we thought we were very comfortably in the 400 to 600 range. We probably migrated more up to the 500 to 700 range. So probably, 600 is a comfortable number, and certainly, some of these projects that we're announcing right now are simply going to carry over into 2013. So for the next couple of years, there's probably a bias towards being upwards of 700-plus. How long these industry fundamentals and what competition does cause you to get a little bit fuzzier when you get beyond the next couple of years. John D. Edwards - Morgan Keegan & Company, Inc., Research Division: Okay, great. And then Dean was talking about the gas storage limits being tested. I was just wondering if you could give a little more discussion on really what are the implications if those gas storage limits are tested. I guess, what does it mean physically? And financially, it can go different ways, and so if maybe you could talk about that.

Well, I heard too much of my voice already, so I will turn it over to Dean.

Yes, John, what could happen if you get to late-summer? I think, ultimately, storage fills, you see the pipelines back up and shut -- ultimately, if the pipelines fill up, you're going to shut-in production, and you're going to start -- see the price effects of that financially. You read the same articles out there we do. If you get that train wreck that happens, you could see for a time gas fall below the levels that it is right now. So I think physically, that's what happens. You're going to see pipelines fill up, ultimately, because storage is already full, and there's just no place for the gas to go. And you're going to see those wells get shut in. And then financially, you're going to see the impact of that in the absolute price of the commodity. John D. Edwards - Morgan Keegan & Company, Inc., Research Division: I was actually thinking gas storage rates. I mean, how does that impact gas storage rates?

I think on gas storage, I think what you need still, as Greg discussed a little bit, is you need demand growth long-term. We haven't been in that environment yet. I think short-term opportunities will prevail, but we -- you just have to see how they manifest themselves in the long-term rates. That's really what we look for. And although short-term opportunities are nice until they embed themselves into the longer-term rates and longer term view, I think it takes demand growth to overcome that prolific supply to get there. We'll just have to wait and see, but that's what it's going to take. I don't think it's -- I don't think that's going to have a impact, at least long-term, on rates until you see some demand growth. John D. Edwards - Morgan Keegan & Company, Inc., Research Division: So upward pressure on short term rates but really no impact on long-term rates?

Yes. There will be some impact on long-term rates because the marginal rate will be set by the marketing companies that are trying to trade that volatility. And so if you go back, John, to probably the -- in recent memory -- and recent's going to be a long time. If you go back to the late 80s, early 90s when we had what ultimately became -- referred to as gas sausage or what one would call the bubble, but ultimately, it became a sausage. And you could see rates -- or excuse me, you could see gas prices in the $2 to $2.50 range in the winter months. But you actually saw $1 spread between the summer to winter, even at low prices. Clearly, that's going to -- if you return to that, you could end up with some pressure on terms storage rates. What probably happens is the same thing that happened back then, too, is when somebody brought gas on in a cash market that they didn't have a place to sell it to, they had to take big discounts. And if there's enough of that, then you will influence people's beliefs as to what the extrinsic value they might be able to pay. And so then they start to, depending on what the supply of storage is on the market, they may push rates up a little bit on the margin, trying to capture some of those opportunities. But again, you're not going to get the same type of market that we saw in 2005, '06 and '07, $0.20 rate for solid storage was $2.40 a year. As a percentage of a $13 gas price, that's 20%. As a percentage of today's gas price, that's 100%. So you shouldn't be expecting it to go back to that level.

The next question comes from the line of Michael Blum with Wells Fargo.

Question on PNG. So on Slide 21, where you show the contracted and uncontracted capacity, should we assume that as you roll forward in time, you'll contract that uncontracted capacity? So if we rolled the slide forward a year from now, you'd still be at 90% for the first year, 70% in fifth year, something like that? Or are you thinking you might keep that uncontracted capacity for your own account effectively and just use that for merchant functions?

All right. Yes, Michael. When you look at -- as you go forward, we've -- you would tend to see because of the laddering effect of our contracts a shift in that. So in other words, in 2013, as we go to sell our storage, we would hope to move closer to that 90%, as we get to 2013, and then 2014, that 50% move -- number move up to 70%. So we're comfortable holding a little bit of merchant, depending on the market. I mean -- and I would call it in the 10% to 15% range. But we fully expect, as our contracts roll off, that we would kind of have that balance in there, is what you see.

