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 James E. Scheel - Senior Vice President of Corporate Strategic Development Donald R. Chappel - Chief Financial Officer and Senior Vice President Francis E. Billings - Senior Vice President of Northeastern G&P Operations Rory Lee Miller - Senior Vice President of Gulf & Atlantic Operations Fred Pace John R. Dearborn - Senior Vice President of NGL & Petchem Services Allison G. Bridges - Principal Executive Officer and Senior Vice President of West

Stephen J. Maresca - Morgan Stanley, Research Division Christine Cho - Barclays Capital, Research Division Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Craig Shere - Tuohy Brothers Investment Research, Inc. Carl L. Kirst - BMO Capital Markets U.S. Sharon Lui - Wells Fargo Securities, LLC, Research Division Theodore Durbin - Goldman Sachs Group Inc., Research Division Jeremy Tonet - JP Morgan Chase & Co, Research Division

Good day, everyone, and welcome to the Williams and Williams Partners Second Quarter Earnings Release Conference Call. Today's conference is being recorded. And 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.

Thank you, Mary. 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 websites, williams.com and williamslp.com. These items include yesterday's press releases with related schedules and the accompanying analyst packages, the slide deck that our President and CEO, Alan Armstrong, will speak to momentarily and an update to our data books, which contain detailed information regarding various aspects of our business. In addition to Alan 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 Atlantic Gulf; and John Dearborn 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 reconcile 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. Thanks, John. We are excited to talk to you about our second quarter, as well as the continued progress on executing our strategy. We remain very confident that our strategy is well positioned to benefit over the long haul as we continue to see this market emerge and tremendous demand for infrastructure to take advantage of the low cost natural gas and natural resources continue to be developed in North America. Just to level set before we get into the presentation. I want to run down a few key points that are key to our strategy and this is starting here on Slide 4. First of all, this -- the strategy really does frame our growth investments, our dividend and distribution growth strategy as we continue to use that as direction for how we manage the business. So we remain very disciplined around the strategy and it really is a very strong compass for us in the decisions we make. So it's important for you to understand it. First of all, in the competitive advantage. Competitive advantage is created by large scale and the resulting market access and low-cost that we offer to our customers continue to be a guiding light for us. You won't find us making investments without those characteristics in our sites. Our Transco system and our West operating areas are great examples of what that looks like to us. And if you look at the Northeast, the moves we're continuing to make in this area really are all focused on getting to that scale of #1 or #2 position in that area. And certainly, we are convinced beyond a shadow of a doubt that over the long haul, this creates great opportunity and value for both our customers and our investors. On looking…

[Operator Instructions] And we'll take our first question from Stephen Maresca with Morgan Stanley.

Alan, I want to talk first on Bluegrass. You seem pretty confident in the project obviously, it's now in guidance. What's your view on what sort of commitments you expect to move forward on it? What are the next steps we should hear about in terms of permitting? You mentioned getting commercial agreements later this year and then finally on that, do you expect this own -- just 50% of this or more or less as the project plays out?

Well, it's kind of hard to speculate on the ownership interest towards that. It's going to be up to Boardwalk and their decisions there. But I think as things stand we're so confident in the market demand right now on the asset that I would expect that they would carry through with their plans just because I think the returns are going to be very attractive relative to other options in the market. I would say from a volume commitment standpoint, remember that we have a number of opportunities that came to us through the Caiman acquisition in terms of the liquids there, at that facility, as well as we have the dedication that we receive from Chesapeake and we also have other parties that -- where we had the processing rights on various gas streams out there as well that give us pretty nice base, frankly, volumes to build off of and while we wouldn't be going forward on the project if we thought we could only get to that 200,000 barrels a day or so of production, I would just tell you that we're seeing very strong interest from some of the larger players out there that really recognize how much value this is going to mean to the acreage out there and perhaps even see it as a strategic advantage in terms of being able to acquire acreage in the area. So I would just tell you, the excitement has been pretty, pretty big on this from the customer base. These are very long term commitments that we're looking for and of course, those take some time to gain corporate approval on. But I would just tell you that I'm not sure we could be asking for any better response than we've received today from the shipper community.

Okay. And do you -- just a final on that in terms of the ownership. Is it something where you have an option to increase if you want, or is it again something where you both have to agree to change that ownership percent?

