John Porter Alan S. Armstrong - Chief Executive Officer, President, Director, Chairman of Williams Partners GP LLC and Chief Executive Officer of Williams Partners GP LLC Francis E. Billings - Senior Vice President of Northeastern G&P Operations James E. Scheel - Senior Vice President of Corporate Strategic Development Rory Lee Miller - Senior Vice President of Gulf & Atlantic Operations Donald R. Chappel - Chief Financial Officer and Senior Vice President Allison G. Bridges - Vice President Frank Billings Randy M. Newcomer - Executive Officer

Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Faisel Khan - Citigroup Inc, Research Division Stephen J. Maresca - Morgan Stanley, Research Division Theodore Durbin - Goldman Sachs Group Inc., Research Division Sharon Lui - Wells Fargo Securities, LLC, Research Division Craig Shere - Tuohy Brothers Investment Research, Inc. Brett Reilly - Crédit Suisse AG, Research Division Rebecca Followill - U.S. Capital Advisors LLC, Research Division Carl L. Kirst - BMO Capital Markets U.S. Selman Akyol - Stifel, Nicolaus & Co., Inc., Research Division Heejung Ryoo - Barclays Capital, Research Division

Good day, everyone, and welcome to the Williams and Williams Partners First Quarter Earnings Release Conference Call. Today's conference is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to Mr. John Porter, Head of Investor Relations. Please go ahead, sir.

Thank you, Lisa. Good morning, and welcome. As always, we thank you for your interest in Williams and Williams Partners. Yesterday afternoon, we released our financial results and posted several important items on our website, williams.com and williamslp.com. These items include yesterday's press releases with related schedules and the accompanying analyst packages; a presentation discussing these results; guidance updates and growth opportunities with related audio commentary from our President and CEO, Alan Armstrong; and an update to our data books, which contain detailed information regarding various aspects of our business. This morning, Alan will make a few comments and then we will open the discussion up for Q&A. We also have the 4 leaders of our operating areas present with us: Frank Billings leads our Northeastern G&P operating area, Allison Bridges leads our Western operating area, Rory Miller leads our Atlantic-Gulf area and Randy Newcomer is here from our NGL & Petchem Services operating area. Additionally, our CFO, Don Chappel, is available to respond to any questions. In yesterday's presentation and also in our data books, you will find an important disclaimer related to forward-looking statements. This disclaimer is important and integral to all of our remarks and you should review it. Also included in our presentation materials are various non-GAAP measures that we've reconciled to Generally Accepted Accounting Principles. Those reconciliation schedules appear at the back of the presentation materials. So with that, I'll turn it over to Alan Armstrong.

Great. Good morning. Thank you, John. Well, first of all, our cash flow metrics for the first quarter remained strong and in line with our expectations despite a continued decline in NGLs. Earnings at WMB, however, for the quarter were impacted by higher DD&A, including an additional $17 million of noncash amortization related to the ACMP acquisition. But we were pleased with the 1.05 coverage at WPZ despite another 21% step down in NGL margins from the fourth quarter of '12 and now a 50% decline from the first quarter of 2012. Looking forward, we see some short-term painful but long-term healthy cross-currents as both the NGL markets and the natural gas markets continue to expand on the backs of low-cost supplies relative to global alternatives. The natural gas market right now is ahead as the demand decisions have already been made in response to an extended low gas price period. But the NGL demand side will also begin to respond but perhaps not as quickly and certainly to more limited options for market expansions. As a result, we see a couple of years where NGLs will be oversupplied and producer's response to natural gas price signals will be more -- or will be met by most people -- be slower than most people's expectations just because of the time it takes to set the flywheel rolling in these large-scale operations. Areas like the Marcellus and the Utica will be advantaged by the benefits of large-scale development because those major programs are already in place. For Williams, this results in great infrastructure investment alternatives to expand in the market, access for these large-scale NGL and natural gas values that still will be ready to deliver quickly against the positive market signals. So in the short term, the higher natural gas prices will be negatively impact -- will negatively impact our margins. But longer term, this will drive even more investment alternatives. So while our 62% growth in DCF from 2013 to 2015 is certainly impressive, we could see this improve even more if the forecasted pricing environment holds up long enough to spur more supplies and more demand because after all, our strategy is built around the volume throughput that will come with expanded markets with these great low-cost resources being developed here in North America. We're excited this quarter to announce the continuation of our 20% dividend growth at WMB through the 2015 guidance, and we look forward to sharing more about our large platform of growth capital projects that supports this continued growth in 2015 and beyond with our Analyst Day coming up here on May 21. And with that, we'll turn it over for questions.

[Operator Instructions] And we'll take our first question from Brad Olsen with Tudor, Pickering. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Could you provide maybe some kind of breakdown of what is driving the CapEx growth in the Northeast segment particularly? Is that the result of regulatory hurdles, labor, materials or another factor?