Yes, Michael, if you went back, look at the same slide last year, I think it showed almost 100% leased for 2011, 80% leased for 2012 and 50% for 2013 in a period where we're still growing volumes. And you look at it today, and now, it looks about the same as it did before, actually a little bit better in certain areas. So I think what you're going to see is us continuing exercise the discipline of taking what the market offers. We've got attractive facilities. People want to contract with us. They may do it at a lesser price than we'd like to see long-term, but we're going to protect our distribution and protect the potential growth of it. And as Dean said, I think on the 10% to 15% that we manage, we're pretty comfortable that if we actually ever get to the position we think we can cause a turn in the market, 15% may grow to 20%. But we're not going to get silly and take a huge amount on it because, again, our goal -- we're an MLP. We're not going to paid home runs in 1 year and strike out the next. We're going to get paid to hit singles and doubles and triples game after game after game.

Okay, great. And my second question, just staying on PNG. Just from on M&A perspective, as the tough market conditions persist, do you -- are you seeing any change in terms of M&A opportunities where weaker players in the market or private equity backed are more willing to transact? And do you see any shift in the multiples that may be paid them? And what I'm really asking, do you think multiples could come down from where they've been for the last 2 to 3 years?

I think for transactions to occur, they have to come down. I think it's too early, really, to say whether people are getting realistic about this new environment. And to some extent, depending upon how much flexibility they had on their capital structure, that will determine just how quick they come to reality. But I think it takes a while. It usually takes, as I shared with folks [indiscernible] day, it takes longer for a crisis to occur that you think is inevitable -- it takes longer for it to happen, and then when it does happen, it happens much faster than you would have thought it could. So I think it's coming. It's just not here yet. I think PNG -- what we've tried to do at PNG and, as a sponsor, PAA, is position it where PNG is logical consolidator at this level.

The next question comes from the line of Elvira Scotto with RBC Capital Markets.

My question -- most of my questions have been answered, so I want to ask, on the Bakken area gas processing plant, is that included in the 2012 CapEx guidance?

No.

That's not included. And then just bigger picture, with the gas processing -- well, I guess, a couple of questions. I guess, going back to that one project, what's the plan for the liquids? Where would the liquids ultimately go?

We have a rail facility at Ross. That's one of the reasons why we like the location. And we like the location because of the supply of rich gas there as well. So propane and butane will go on a rail. Ethane has a couple of alternatives. One would be connecting to the Vantage pipeline system that would move into Alberta. There's also some of the BP infrastructure that actually could be tied into this facility longer-term as well.

Okay, great. And then just, I guess, bigger picture gas processing. How do you see this business evolving over time? How are you thinking about expanding it longer-term?

Well, I think we first entered the business in probably 2005 when we first got into the, really, butane with the processing and fractionation business. We expanded in 2009 with the acquisition of CDM Max. And we said then that we were pursuing a different business model than the typical percentage of proceeds or keep-whole arrangements. And we've been successful about being able to do that. We built several smaller plants, now these are some bigger plants that we're talking about. We built one last year at -- $135 million plant at the Seal. And so I think you would see us continuing to, especially in areas where there's -- we've got a footprint, where there's liquids-rich areas, you're expecting to see PAA there for both crude oil and the liquids part of it. And so it's really an adjunct to what we're currently doing. And then I think it has the opportunity from time to time because the expertise we have in-house to be able to step out a little bit and let maybe it lead us into an area where -- as opposed to just following us into an area through PAA. So whether it ever becomes so big that it's its own kind of segment, so to speak, part of that's just a function of how big PAA continues -- intends to grow, and we intend to grow quite a bit on the crude oil side, too. So they're going to have trouble catching up to be huge. But again, it's very complementary to what we currently do.

We'll next move to the line of Andrew Fairbanks [ph] with Sagatak Energy [ph].

Questions for you. First on the Mississippi Lime pipeline, recognizing all you've said about limits around what you can really say, I was just hoping you could characterize the ramp-up in volumes there. Do you expect to get to full capacity in 3 years, 5 years? Is there any sense you can give us on that? And is there some degree of trucking volumes you can move on to the line immediately?

Yes, well, definitely we would start with our Medford line. That came online 10,000 barrels a day. It's should be 25,00 barrels a day by July. That will be full, so there's quite a bit of truck lines that can be directed to the -- to that pipeline once it's in service. The line is probably, when you look at the cost of versus various size pipes, it's probably a little on the larger side because with the current volume, we've got a lot of expectation that there should be quite a bit of drilling, so we tried to position the line for very low option value by upsizing the line a little bit to capture potential growth in Mississippi. I don't -- I'm not saying here today that there's 170,000 barrels a day that could go on to it. But there's definitely enough to make the line viable.

