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 the Northeast Gathering & Processing Operating Area Donald R. Chappel - Chief Financial Officer and Senior Vice President John R. Dearborn - Senior Vice President of NGL & Petchem Services Allison G. Bridges - Principal Executive Officer and Senior Vice President of West Rory Lee Miller - Senior Vice President of Gulf & Atlantic Operations

Abhiram Rajendran - Crédit Suisse AG, Research Division Carl L. Kirst - BMO Capital Markets U.S. Christine Cho - Barclays Capital, Research Division Theodore Durbin - Goldman Sachs Group Inc., Research Division Sharon Lui - Wells Fargo Securities, LLC, Research Division Timm A. Schneider - ISI Group Inc., Research Division Rebecca Followill - U.S. Capital Advisors LLC, Research Division Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Christopher P. Sighinolfi - Jefferies LLC, Research Division

Good day, everyone. Welcome to today's Williams and Williams Partners First Quarter Earnings Conference Call. Today's call is being recorded. And at this time, I'd like to turn the call over to Mr. John Porter, Head of Investor Relations. Please go ahead, sir.

Thanks, Melanie. 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 this morning, we also have the 4 leaders of our operating areas with us: Jim Scheel leads our Northeastern G&P operating area; Allison Bridges leads our Western operating area, Rory Miller leads the Atlantic Gulf area; and John Dearborn leads 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. Thanks, John, and good morning to everybody. Thank you for joining us. Certainly excited to be reporting another great quarter and really on all key measures, but before we dig in to the quarterly results, I want to remind you that we remain very committed to our natural gas focus strategy and we continue to have -- and the strategy really continues to have us right in the middle of some great opportunities, and really, we couldn't be more excited about the way we're seeing the tailwinds build for the opportunities that we've positioned ourselves for. This has certainly been a wave that we've been seeing building for quite some time, and we think we've got ourselves in the perfect position to catch this wave. And certainly, as we see a lot of our major projects start to come on here in the last half of this year and really, for many years to come, we just got a tremendous wave of great projects that we've been working so hard on to get out in front of. So we certainly see it -- the wave building here in the first quarter and through our guidance period and then well beyond, and we look forward to talking about that well beyond certainly at our upcoming Analyst Day. So we are also well positioned to return this value to our shareholders for many years to come with our industry-leading dividend at WMB and as well, our solid and very visible distribution growth at WPZ. So today, we'll talk about the key measures for our first quarter results. We'll talk about the continued project execution and development that we've got ongoing, discuss the drivers for our '14 and '15 -- 2014 and 2015 guidance range. And I'll provide a little bit of…

[Operator Instructions] We'll go to Abhi Rajendran with Crédit Suisse. Abhiram Rajendran - Crédit Suisse AG, Research Division: Just a couple of quick questions. First, on Northeast G&P. So your segment profit in 1Q was $12 million, but you also maintained your full year guidance of $195 million, which suggests a pretty meaningful ramp up. So could you maybe just talk a little bit about some of the puts and takes driving this? And also what some of the main risks may be to this ramp?

Hi, this is Jim Scheel. Thanks for the question, Abhi. As we looked at this winter, this has been one of the worst winters we've had in the Northeast, and I know over the course of the last few meetings about the reliability of the OVM system in particular, there have been some challenges with that. Those, we didn't face this year. And so volume challenges that we had were more on the producer side versus the asset side that we're operating. So we're very excited about having a reliable system ready to move gas, especially in this market of ever-increasing prices for our customers. We see a rather rapid ramp-up of volume over the course of this year. Obviously, we saw a 2% growth between the fourth quarter and the first quarter. But I want to remind you, Abhi, that during the fourth quarter of last year, we had some incremental volumes coming into OVM due to the Natrium fire. Those did not materialize or weren't in there during the first quarter of this year and we still saw an increase. As we move through the course of the year, I would expect our volumes to be slightly under perhaps what we've shown on our spreadsheets as the $335 million average, but I want to emphasize, we'll probably end the year with a much -- with above the $400 million that we're showing. So I'm excited about the assets' ability to move the volumes, to reach those goals. One of the key risks that we may need to look at is related to the Chevron well pad fire and how they react to that with bringing volumes online later in the year.

This is Don Chappel. Just to add to Jim's comments, I'd also just remind you that, again, we're bringing a number of processing and frac facilities online during the year. And even on the volumes -- on the growing volumes, those will provide additional fees. So we'll not just get the volume growth, but we'll get additional fees for additional servicing.