Yes, this is Frank Billings. The majority of the capital increase in the Northeast that we're seeing and forecasting for really '13 and '14 and a little bit of '15 is really targeted for additional capacity requirements to support the drilling programs for our customers in Northeast Pennsylvania. We're actually expanding market outlets to support those drilling programs and increasing our takeaway capacity to the current pipeline connections that we have, as well as setting up for Constitution coming on as well. The other thing we have is -- the other piece of that is we do have our Three Rivers investment in that time period as well. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And when you talk about increasing takeaway alternatives, is that focused more on gathering? Or is that -- is there a specific long-haul pipeline that you're delivering into more than you expected or where you're building more capacity?

It's spread out across the current delivery points that we have today. So we have our deliveries into Transco, Tennessee, Millennium, we'll have Constitution, and those are the primary ones we're going to continue to focus on. And that's the -- and those are the outlets that our producer customers are wanting us to focus on as well. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And is there an update at this point on Bluegrass, how the contracting of the pipeline is coming along? And if Bluegrass does proceed, do you believe that it reduces the demand for local market fractionation in the Northeast?

This is Jim Scheel. Bluegrass negotiations are going very well right now. We have operations, legal and commercial folks working to finalize the agreements. It's my hope that we'll be finalizing those some time during this month so that we can go out to customers with tariff proposals early next month. Going to the next part of the question, yes, I do believe that Bluegrass will provide a great opportunity for wide-grade [ph] product to move to the Gulf Coast in order to meet the customer demand for NGLs in the large-scale fractionation facilities in that area of the country Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And just one last question from me. In 2014, there was a revision to the Atlantic and Gulf segment EBITDA. It looked a little bit larger than just commodity impacts alone, and I was wondering if you could comment on that? And that's all for me.

Alan, do you want me to take that.

Yes, please, Rory.

Yes. Just a couple of things going on there. Effective March 1, 2013, we have set new reserve rates and rates subject to refund. And the main driver there was we wound up with a little lower rate base to work against than we were forecasting in earlier periods. We had a little lower maintenance capital spending and so that drove the rate base down, which brought that kind of forward-looking base down a bit. And then there is an impact on Gulfstar. We're probably looking at a couple of months, potentially, delay there, and that effect is kind of amplified because of the accounting treatment that we're using with the Marubeni buy end of the project. As you recall, we sold half of that project to Marubeni and due to the accounting treatment, it shows the full impact to segment profit, but the impact on DCF is only about half of that. And Don, if you -- you may have a little more clear accounting explanation of that, but that's it in a nutshell.

Just to follow up on Rory's comment, again, we consolidate the Gulfstar project, so we show 100% of it despite the fact that our ownership is 51%. And our partner, Marubeni's interest, shows up as non-controlling interest, so you see segment profit move down as we've pushed the startup of that project back by a quarter. But the net effect of that is about half of what shows up in the segment profit change because of the non-controlling interest change that offsets it.

And we'll take our next question from Faisel Khan with Citigroup.

It's Faisel at Citi. I appreciate the additional guidance on the dividend for 2015, but I just wanted to ask a few questions on those assumptions in order to get to that number for dividend growth for '15. I guess if I look at the analyst package and look at your coverage ratio for the dividend payout for '13 and '14, it seems like you have enough coverage. But it looks like that assumption is based on a very low cash tax rate. It's also based on ethylene prices kind of holding up where they are, and I guess it also assumes that ethane rejection kind of continues for the foreseeable future. I'm just wondering, what gets you comfortable that you have enough wiggle room through the -- over the next few years to increase that dividend all the way to 2015 by 20%? I mean, the cash tax rate looks a little bit aggressive, and the ethylene assumption also seems -- it seems decent now, but there doesn't seem to be a lot of wiggle room.

Faisel, this is Don. I'll just take the first part of the question on the cash tax rate and then I'll turn it over to Alan. But you're correct, our cash tax rate through '14 is fairly low. And even into '15, it's less than probably the long-term rates. However, we have a forecast that goes out well beyond '15, and we do account for the fact that our cash tax rate will be moving up over time. And despite that, we're comfortable that we have the coverage, the capacity and the underlying growth projects to sustain that dividend growth through 2015. And again, I think we feel comfortable that we have strong growth beyond. Despite it, we're not providing guidance out in that beyond-'15 period.