I'm going to have Jim Scheel who's been right in the thick of that answer the point.

Williams and Boardwalk negotiated an agreement where they have an option to be a 50% partner. However, if they choose not exercise that right, Williams has the option to go ahead with the pipeline unilaterally.

Okay, that's helpful, appreciate that. And then moving, Alan, you talked about the opportunities at the Florida market for Transco has on the expansion side, but also you mentioned about potential ownership of Sabal. Would that be something again at your option you could purchase? Would it be from Spectra or would it be from the next terra portion of it or any sort of color on that?

Yes, sure. It would be from the project as a whole from the Sabal trail project as a whole is what our option would be on. And again, just to make it clear, we will be supplying basically the volumes in a phased approach on the front end of that project via Transco. So we're basically the supply source by expanding to a point that reduce the amount of construction -- the greenfield construction, required for Sabal trail. So we're kind of the front end of that. And Sabal trail is going to lease that capacity with a return that's consistent with our cost of service returns. So eliminates our construction and volume risk on that. And so we have that as investment, which we found very attractive. And in addition to that, when have an option down the road to invest in Sabal trails and of course, we really like that because it gives us a chance to see how the construction costs look like when they come out and the volumes will have a much better picture on what the volume commitments look like at that point.

Can you say a what percent you could potentially own of it?

No. I would just say it's meaningful. But it is a minority position.

Okay. Final one for me. You mentioned as -- I was going to ask you about the reduction in Northeast G&P at Williams WPZ in terms of the segment profit and DD&A. I think you mentioned that was -- so this is just higher cost that's what brought that down the $55 million in 2014 and $30 million in 2015? I just wanted to make sure I'm understanding it.

It's primarily just an allocation. We have things like our engineering construction costs, our technical support for operations, accounting, all those things that we allocate as a corporation out against our various operating areas and because we've got so much growth in the area and we're applying so many resources it, we studied our cost across those areas and applied those more appropriately to the real expenses. So it's not really a shift in our overall cost against the company. That's just a reallocation of overhead cost to that area.

Okay. So not a new cost or a higher cost, just taking it from where it was accounted or allocated before and putting it into this segment.

That's exactly right.

And we'll take our next question from Christine Cho with Barclays.

CapEx looks like it went up by $2.7 billion across 2013 to '15. Assuming some sort of increase over the $1 billion cost number that I think you originally gave us for the PDH facility, is the remaining mostly tied to Bluegrass or are there other large ticket items in there that were either included or taken out, of out of the 3-year guidance.

Christine, it's Don Chappel, it's mostly entirely Bluegrass. There's some other moves as you mentioned, but it's largely Bluegrass.

Okay. And then would you be able to give us, I guess, some sort of idea on what the cost increase is looking like for the PDH facility, is it materially over or like 20%?

No. I would just say, again, we kind of came at that with an initial estimate that was very rough and the return was so attractive on it that we decided to proceed because even at an overrun, that would have been -- or an increase in our estimate, that would have been much higher which still would make sense. And I would just say, that cost did not go outside of that range. It was higher than what we early had in our guidance. But more importantly I think, the point to be captured there is that as we look at the project, we realized one of the fundamental benefits and what I would call industrial logic that underpins the project is the fact that we have got the ability to transport propylene derivatives rather than propylene itself into markets that are much closer than transporting the propylene all the way to the Gulf Coast and then turn around and transporting the propylene derivatives back to the Midwest markets and to the -- particularly in the Northern Midwest markets. And so by getting the propylene derivative business built there, we're getting -- we are positioning ourselves to be able to capture some of that transport and logistics advantage. And so we want to build that complex in concert with those derivative plant and there may be some optimization opportunity between the propylene plant and the derivative plant. Now having said that, don't hear us say that we're going into the propylene derivative business because that's not at all what we're doing here. And in fact we're going to do this in a way that's going to reduce our commodity exposure to propylene. But it does allow us to optimize the construction of the facilities. And again, to enjoy some of the benefits of the logistics through the pricing structure.

I see. So net-net, would you say that your returns overall look better than when you originally looked at it? Or do they kind of just off -- does everything just offset each other?