To add to that, that's a great point, Don, is we'll be bringing on a number of facilities around the OVM very quickly. We've -- we're already starting the pre-commissioning of these assets that include the stabilizer. That'll provide a much larger netback for our producers around their -- around their stabilized condensates. The deethanizer, I want to add, that's going to be a great asset for our customers. Again, we've had some restrictions in the ability to get product into the interstate pipelines because of ethane content over the course of the last couple of months. With the deethanizer online, that will no longer be an issue. It will allow basically unfettered flow out of the assets into the interstates. And then as we bring on additional capacity on the West Side of the system with the 24-inch line coming in, we're excited about the ability to fill up our cryos and continue the execution of building more cryos at the Oak Grove facilities as we move forward. Abhiram Rajendran - Crédit Suisse AG, Research Division: Okay, great. And then just shifting gears a little bit, just a broader question on maintenance spending. So this appears to be trending lower over the coming years despite kind of more projects being put into place, but we've also seen some of the operational problems that you referenced. So I guess, how should we think about all of this? Do you need to spend more going forward? Or efficiencies making up for it? Any color here would be very helpful.

Yes, sure, Abhi. I would just tell you that if you look over time, we've been at the -- I'm not sure if it's good or bad, but we've been in the lead in having more maintenance capital as a percentage of our EBITDA if you look back over the last 4 years or so, and that is really just driven by our focus on making absolutely sure that we're spending dollars wherever we can to improve safety and reliability on our systems. We'll continue to do that. I would just tell you that we got a lot of work out of the way, a lot of big, expensive work done out of the way in terms of -- in 2012, and that's for a number of reasons, some regulatory required, but as we inspected our lines, we went to the areas where we thought we would have the worst conditions on our systems, and as we've moved off of that group, obviously, we get to the newer and newer systems and the systems with less potential anomalies in it. And so our cost per mile of inspected pipe is coming down dramatically on us because we're getting into the better and better pipes. So we saw kind of a big run up there in '11 to '12, driven by things like the Clean Air Act and some pipeline inspection rules. And that was really kind of driving that. So not telling you that you should expect that to continue to go lower because we don't have that built into our plan. But so far, just the things that we've been hitting lately as we inspect our pipes, we've had less repairs required. So we basically have to forecast what we do expect to find with our in-line inspection tools. And our pipeline inspections, we basically have to estimate how much of that we'll have to repair, and that's been coming down over time, just again, because we're into the better -- some of our better-conditioned pipe. Abhiram Rajendran - Crédit Suisse AG, Research Division: Okay, got it. And then one last quick one, if I may. So I guess one of the emerging debates in the industry is the viability of the export market for ethane, and you guys are in a unique position to kind of evaluate this. So could you maybe just your thoughts on this in terms of where the supply-demand balance is headed longer term in your view? How do you know -- how big of a market you think this could be? Any color there would be great.

Yes, Abhi. I'm going to ask John Dearborn. He is quite the student of that issue. And I'm going to ask him to offer his thoughts on that.

Yes. Hi, Abhi. Thanks very much. It is an interesting idea. It think I'm a bit schizophrenic on the idea of this, so let's talk about both sides. From one perspective, you'd really like to see some better price signals out there on ethane so the necessary infrastructure gets built and you get supply reliability to the industry, to the petrochemical industry, which, of course, we're a participant of, but of course, that could mean ethane prices going up. So moving some ethane offshore I think begins to increase some of the demand, which perhaps begins to create a better balance there so that we do get the infrastructure that provides the supply reliability, which then assures on the demand side that people continue to invest capital. On a very positive note, though, that -- and I can't speak to the project that was recently announced. But on a very positive note to projects like this, I think there's also an opportunity because there are some shortages out there in the world for ethylene that we could export some ethylene from some of these ethane facilities. And I think that bodes well for the ethylene balance in North America, which would be a very positive dynamic for us with our investment at Geismar today. So I see a fair bit of positive there. Exactly how big the market is going to be for ethane export, that's a difficult challenge, a difficult question to answer right now. But I do see positive dynamics on the -- potentially on the ethylene site.

We'll go next to Carl Kirst with BMO Capital.

Just a maybe a micro and a macro question. First, on the micro side with respect to Geismar. And Don, perhaps this is for you. With -- if you could just give us an update on when you see the next tranche of insurance recoveries coming? And I guess, perhaps an associated question is to the extent that what was in the first quarter adjusted EPS was a relatively large healthy number for Geismar, given that amount, do you see business interruption actually being sustained through the outage period? Or are we going to see a little bit of a gap between that ending and the plant coming back online?

Good morning, Carl. In terms of the next tranche of cash, I would expect we'll see some cash in the second quarter. We've made an application with the insurers for the next period of loss and it's going through their process. So I would expect we'll see some cash in the second quarter. I think we've disclosed that our business interruption insurance combined with our property damage insurance would substantially offset the down time. We think that's still the case. Exactly what that is will be dependent on the Geismar -- I'll call them pro forma margins, had Geismar has been up and running, and as well as our negotiations with the insurance companies. But I don't think anything has really changed. I think we're about where we were the last time we talked.