Faisel, I'll take the question on the pricing, particularly on the ethane and ethylene. At the WMB level, which I assume your question is pointed to relative to the dividend, don't forget that we do have ethane exposure, positive ethane exposure, in Canada that is not captured in a lot of that PZ analysis that we've shown in terms of our sensitivity of ethane to ethylene such that if you add back in that exposure -- now remember, that -- the way that contract is structured, we have a floor that's a cost of service basis for negative ethane. But when ethane goes positive, then that's long barrels that would offset that otherwise short position that we have against ethane. So at the WMB level, we're actually fairly neutral there. In addition to that, we also have the impact, and it actually showed up pretty significantly in these numbers as we went to full ethane rejection from our Overland Pass business, where we're showing full ethane rejection throughout this period. So even though that doesn't show up as direct commodity exposure, it's pretty significant in terms of its impact over this 2-year period. So if you really look at the full balance of our exposure there, I would tell you we're -- from a cash flow standpoint, we're pretty well neutral relative to that ethane assumption at the WMB level. And so -- and as to the ethylene and propylene margin, we're certainly showing that reducing by about 10% from what we saw here in the first quarter of 2013. So certainly wouldn't suggest that that's not without risk. But frankly, we're seeing a lot of pull through on the ethylene side right now, on the demand side for ethylene. So at this point in time, we think that's a sound assumption on our part.

Okay. And, Alan, just to make sure I understand the guidance going forward for '13, '14 and '15, the ethane equity sales that we saw in the first quarter and the ethane production numbers we saw in this first quarter, are we to assume that those numbers kind of continue with the same first quarter numbers kind of going forward, which would be a drastic short of reduction in volumes over the fourth quarter of last year and all of last year for that matter. So I just want to make sure I understand that number in the guidance.

That is an -- I will tell you no -- even though we've said we will expect our pricing is done on a -- in terms of what we put out, is done on an annual average basis, and I will tell you, it won't be that smooth. And there will be periods where we have recovery and there will be a short period in there as prices inch up, and then we'll see rejection turn around. So when we say full rejection, we mean that in the sense that the pricing signal on an annual average basis will keep that. But we'll see spotting. In fact, I think we had some periods of recovery here recently here in the second quarter as well. So we'll see periods where we go in and out of recovery and rejection. But we think there's plenty of supply to hit that bid very quickly out there in the market, and I think one of the things that's kind of reset that market a little bit from what we would have seen maybe 5 or 10 years ago is there's a lot of ship-or-pay kind of contracts out there such that the variable expense to a producer is higher than what it used to have been. So they're making a decision against the ship-or-pay contract, which is kind of lowering the point at which people will go into rejection. And we as Williams really don't have that. And so we're right on the edge there and really looking at variable expense with the exception of the little bit of impact, the benefit we get from the Overland Pass transportation. So I think that's keeping that pricing level down below where you normally would see it for -- to encourage ethane recovery.

Our next question comes from Stephen Maresca from Morgan Stanley.

My first question is just on the IDR waivers. Alan and Don, you had 1.05 coverage in the first quarter. What made you feel like you needed to do the IDR waivers through the year? And how much of this was just a reduction in price assumptions? Or how much of it was kind of your view that volumes are not picking up quite as fast as previously thought?

Steve, I'll take that. I would just tell you very clearly, the pricing is, by far, the primary driver for us on this. I'm actually encouraged, and I think there's a good chance that we'll see volumes respond even more positively than we have in our forecast. But I would say we're at a little bit of a cross-current here in the market where gas prices picked up. And yet, the producers -- we're not seeing that response from the producers quite quick enough. I think they're kind of looking at this pricing and wondering if it's for real or not in terms of this price pickup on natural gas, and they're not quite ready to put the capital back behind what might be a blip in price. So I think if that continues, that we'll see that. Nevertheless, I would tell you that, partially because of that response, we're showing higher gas price throughout this period, which is a big driver of that lower margin. And as we've said here in the second quarter, we watched butanes drop by $0.01 a day for almost 30 days in a row. And so I would just tell you, its hard to build a lot of optimism in that market, in that pricing looking forward, and we certainly don't have a good answer other than exports picking up some of that. We don't have a good answer because we continue to see the incredible amount of NGLs that are available in places like the Utica and the Marcellus and the Eagle Ford. And we just see those supplies continuing to roll in. And so yes, we've got expanding markets in the way of exports, but there's a tremendous amount of supply continuing to build here for the next couple of years. And we're going to need to see very large-scale solutions developed like the Bluegrass project to really provide big enough market access for these products.

Okay. And then I believe you mentioned, Alan, also on the podcast, just some of the lower segment profit guidance in '14, including some changes in in-service dates for projects. Can you elaborate what is driving a little bit of that?

Yes. I think the primary driver there for '14 was the Gulfstar project that got mentioned. And again, that just hit segment profit by the larger number, and you cut that in half when you get down to DCF. That's probably the largest impact project that we have for 2014, and I think that's really the primary driver.

Okay. And then final one from me, another thing you mentioned was being a little bit disappointed with the Ohio Valley cost environment, higher cost than had thought. Can you talk a little bit also about what is driving that? How you see that playing out over the next 6, 12 months?