I would say that our returns -- I would say our returns will be lower than what we originally thought. But I would also tell you that they're going to be a lot lower risk because you are converted to more fee-based business.

Okay. And then in your presentation slide, when you talk about equity funding for Bluegrass, you say WPZ investment and then you wrote WMB and/or third parties. Can you just clarify, when you say third parties, do you mean that you're willing to sell a portion of your interest in the Bluegrass project or sell your interest in some of your other assets like we've seen you do with Constitution, I don't know, maybe with some of your assets in Canada, et cetera to raise the cash?

Christine, this is Don Chappel. I'd just say we have a lot of options. WPZ is our preferred funding source. So to the extent that we need equity, our preference would be for WPZ to fund that versus Williams. But there are a number of other sources we expect that other parties will have interest in equity in Bluegrass. We may not choose to give any of it up, but it's really -- what you see there on the slide is just an expression of we've got quite a few options. And in the near term to the balance of this year and into next year, at least, early next year, we'll be funding this with excess cash at Williams, and beyond that, we'll have some choices to make. But for the next couple of quarters, 2 or 3 quarters, it's really funding with excess cash flow at Williams.

Okay, great. And then lastly, for me. In the Northeast, it looked like OBM volumes were slightly revised down in '14 and '15 while Susquehanna was raised. Can you verify that's the case and can you also provide a number for what volumes are today at OBM?

Sure, this is Frank Billings. I would say that we did revise the volumes down a little bit. The majority of that is, as we actually have derisked a little bit it to the OBM volume forecast because we had a customer identified in our forecast and we've actually executed an agreement to have them become a true customer versus a forecasted customer. And with that, we've got a revised drilling program -- drilling schedule from them and we basically included that in our forecast, as well as one of our existing customers revised slightly their drilling program for '13 and '14. So that's the main driver for the volume adjustments, I would say, in OBM.

Okay, great. And then can you provide a number for what volumes are today at Williams?

Yes. Right now we're moving around $200 million today, kind of we're moving around $250 million to $260 million, but we do have some volumes that are not moving. We've hit a peak volume in excess of $300 million a day in OBM. And right now, what is happening is we have a couple of customers, one is drilling and frac-ing a new well, so they've shut in some production around that well frac so that they don't -- or for whatever reason, I guess they want to protect or manage that activity. And then we have another customer that is having some permitting issues on one of their well pad, so they had to shut in production as well. But I can tell you that we're also -- we have multiple producers out there that are in the process of completing some wells and I think -- we see the activity that we expected to see from the producers in OBM this summer as they're trying to get some work done before the fall and winter season hits. So I think we're on the right trajectory and I just think what we have is -- when we lose 30% of our volume or 10% of our volume, $30 million a day for producer activity, it shows up at this point. But I can tell you that in OBM today, we are operating well mechanically. All of our mechanical and operational issues are few at this time. And I think, we're in a good position to move the volume that's behind the system today. And when we complete the work for -- that we had talked about in the second -- the first quarter call around the CR -- or the facilities that we're going to get in place, I think we're going to be in great shape for the rest of the year.

And we'll take our next question from Bradley Olsen with Tudor Pickering. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: My first question is on Transco and some of the opportunities you're seeing around that asset. We've seen Leidy pricing and just pricing around the dry gas pricing area, the Marcellus come under a lot of pressure. Is that adding to kind of inbound producer demand and maybe even some inbound demand side or utility demand for capacity on projects to get out of the Northern PA and Northern New Jersey markets like Leidy Southeast and Constitution?

Bradley, this is Rory Miller. Good question. In fact, when we closed out our Leidy Southeast project, we had very robust demand. But we've had a number of producers that have called back saying if they could get in to see if it was not too late to open the door and get on the project. So I think we've got over 8 BCF a day of pipeline, interconnects and capacity connected to bring gas into Leidy. And as those new connections see additional wells drilled behind our system and behind those interconnects, people are finding they need to get a way out. So we think there's an excellent chance for additional expansion up there, somewhere down the road. But very much a supply push situation. We've talked a lot about the quality of the Cabot reserves, the quality of their wells up there. But we're seeing that sweet spot extend west of there as well. So even though it's a dry gas area, the EURs on those wells are so robust that the economics of the current gas prices are very compelling. So we see a big supply push coming out of that area and we're looking at number of opportunities to help satisfy that demand from producers. Likewise, we talked a lot at Analyst Day about all the power generation opportunities up and down the system. We continue to see those opportunities roll in the door. So there's a fantastic opportunity for us to match up demand pull with the supply push, and we think that's going to keep new projects coming for years into the future. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: But no plans today on the table to expand either the Leidy Southeast or the Constitution project?