Yes, I would point out, too, by having 2 lines there, one of which is, obviously, larger and has more capacity than the other one, we retain a lot of optionality if later on it turns out that we don't need both lines. We can convert -- reconvert the Medford line back into the natural gas liquid line and put the volume that's on it on over to -- consolidated under one line. So again, we have a lot of flexibility in that particular area.

Right, that's great. That makes sense. My other question was just around the Bakken and the Ross terminal. Are you doing any crude by rail shipments out of there currently, and when we do get to the end of the year, are you still thinking of that facility as sort of 1 unit train a day, kind of, 65, 70 MBD take out capacity?

We just started loading Medford's trains out of there, so we'll have unit train capability by the end of the year, but that's in line with our thoughts on the unit train volume. We already rail out of different areas in the Bakken, so this is just adding another take out point.

Right. And have you seen an uptick in demand from producers given the volatility we're seeing in upper-mid con crude pricing lately?

We are seeing continual increases of crude coming into our receipt facilities, but those volumes are escalating every month.

We're in the process of expanding our St. James facility be able to -- right now, we're at, what, 65,000 barrels a day, Harry?

We're taking about 80,000 or 85,000 barrels a day at St. James right now.

It will be all for account. That's what's coming in.

Right.

Then it will be able to go up to 120,000, so we're expanding our receipt capability at the other end, which should give you a strong signal that we're not worried too much about volume availability on our rail facilities.

Right. No, that's great. And then the offload terminals in California and Yorktown you mentioned, what size are you thinking for those? Would they be kind of typical refinery, 20,000, 30,000 barrel a day type sites?

Yorktown will probably be closer to 60,000 barrel a day site. It will have the capacity to do that. That's not to say that, that will unload that much immediately, but Yorktown should be in the range. The one in California might be a little smaller than that.

We'll move to the line of Selman Akyol with Stifel, Nicolaus. Selman Akyol - Stifel, Nicolaus & Co., Inc., Research Division: In terms of PNG and in terms of rates, just sort of industry-wide, can you guys put some brackets in terms of percentages on what you're seeing and how things are repricing out there? I mean, we know it's down. I'm just trying to get what it's looking like.

Well, no, not really. Selman Akyol - Stifel, Nicolaus & Co., Inc., Research Division: Okay. Fair enough.

There's some sensitive, I mean, commercial issues at hand there, but I will say, we have the best facilities that always command a premium rate, and that's not only for you, but for the customers that are on the line as well. Selman Akyol - Stifel, Nicolaus & Co., Inc., Research Division: All right. Then in light of the weak environment, can you guys discuss have your expansion plans changed at all in terms of adding additional capacity as you look beyond what you've got set for 2012?

In this market environment, Selman, we continued to bring on our low-cost expansion. We have no plans right now to drill new wells, but we continue smugging and fill the water to bring on those low costs. As we've mentioned in previous calls, that's about in the $3 million to $4 million all in per Bcf. And even in this environment, those are good decisions to make. I will say if the market does turn, we certainly are prepared and can bring a new cavern on in the 14 to 18-month timeframe, so we're well-prepared in either direction if the market does change. But our plan for the next few years is through smugging and and fill the water the low-cost capacity increases through that method. Selman Akyol - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then, Greg, in your closing comments, you gave a nod to your board and, specifically, one of the values that they had was being on the outlook, I guess, for potential negative developments. Can you expand on that and just maybe a little color on what they're focusing on?

I think it's just a fair statement. They've been through a lot of cycles as have we, and just -- it's always nice to make sure that we realize the difference between brains and a bull market. And I think we've got a board that's very engaged, understands the business and can serve as a reminder from time to time that says, "Guys, it's not going to be up and to the right forever." And so it calls us to basically think, in some cases, how could we make an offensive move but have the defensive fallback. And obviously, we've got a great board and a very supportive general partner that takes a long-term view and allows us to do that. And I don't think that's prevalent throughout the MLP space. I think sometimes it's driven by agendas that are different, and they're sometimes a little bit more focused in on what would the market offer up over the next 12 to 18 months, not what should we be doing for the next 5 to 10 years. And I think that makes us and a few others of the large-cap MLPs different is that we're here to build the business, and we've chosen to build the business in an MLP structure as opposed to, I think, in some cases, we compete from time to time against people whose business is to be an MLP, and they're trying to figure what they can stuff in it.

Seeing no additional questions at this time.

Thanks, everybody, for participating in the call and for your very insightful questions. And we look forward to updating you on the next call.

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