Sure. I'll take that and Frank can fill in where I miss here. But I would just say, we have really poured into that. But I think one of the things that might -- some of the way that language came off, a lot of the cost increases we're talking about, just from an accounting perspective, is much higher depreciation expense. And so that's really one of the primary drivers of expense on that. But I would tell you that we are working very, very hard to get our operations in line up there, and we're really trying to not spare a whole lot of expense on that. We're certainly mindful to it. But there's so much value in getting that system up and running and getting it up and reliable that we are -- we are bringing in a lot of resources from other parts of the country and really working hard. That's a very high-margin business for us, as you can imagine, on one hand. And in addition to that, it's certainly a reputational issue for us as well in terms of serving the customers out there. And so we're working hard. There's a lot of issues to overcome out there as a lot of that system really wasn't built in a robust enough way to handle the variability that we've seen in production out there. And so we're working hard to overcome that. And so I would just say we're going to get there, and we're having to pour the coals to it on the expense side right now to overcome some of them.

And we'll move on to our next question from Ted Durbin with Goldman Sachs.

I just want to come back to the 2015 dividend. What is the coverage, by the way that you defined it, that you're looking for in 2015? I think you're at sort of 1.3 or 1.34 on '13 and '14, but what's your coverage on '15 that you're seeing?

Ted, we have not put that out yet. We'll put it out on Analyst Day. But we're comfortable we have more than adequate coverage in light of the assumptions that are embedded in our forecast. And again, we didn't put out all of our '15 detail and keep you interested and coming to our Analyst Day in a couple of weeks.

Got it. I will be there. Just on Bluegrass again. I'm trying to understand the mechanics of kind of how -- the contribution that we'll get from Boardwalk. As I understand it, they'll contribute the pipeline, you'll contribute the cash. Is there any kind of crossover where, on capital or whatnot, they need to participate? Maybe walk us through that. And then also, this idea that ATEX, the enterprise line, might run more than just ethane, how do you see that impacting the Bluegrass pipeline?

Well, I'll start with the first question. Again, this is Jim Scheel. The anticipation right now is that Williams and Boardwalk will be 50-50 partners in the Bluegrass pipeline. Boardwalk will contribute part of Texas Gas that will have a value in the joint venture. Williams will true up through capital contributions for new construction. We'll be equal owners throughout the pipeline, as well as fractionation and storage facilities. To the extent there's customer demand for a export facility, we'd also anticipate sharing ownership in that on a 50-50 basis. That's the expectation today, and that's what we're working towards currently with them in those negotiations. As far ATEX going into additional products, actually, we would support seeing some of those opportunities to provide clearing for near-term liquids out of the Marcellus to meet customer demand. So I won't speak for enterprise, but that would be something that I think would help the market in the Northeast in the near term.

Got it. That's helpful. And then maybe just a big-picture one. It sounds like you have a lot of great growth projects, a lot of capital going in. Is there any sense that you feel capital constrained at all? I'm just wondering if there's projects anywhere that you might be turning down, maybe the pipeline into Florida that folks are working on? Just kind of how you're thinking about how much capital you have available relative to the opportunity set?

Well, we certainly are in a position to allocate capital, and we consistently do. And I would just tell you, we're very wary of risk as we do that. And so I would say we're allocating on a risk-adjusted return basis, and that's -- it's a good situation to be in. But we certainly are in a regular process of allocating capital and turning down alternatives that are put in front of us today, which are above our current cost of capital on one hand, but on the other hand, we've certainly loaded into our equity pretty heavily last year, and we've got such a great set of projects that provide so much value if we execute on those, that anything that can get in the way of that kind of value being realized is something that we're going to guard against pretty heavily.

We'll take our next question from Sharon Lui from Wells Fargo.

Just wondering if you could talk about, I guess, the decision to undertake Bluegrass at the WMB level and whether you envision this project to, I guess, generate primarily fee-based cash flows that would be appropriate of the drop down to WPZ some point in time?

Sharon, this is a Don. I'd just say that we felt that WPZ had a pretty full plate in terms of projects to develop and finance and that Williams had some excess cash flow, and the Bluegrass development was a good place to put it. So clearly, it's a perfect drop-down candidate, or it could even be jointly developed in time. But that was really the thinking around the decision to at least initially fund that at Williams.

Okay. And then I guess just looking at the cash balance that you guys have and the projected -- the excess cash flow at WMB, do you envision, I guess, any equity requirements to fund CapEx at that -- the WMB level right now?

Sharon, there's no equity requirements contemplated in this plan that we put forth, but we wouldn't speculate as to what could occur. But again, I think as Alan mentioned, we're -- we have a vast array of opportunities. We're allocating capital very carefully, looking at risk as well as strategic value and near-term value as well in deciding what to fund. So it'll be based on the facts and circumstances and what comes forward.