Right now, we're probably focused on the Leidy opportunity and I would just say, we're early on in that, but something could be coming out here in the near future. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And on the Bluegrass project. As you look at the pipeline fractionation storage, integrated nature of that project, is the 2.7, give or take, that you discussed as being largely Bluegrass related in your CapEx budgeting, does that include an export facility? And do you think that you would need to enter into a JV or some kind of economic sharing agreement with someone who has an existing export facility or existing acreage on the Gulf Coast in order to get that done?

Bradley, this is Jim Scheel. We have not included in the guidance number the export facility. We're still defining that at this point. We have seen a great amount of interest from our customers for that, they do view the international markets as the logical destination for many of the propanes and butanes. We have identified the site and we're moving forward to acquire that. As it relates to the cost of that, we're still defining it. We'll include that in future guidance. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, great. And just a follow-up on some of the PDH questions from earlier. The PDH, as well as the ethane recovery costs appear to have increased since the Analyst Day. Is that, in the case of the PDH something related to kind of overall labor and cost trends in Western Canada? Or are those 2 separate issues? And on PDH, Alan, you mentioned that you would kind of rule out entering the propylene derivative business. Is there any reason, specifically, that you ruled out providing your own polypropylene facility just to expedite that process?

Yes, I'll take the last half of that and then I'll ask Fred Pace, who runs our engineering construction, to answer your question on the fundamentals in the construction cost in Alberta. On the derivatives side, I would just say that as you move further and further downstream, that starts to become more and more knowledge that is outside the base of our operations today. And I would just say, we have so many opportunities that are right down our fairway of knowledge that it doesn't really entice us to move outside of the area that we have strong knowledge in. And so we're excited to partner with others that have both the marketing expertise and the operations expertise that can help bring the value to that. So said another way, we're not really all that motivated to learn some new lessons when have such great opportunities in front of us right now. And so that's really driving that decision. And I'll ask Fred to answer the questions around the cost pressures in Alberta.

Yes, on the PDH cost outlook kind of playing on Alan's earlier comment about our observance of other projects, having cost pressures, we've analyzed that. And did a much better job of also analyzing all of our other risks around availability of labor and contract personnel and materials, our entire supply chain around that. So that's just our best current thinking and guidance around our current risk analysis to come up with our current outlook. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, great. And just one more and I'll get out of your hair. The Atlantic Gulf segment, you reduced kind of 2013 and 2014 guidance fairly significantly after the first quarter call. Now you've kind of printed 2 strong quarters in a row in the Atlantic Gulf segment, really the kind of Transco-related seasonality really wasn't visible on those results. And so you've kind of printed $300 million of segment profit in the first half of the year and you've kind of guided towards a full year segment profit in the low $500 million range. Is that -- is it correct to imply a decline in the second half of the year? Or is that just a segment that has, I guess, outperformed since the first quarter reporting?

This is Rory Miller again. I think the guidance that we included in the book showed us outperforming guidance, maybe $30 million on a full year basis. And I -- so I think we're going to be able to hold on to some of that, about 2/3 of that revision is attributable to lower O&M and G&A and we've been working hard I think as Alan mentioned earlier to control expenses. And I think a lot of that is -- will be sustainable improvements. We also had some other minor issues that are helping out. We did have an increase on our liquid transportation rates on Transco for condensate and retrograde. That combined with a little higher DD&A and then a reimbursement for some engineering cost from Gulfstream accounted for about 1/3 of that $30 million. So that's a lot of detail. But a number of those are sustainable type items. Of course, the engineering reimbursement would be a one-time event.

And we'll take our next question from Craig Shere from Tuohy Brothers.

A couple of quick questions. Does the business interruption insurance in the 2014, say, for the first quarter cover the delayed startup of the expansion on Geismar?