Okay. And then if you could just provide some color on the operational issues experienced at Ohio Valley and how that's being resolved?

Sure. This is Frank again. Right now, we're really working to debottleneck the system with some near-term projects to kind of get some -- take some quick wins. Really, we're beginning to implement our long-term operating philosophy for the area that really focuses on removing the fraction of gas stream that wants to be liquid under the conditions we're realizing in the gathering system. We're still going to move those hydrocarbons to Fort Beeler and Oak Grove, but we're going to pull them out of the gas -- gathering line and put them into our liquids line and then handle the separation and product upgrading at those central facilities at either Oak Grove and Moundsville. The primary benefit that we're attempting to do is remove those liquids that are pooling in the line and driving up the operating pressures of the system, to the point that the liquids are curtailing the volumes. Another significant benefit of the change in philosophy is really a significant reduction in our pigging activity, which has been impacting our reliability but also creates a lot of operational complexity. As an example, we're going to get operating expense improvement as well out of that because today, we probably pig that -- pig those systems 3x a day, and with these changes we'll be able to do that potentially once a month. So we'll have significant reduction in those things that could impact our pressure. But what we find is when we pig the system today, we don't get very lasting benefit given the operating conditions. And the other thing that we're really setting up for. And you've got to remember, that system has only really been out there 12 months or a little over 12 months, but we have a wide variety of temperature and pressure that we see over a calendar year. And what we want to do is set up a system that we feel we can operate safely, consistently and reliably 365 days a year. So we feel like we've got the right path forward, and we're going to begin to implement some of those significant changes throughout the summer months.

We'll take our next question from Craig Shere with the Tuohy Brothers.

A couple of quick ones. Don, did I see correctly that you all are guiding to slightly higher cash tax rate expectations versus the fourth quarter guidance? And what's driving that? And then, Alan, I had a quick question about the IDR forgiveness after that.

Yes, Craig, I think there was a very minor change in cash tax rate, and that's usually just a function of CapEx and taxable income. So I wouldn't read anything more into it than that. So it's just a tweak based on all of the other changes we made in our forecast.

Okay. And, Alan, on the IDR forgiveness -- I mean, frankly, as a onetime event, as you fill in for commodity margin with your huge fee-based growth CapEx pipeline, a couple of hundred million dollars as an NPV is irrelevant on a pretax basis. The question though, would be is, is this really a onetime event as you are guiding to just over 1x, 1.03x, I think, in 2015 PZ coverage? Or could you envision a circumstance where this might have to be repeated?

Well, I think you could certainly describe the time where we might repeat it if we saw conditions occur, but that's certainly not what our plans suggest right now. And I think we have a fairly conservative plan out there. I think it's really just the result of the amount of heavy investment that we're going through right now on the capital side to take advantage of all these great opportunities. And so we are very much investing into what we think is a great strategy and -- but that obviously has required a lot of equity issuance at WPZ to fund all that, and that certainly put a lot of pressure on that coverage. And you couple that, of course, with a rising gas price and drastically lowering NGL prices, and that's the circumstances we find ourselves in for 2013. None of that, from my perspective, overshadows the great growth prospects that we've got going on in the fee-based business, and I think our effort here is just to bridge into that more fee-based model that we're moving to. And so I think in the future, there will be less variables as we become less and less reliant on the NGL margin. I think there'll be less variables that would drive us or require us to do that. So I think that's the way I would answer that.

Craig, I -- this is Don. I'd just remind you and the others on the call that, again, Williams owns 68% of the LP units and the IDRs. If you look at our guidance, we enjoy 73% -- and I think of the cash flows out at WPZ in '13. And I think it goes up to about 76% by 2015. So the amount of IDR reduction that's given back to others is, call it, 25% of the total 200. So really, the lion's share of that is really staying, and to the benefit of Williams, it's just putting it in a different pocket.

We'll take our next question from Brett Reilly with Credit Suisse. Brett Reilly - Crédit Suisse AG, Research Division: Can you just add a little bit more color on the OBM lower volume assumptions more in the '14, '15 time frame, recognizing the issues you face today?

Sure. When we look at what's going on in '13, I think if you look back at some of the producers behind our system, they've openly said that they're scaling back 2013 drilling behind OBM as a result there, in response to the current operating capacities that we have there. There's still probably $100 million a day of volume that we're going to unlock over the next 4 to 6 months that we feel like we can bring to bear. But we really feel that the producers are really focused on the drilling programs for 2014 and '15. And given the things that we're doing up there, I think we're going to allow the producers and Williams to get to the levels that we've previously forecasted. I think in '14, our volume projection's not off that far. And I know we have a little bit of a step down in '15, but I really think that's less -- that's probably less a response to known information. I think it's really just when we try to just project what we think the producers can actually do out of that area and given their volume profiles, we're really just trying to forecast more of what we see the activity being. But really, we're going to get out of -- we know we're going to have reduced volumes in '13 for the known things we have, but we feel like we'll have the system capable of moving the volumes that we've had in our previous forecast, and I think we've stayed pretty close to that level in '14. Brett Reilly - Crédit Suisse AG, Research Division: Okay. Got it. And with the additional capital being spent in that area to resolve some of the bottlenecks today, is there an opportunity at all to recover some of that cost? Or is this all incremental capital just to get or satisfy the current contracts?

That's a good question. And actually, what we're doing is we want to make -- we do have to do some of these things to make certain that we stay in compliance with some of our current contractual obligations for pressures at some of our field receipt points. But we have had some discussions with producers to looking at a value trade that could either be some -- maybe some acreage that is currently not dedicated or some other ways to get some improvements in revenues as a result of the improved level of services that we're going to see out there. Brett Reilly - Crédit Suisse AG, Research Division: Got you. And then maybe looking to the Western part of the portfolio, any update on recontracting some of those commitments you have out there so that it's more fee-based versus commodity-based?

This is Allison Bridges. Certainly, we are proactively negotiating contracts with producers as they are coming due. And I think that they are interested in moving away from pure keep-whole deals. So we are looking at different ways of contracting, whether it be fee-based or based on price of gas or other items. Brett Reilly - Crédit Suisse AG, Research Division: Okay. And then last one for me, the $2 billion bump in your growth capital opportunity set at the MB level, is that really just a function of Bluegrass? Or is there a few other moving pieces within there?

Brett, this is Don. I think there's quite a few moving pieces. I think the biggest change is the expansion of the scope of the Bluegrass system to include, I think as Jim described, fractionation storage and export.

We'll take our next question from Becca Followill with U.S. Capital Advisors.

Back on the cash on Page 79, the 2014 ending cash balance of $308 million at WMB level. How much of that is Canadian and how much of it is domestic? And then just along with that, with the Bluegrass project expected to come online in '15, I would expect a significant amount of CapEx in '14. So how do you kind of bridge that gap at the MB level?

Becca, the bulk of that cash is Canadian cash. How do we bridge that gap? Well, it'll certainly be from capital raising. And it could be debt, could be equity. We'll determine that when we finalize our joint venture agreement and officially sanction the project.

Becca, a couple of things on that capital I don't think we've disclosed. I think Jim took a question earlier around Boardwalk contributing to the pipeline and us contributing capital, that's not an accurate representation at all of the funding situation there. And I think the question was that -- Jim didn't say that, but that was what the question implied. And so there is a contribution of pipeline, but there's -- and there's some recognition of that in value. But the sharing of the capital obviously is a lot more easily split on the pipeline. As well, I would just say a big chunk of that -- we'd love to be in the field constructing in '14, but I'll tell you, more likely, most the construction dollars will actually be in '15. And the project is scheduled to come on very late in '15.

And then on the Northeast, the segment data shows I think a loss of $9 million in segment profit, and the guidance is $100 million for the year. Can you talk to us about how that ramps up? Is it ratable to get to the $100 million? Or is it more back-end loaded?

I guess I'm not -- I need to see -- I'm not quite certain of the information. Are you looking at...

Just looking at the first quarter versus your annual guidance.

I'm looking at the adjusted segment guidance within the PZ first quarter data book that's on Page 5. It shows guidance for Northeast G&P of $100 million for the year versus -- sorry, I've got so many pieces of paper around here. I think the first quarter was a loss of $9 million.

Okay. Let me see if I can get that in front of me. Why don't we take the...

And then while you guys are looking then, Geismar. In your call, your podcast, you talked about cost overruns at Geismar. Can you quantify how big those are?

Well, I don't think we have disclosed that. I would tell you it's still a little bit of a moving target at this point. But the -- what we do know is that some of the estimations of the amount of steel and amount of wiring and so forth came in at a higher level. So you can see on Page 61 there, you can see kind of the new range for that. But I would tell you, we are pretty far along on it in terms of the project itself and have a very good idea of the required additional materials and labor on that. And so that's reflected in there. But I don't think we've disclosed the actual amount on that. But again, you can get a very good feel for that on Page 61 in terms of the range there.

Sure. And to your question on the first quarter versus the year guidance, this is Frank again. I think what you're seeing in the first quarter is we had some slip issues, and we also had the rupture in the -- on the pipeline system in the Ohio Valley that hit some of the first Q guidance. But if you look at our businesses up there, other than the kind of the -- what we're experiencing in OBM, our businesses in Northeast Pennsylvania around our Susquehanna County Supply Hub assets as well our LMM businesses are performing pretty well. And we should be seeing good cash flow and segment profit coming out of those areas. So it's not back-end loaded. We should see it start to come back quarter-to-quarter over the rest of the year.