Craig, this is Don. I think answer is yes. Basically the policy covers our losses. So it's a comparison of what we would have made had the event not occurred to what we did or didn't make as a result of the loss. And obviously, we have a responsibility to minimize the loss and we would do that with or without insurance. So we're interested in getting the facility back up and running safely as quickly as possible, including the expansion. But the repairs are really the critical path item and the expansion will be complete along with the recovery and the turnaround. And we expect that to be covered.

Great. And Don, while I have you on the line, there was little uptick at least, for the quarter in the tax rate, but I don't think the full year has changed in terms of guidance. Can you give us some color around that?

I think the full year is down a little bit because of some additional bonus depreciation we were able to identify. And then just a function of continuing to refine the numbers, I think, the quarterly numbers are -- tend to move around a little bit, depending on the profitability and where that profitability is.

Great. And then finally, I wonder if you all could just give a little more color because I think there were some prepared comments regarding it and then also just recently some comments about attacking L&M and G&A that's helping the Atlantic Gulf segment. But could you all discuss in a little more detail the success you seem to be having with cost containment, especially in 2013 to offset some of the headwinds we're seeing?

Well I would just say, we've all made a concerted effort on that front. As you know, we went through some very significant organizational restructure post the spin-off of WPX and I would just say that we are positioned and we reorganized ourselves in a way that we can really focus and bring some transparency to our cost structures and understand the areas of opportunity we have to put pressure on that and the team is doing a great job of doing that. So I would just say it's kind of the old-fashioned way. The good news I would tell you is I think it's very sustainable. And I think we have opportunities to continue to improve even more so as we kind of explore new opportunities in a much more integrated company. And so for instance, we're seeing areas of opportunity between gas pipes and midstream where previously, we operated as separate -- completely separate business units and now, we're seeing opportunities to save money because we're operating in a much more integrated fashion than we have previously. So more to come on that, but the team is doing a terrific job and very proud of the focus they've put on that.

And we'll take our next question from Carl Kirst with BMO Capital.

Three, perhaps, cleanup questions. The first actually on -- just with respect to the insurance of Geismar. Obviously, you laid out the expectations and I guess with potentially only a 60-day lag that kind of implies a pretty smooth process. Has there been any contention or friction from the insurers at this point that would give you pause at all or is this -- do you expect to be a pretty smooth process?

Carl, its too early to tell. We've not yet filed our first claim. But this is something where we'll be able to: one, we can present our forecast. The forecast we had before the incident and that was prepared without any knowledge of the incident coming, so I think that's pure. There's no bias in that forecast. We can present that to the insurers now. We would have our first insurer loss in the month of August. That would have been after the 60-day waiting period, but before the planned turnaround. So there's a small period that's insured. Just a couple of weeks of operation between that 60-day waiting period and when the turnaround would have happened. So we'll be able to submit that at the end of August, early September, and get response from the insurers on that payment, and that really set the stage for the balance and then we'd be in 50-day turnaround and so then in October, we would have a partial month again where we would have another partial month claim. We'd submit that claim at the end of October and then we'd submit a claim update every month. So we think that the 60-day lag is reasonable. It's possible we could get paid earlier or somewhat later. But right now, that's our best estimate.

Appreciate the color on that. The second and not to, perhaps, beat a dead horse on the PDH facility. But just given all the cost inflation that we have seen in Alberta and seem happening in such a quick period of time. When you look out with the major spend on when the PDH would actually happen. Is there any possibility of locking something up turnkey with someone in order to stem any possible future labor inflation?

Well, again, I think by stretching our schedule out, we give ourselves a lot more opportunity around that. And as you'll recall and I think we mentioned this in our announcement -- original announcement with PDH facility that we were going with a little bit different design than some on the industry had because -- and a little bit smaller, so that we can build that business on a more modular basis. And so that allows us to bid out that modular construction on a fixed fee. And so the remaining portion would be the in the field construction. The good news about this project aside from some of the other projects we've seen a lot of cost pressures is this work is at Redwater, which is near Edmonton. A lot of the areas we really had a lot of struggle with in terms of low productivity and cost pressures has been in the Fort McMurray area where labor is more constrained, particularly skilled labor is more constrained. So I would just say, we're taking -- we're working hard to contract this in a way that really eliminates a lot of that build construction labor risk and productivity risk and stretching the schedule out gives us even more opportunity to do that.

Fair enough. And then last question if I could. Just on Bluegrass and if you could just refresh -- I think, you probably addressed this in prior conversations. But as you look out at sort of this large material investment, are you expecting from -- the feedback you've heard from shippers, are you expecting a return profile in line with other sort of large, almost, call it, FERC allowed type of traditional infrastructure returns? Or is it the uniqueness of the NGL solution would allow something higher more indicative of Midstream infrastructure?

Well, I would say a couple of things allow us with a -- and remember, only a portion of this is regulated. The frac and storage business downstream of that is not regulated, so we have that opportunity, if you will, in terms of better than FERC return and I would just tell you, we have plenty of regulated cost of service returns available to us. And so we wouldn't take any additional risk or development cost like this if we didn't expect higher returns than that. So the answer to your question is, we do expect higher overall returns on the project. And one of the things that helps us achieve that obviously, is the benefit of the Texas Gas line and which provides us with a better solution than the market would otherwise had to offer. And gets us in schedule. Importantly, I can tell you from the shipper's perspective, this timing issue probably can't overstate that in terms of importance because people have all this acreage up there. They're very anxious to go drill, but they're seeing NGL prices continue to collapse up there in a very oversupplied market. Their only option is to transport out by rail and that -- even that is getting pretty congested. So I would just say that the market is very anxious for this solution and the return we're making is -- reaps the benefits of some of the things I mentioned.

And we'll take our next question from Sharon Lui with Wells Fargo.

Just wondering if you could maybe talk about the risk to achieving that April resumption date for you Geismar? Is it really just mainly, I guess, the pace of the repairs? Or does the status of the investigation play a part at all?

A very insightful question. This is a John Dearborn, on the answer to that, if you take a look at it, we've got a few investigations underway, 1 by OSHA, 1 by CSB, and of course, the Williams' own investigation. We're collaborating there in a very open and transparent way with OSHA and CSB. And as a result of that, over time, over the last few weeks, OSHA and CSB have been, I'll say, giving back more and more of that plant so that the effective plant now that's still under the control of OSHA is a very small area around the fractionator itself. And so that's allowing us now to begin to, I won't say demolish, but begin to take apart the impacted part of the plant. So pretty quickly here, we think that the investigation is going to become a less of a risk to our path of rebuild. Then the question becomes, how quickly can we get the equipment and the necessary materials to plant and construct it and that in fact sets our timeline. Though it's not without risk, we feel pretty confident about the April 1 date, that's why we've been out with it.

Okay. And just another follow-up. In terms of the business interruption insurance, does that, like, cover, I guess, any obligations or contracts with your supply or sales?

I'll let John take the question on the sales contracts. I don't think we expect to have any significant losses in that area. But yes, it would cover.

Yes, and again, very insightful because of course, our customers are a very important stakeholder base for us right -- but we're going out to continue to build our relationships with our customers. All of our customers essentially are on force majeure at the moment and will be over time. We want to continue to preserve those relationships, so that they'll be there when the plant comes back up. So all these information is actually fresh for our customers in the coming weeks. We're going to be going out and speaking personally with our important customers out there so that they are with us on the other end of the startup.

Okay. And this also applies for any supply sources in terms of ethane?

We really don't have a concern about the ethane. Essentially, the ethane goes back into the market and probably get used and consumed by others so it's not really an issue for us in our business.

And we'll take our next question from Ted Durbin with Goldman Sachs.

I just want to understand the -- kind of picking up off of Sharon's question, sort of the range of outcomes if we're plus or minus the April 1 date on financials relative to kind of where you are with the insurance and the deductible let's say we push another quarter out, what does that do in terms of -- kind of the financial impact?

Ted, I think as John mentioned, we have a plan to get us started back up in April. If we push that back at some point, we would run out of potentially, or hypothetically, we'd run out of insurance -- business interruption insurance and the coverages combined $500 million for both business interruption and property damage. We have a current estimate on the property damage of $102 million, less a $10 million deductible. So that's $92 million of assumed coverage at this point. And then as you saw, we disclosed an estimate of $384 million on the business interruption coverage. So certainly, significant delays would expose us.