And then the last one is on IDR support. You talked about up to $200 million. That's really going to fluctuate depending on how much WPZ needs. So as we model that, do we look to you guys wanting to target throughout the quarters a 0.9x coverage? Or what kind of coverage would you give support to? Or what kind of -- how much cash to get to what kind of support level on the IDRs?

Becca, I think we've maintained some discretion over that. But we have 1.05 coverage in the first quarter. We'll look at what the second quarter results are on a year-to-date basis, as well as our outlook for the balance of the year and we'll make a determination. I wouldn't expect that necessarily we'll -- we won't try to put each quarter exactly where we would expect the full year to be, but we'll look at kind of year-to-date actuals, as well as the outlook for the year in determining how much to waive each quarter to get to the full year effect that we are looking for.

The $200 million only applies to '13, not to '14. Is that correct?

It is for the next 4 quarters. So it does -- it would be available. As you can see right now, we're not forecasting that we would need that in '14, but it is available.

Yes. Our guidance includes a waiver for each -- well, for the next 3 quarters. So if you look at Q2 through Q4 and the -- the actual payment for Q4 would extend into early '14. That's what's in our guidance model. However, the commitment is up to $200 million over the next 4 quarters, and we're targeting a 0.90 coverage ratio for 2013. And again, we didn't model any direct waiver beyond the next 3 quarters, even though we mentioned 4 quarters potentially.

Our next question comes from Carl Kirst with BMO Capital.

I think most of the questions here have been asked, but maybe just a couple of cleanups. And first, just to clarify, the projected spending on Bluegrass, that anticipates the 50-50 structure? Or is that being showed more 100% at this point?

It's in the 50%, Carl, but it's not in our guidance. It's only in the disclosure of projects that are beyond the guidance set of projects.

Okay. And then lastly, if I could just clarify, and appreciate the extra information on Gulfstar. This is with respect to 2014 WPZ guidance. Is it possible to clarify -- maybe Gulfstar is the only major project of note, but is it possible to clarify of the reduction in 2014 segment guidance and -- so understanding this is segment, not the DCF, how much of that came from the collective shift of in-service dates?

I'm not sure I have that. This is Rory, I'm not sure I've got that. If I had to guess, I'd say it's around half of it. And then the other biggest driver would be the other item that I mentioned about going through a rate case and our reserve rate and just dealing with a little lower rate base. But the Gulfstar project is going extremely well. I was down there last week and looking at the hull. The project looks fantastic. It's, like a lot of these projects, very complex and we think it could be a couple of months' delay on there. So that's about half of that change for 2014.

For 2014? Right.

Right. And then after that, of course there's no effect. There's no impact to any of the revenue streams coming off then.

Our next question comes from Selman Akyol with Stifel, Nicolaus. Selman Akyol - Stifel, Nicolaus & Co., Inc., Research Division: Most of the questions have been asked. In terms of Geismar, do you have a turnaround scheduled for this quarter?

Take that, Randy.

This is Randy Newcomer. We are -- right now, we're planning -- we're finishing up the detailed planning around the turnaround and the integration of the expansion. That will happen -- the tie-in of the expansion will happen during the turnaround. Right now we're anticipating bringing the plant down for maintenance and for the tie-in of expansion latter part of August. So it'll be a third quarter kind of event. Selman Akyol - Stifel, Nicolaus & Co., Inc., Research Division: And how long would you anticipate being down at that time?

We're planning -- right now, it's looking like -- and we have it in our forecast at about 50 days down. Selman Akyol - Stifel, Nicolaus & Co., Inc., Research Division: And then also in the quarter, in terms of production given the strength of margins, I think you were at 246 million pounds this quarter compared to the prior quarter of 261 million pounds. I was -- I would have thought you'd be a little higher than that given the strength in the market. Any comment there?

Yes, a couple of things. One is that if you'll recall, the price of propane was down very considerably in the first quarter, and propane was actually the preferred feedstock during that time. And so we ran heavy on feed, which makes less ethylene, makes more propylene and actually higher profitability. So that's part of the reduction in the volumes in the first quarter. The other one was we had some furnace issues that kind of kept us one-furnace short for most of the quarter. And those have since been resolved. Selman Akyol - Stifel, Nicolaus & Co., Inc., Research Division: And then just more of an industry question, I guess we've been hearing that ethane rejection has been running at about 175,000 barrels per day. Does that seem like the correct number? Could it be higher than that from what you see?