Okay. But at that point then, it's just a matter of sort of the loss -- what's called the loss margin of the downtime from that perspective? And obviously, assuming the repair costs were the same. Is that fair?

Yes. Again, we have no reason to believe that the downtime will extend past April at this point, but certainly as you think about risk, I think you understand it well.

Great. Okay. And then just in terms of the distribution growth here at WPZ. It looks like you're still comfortable running a little below 1x in 2014. You've kept the idea wherever is the same. But again, there's some flex here in terms of what happens with Geismar. I was just wondering how we should think about what you'll target for coverage if the IDR waivers get increased from WMB or do we lower distribution growth, say, at WPZ, kind of how those all interplay?

Those are, I would say, speculative questions at this point. But clearly, WPZ -- Williams enjoys about 75% of WPZ's distribution, so we have a big stake in it. WPZ is our primary equity funding vehicle and funding vehicle generally. So obviously it's very important to Williams. We did waive the $200 million of IDRs. We did not see any point to step forward further on that at this point. But certainly, we'll consider potential waivers, additional waivers if and when needed. So I would just say, we'll stay tuned here. If we execute as we had put forth in our plan here today, we don't believe any additional waivers are required. We look at 2014 at getting closer to 1x coverage again with a lot of fee-based growth. And by 2015, getting back to that 1x coverage number. So we're comfortable running where we are. And at Williams we'll continue to monitor the situation and see if WPZ needs any additional support and make the decision accordingly.

And we'll take our next question from Jeremy Tonet from JPMorgan. Jeremy Tonet - JP Morgan Chase & Co, Research Division: My question is with regards to the Western segment, seems like in the west, results were better than we anticipated and going nicely in the first half of the year. I was just curious as far as in 2014, you have a bit of a stepdown there as far as what you're looking for segment profit in DD&A, it was only marginally increased. I'm just wondering, is that a bit of conservatism or what's kind of driving the year-over-year step down in guidance there?

Well, partly because we do have some contracts that had changed in 2014. So that is some of the reduction. Jeremy Tonet - JP Morgan Chase & Co, Research Division: Okay, great. And then last one for me. I was just curious, with this guidance revision, I think some of the other recent ones, it seems like maintenance CapEx has been ticking down a little bit for 2014, 2015. I was just wondering if you could touch on the drivers for that?

Sure. One of the things is we had some, as we mentioned earlier, we have some time pressures on getting some of our asset integrity work done towards the end of 2012. We completed a lot of that work as we've laid out in the past so we kind of add an accelerated effort there to complete some of that work. And as well, we're continuing to take advantage where we can of the integrated nature of our business and looking to really invest that maintenance capital in the ways that reduce risk very best for this company overall. And so I would just say, we're continuing to really analyze that. Obviously, the thing we're going to spend our dollars on first is keeping the system safe and reliable and we certainly won't back off on the cost that it takes to do that and we'll continue to do that. But there are other areas that we can find ways to improve cost, purchasing power across a lot of our assets, which we -- when we combine our gas pipes and our midstream efforts, we got a lot of purchasing power. And so we're continuing to find ways to improve on that.

And we'll take our final question from Christine Cho with Barclays.

Just some follow-ups. On the PDH facility, if it's going to be in service in 2017 is most of the CapEx going to take place in 2016 with maybe a little bit in '15? I just wanted to know how we should think about the timing of the spending.

This is Fred Pace responding. That's exactly right, wrapping up in '15, but the majority occurring in '16.

Okay. And then this is just an accounting question. But are you going to be consolidating your 50% interest in GulfStar and your 41% interest in Constitution? I wasn't clear if you guys -- how you guys are accounting for it in your segment profit guidance?

John is going to take this one.

This is John Porter. Yes, those 2 assets are shown on a consolidated basis with a non-controlling interest presented below segment profit.

And that does conclude our question-and-answer session. I would now like to turn the conference back over to our speakers for any additional closing remarks.

Okay, great. Well, thank you, all, very much. This is Alan Armstrong again, thank you all for joining us and we remain very excited about the future that we have ahead of us. And our showing of starting to really turn the corner on the fee-based projects really starting to kick in so thanks for joining us.

And that does conclude our conference. Thank you for your participation.