I would say from the vantage point that we have, the areas that we have, I would say that's probably fair of the ethane that's positioned to be recovered today. Obviously, if you included all the ethane that's being rejected up in the Northeast, it'd be considerably larger than that. But I don't think anybody is really counting that because it hasn't been in the market previously. But I do think that looking -- if you track propane volumes and then track those relative to ethane volume, a pretty good idea even though -- as people reject ethane, as I'm sure you're aware, it does lower propane recoveries a little bit. And so I think that's a good indicator. But I would say from our vantage point that 175 is probably in the ballpark. It might be a little north of that, but that's probably a pretty close estimation. Selman Akyol - Stifel, Nicolaus & Co., Inc., Research Division: All right. And then finally, just for clarification purposes, you guys talked about your forecasting based on ethane rejection. Is that at the same level going forward for the next several years? Or do you have that declining in your forecast?

No, we have the same -- really, when we estimate that for us, we're basically just looking at our plant economics and our variable cost economics and determining what we're going to do, obviously not determining what the whole market will do. And as I mentioned earlier, I think there's a lot of contract structures out there where there might be a percent of liquids contracts where the producer might be -– or sorry, the processor might be driven economically to continue to recover because they don't have the shrink risk, or there are take-or-pay or ship-or-pay obligations where the variable decision, if you will, is lower. And so they'll take a lower –- because they're going to have to pay the transportation and fractionation anyway. Therefore, they'll take a loss on the ethane. So I think those are driving some of those decisions. But for our decisions, we basically are forecasting that we'll be in full rejection at all of our plants throughout the period. Now as I said earlier, I can assure you that will not be the case, that there will be periods where we're up a little bit as margins pop up and we'll take advantage of those. But as it's modeled in our plan right now, it is in full rejection.

We'll take our last question from Helen Ryoo with Barclays.

Actually most of my questions are answered. But just on accept and rejection, is any of your keep-whole contracts on your processing plants have –- on those contracts, is there any must-recover ethane volume? Or could you just sell them at methane price when you have that negative spread?

Yes. Well, really, the way that works from a contract standpoint is we just replace any Btus that we take out. So if we don't -- didn't take the ethane out, we just leave the ethane in and we don't have anything to keep a producer whole on. So we're not really exposed on that provided that we reject it. It's just – we only have to replace any Btus that we take out.

Okay. And then -- so I guess the full ethane rejection you saw in the quarter it's mainly affecting just the Overland and Conway fractionators?

That's correct. Now the Overland Pass line, of course, collects the ethane from our Piceance and our Wyoming plants. So that's Opal, Echo and the Willow Creek facility, and those are a large producer of our equity ethane barrels. That's a very large portion of our equity ethane barrels. And so those are in rejection. But remember that those go into Overland Pass, they're not actually fractionated at Overland Pass –- sorry, they're not actually fractionated at Conway. They're fractionated by One Oak at their fractionation facility in the Mid-Continent typically. So those are 2 unrelated issues. I would just say Conway is seeing the impact of rejection in the Mid-Continent. Most of its barrels and its NGLs come in from barrels that are produced in the Mid-Continent area.

Got it. And do you have any take-or-pay type contracts on the Overland pipeline?

No, we do not.

Okay, great. And then just a follow-up or it could be clarification, but I guess did you change your Marcellus gathering throughput expectations for 2015 compared to the previous quarter data book? And if so, how much of that is driven by I guess the spending reduction in the Laurel Mountain that was mentioned?

Sure. Give me just a second to pull-up my notes.

And that concludes the question-and-answer session. I would like to turn the conference back over to Mr. Alan Armstrong for any additional or closing remarks.

Let me get the answer -– finish the answer to that question. There's a few things that went on in the data book to data book. To your specific question, the largest volume reduction was probably around Laurel Mountain Midstream. And what we did there is we have basically forecasted, given that's a dry gas system at this point and really in anticipation of Chevron switching their drilling program into the wetter areas over the next few years, pulled out volume out of that area. But we also pulled back some capital as well. So it was a decision to reduce the capital that was associated with some of that volume growth. In ABA, what we did is we used to -- prior reporting, we actually had some volumes that were coming out of the William zone system and then flowing into the Laser system. Even though it was the same Mcf, we were showing those as being 2 volumes. So in the current data book, we've made a change to pull that out. And we're also doing some recontracting on that business. So it was being accounted for because we were getting a fee from Williams and then we were having a fee from Laser. So to make the -- we made that change. So that was probably the 2 largest ones. And then obviously, we did a little bit of a modification in Ohio Valley, which I mentioned earlier. Okay. This is Alan Armstrong. I'll go ahead and close out the call. Thank you very much for your continued interest in the company. We remain very excited about the environment we're in as we see the infrastructure requirements to build out for these very low cost resources here in North America. And we are still very lucky to be so well positioned in the locations we are to be a major player in providing this infrastructure and excited to see the kind of very long-term growth trajectory we have, not just a flash in the pan kind of growth but very long-term growth trajectory that's going to come off of these major investments that we're making here both last year, this year and into '15. So again, thank you for joining us, and we look forward to seeing you on May 21.

And that concludes today's teleconference. Thank you for your participation.