Fair enough. And then maybe macro question for Alan. And this might perhaps start getting into 2016 thoughts, but I just wanted to get a little bit more color on the ramifications perhaps of not doing Bluegrass. In the sense of do you think that for instance what had happened with Atlantic Sunrise, where you had to see that train hitting the market before people were willing to sign onto long-term contracts. Without Bluegrass, do see perhaps the industry needing to get hit first before we will see longer-term contracts? But ultimately, I'm trying to kind of get to are you more nervous than before perhaps of 2016 drilling activity? I know that's kind of an open-ended question, but any additional color there would help.

Carl, great questions, as always. I would just tell you that, certainly, I think that there's a lot of people kind of counting on somebody else solving the problem as it relates to Bluegrass. And frankly, we're not going to be the ones to do that for the whole industry without adequate contractual support. And -- but yet, we still believe that something needs to get done. We're very interested in seeing the very best project available to the market come forward and get subscribed, and whether it's Bluegrass or whether it's a combination of other projects, we're not all that jealous of the opportunity, frankly, just because we have so many other great investment opportunities, and very well contracted opportunities. But we certainly think that something -- a solution does need to get resolved. Used an interesting term there to say that the train that we would have to hit out here. And I would just tell you that, that is going to be issue is people are going to understand in the not-too-distant future that railing all of this product out of the area is just not going to be a sustainable solution. But I think that's kind of what's got the market thinking it can continue to ignore the longer-term issue at this point. So we're going to remain very engaged in the subject for both our own project and for other potential projects that might come along. And we'll certainly stand by, ready with Bluegrass for the industry, if it becomes adequately supported by contract. You are correct. I do see this a little bit like Atlantic Access, where the market just wasn't quite ready for it and just didn't feel the pain quite enough yet. And I do think that as we get into this summer and into next winter, when a lot of this new production and these -- starts to ramp up. As for our forecast, our forecast that we see through Access and our forecast that we see through Blue Racer, we see a lot of liquids coming into the market and we're certainly hopeful that we can get a project supported that will not deter drilling in 2016 because this is some tremendous resource out here. And we're going to have to work as an industry to come up with the right market access, and we certainly look forward to being a part of that.

Great. And then just to sort of paraphrase back, though. You're thinking that with the supply models that you all are seeing, that we could in fact see that pain as early as next winter?

I'd -- yes, if you look at the ramp-up in volumes that we're expecting, I think we will see some pretty big improvement in volumes.

We'll go next to Christine Cho with Barclays.

I noticed last quarter that your ownership in Caiman Energy II had moved higher, and this quarter's data book confirmed an incremental 11%, it looked. Can you talk about who sold and was management included? Also, can you discuss how the exit plans of the private equity guys work? Do you have the right of first refusal and then it goes to Dominion and then any third parties?

Christine, this is Don Chappel. We had an option in our Caiman II deal to increase our ownership by funding a proportion of the amount of the capital investments. So we chose to act. We had a good look at the -- how the business was developing. We liked what we saw, so we exercised our option to invest a greater amount than our partners and increase our ownership accordingly. So we did that. In terms of the exit, we have a right of first offer on the sale, so we'll see what the sellers choose to do.

Okay, great. We noticed some of the majors receiving permits in Marshall and Wetzel Counties in first quarter, the very end of fourth quarter. But I was unable to tell if they was Utica or Marcellus. Can you provide any insight into any updates on their plans to develop the acreage? Also, one of the majors also had an impressive well in Utica in Marshall County. Can you talk about what that may mean for you on a near-term and longer-term basis if the play is as great as IP rates could suggest?

Sure. This is Jim Scheel. I'll let the majors speak for themselves as far as any specifics related to their forecasts. But I will say, generically, we've had a number of folks in our offices talking about the additional drilling specifically around the Utica dry. I would say there's an upside opportunity for us at OVM to be gathering some of that Utica dry gas into our system, gathering that for them. We have some extra capacity at the plants today, so that wouldn't impact our liquids volumes to provide us with some near-term additional opportunity. Right now that's not baked into our plans, but I think what you'll see is, as folks are delineating that dry side, you'll see more and more permits issued, so they get a better feel for what they have in that particular area.

Okay. And then I noticed you've started to kind of put Pacific Connector in your slides. It's looking like the probability of Jordan Cove, its moving forward, is getting higher. And something that I thought was interesting was that we've seen some pipeline projects for other LNG facilities contingent on the LNG projects receiving FERC approval and not necessarily FID. For you, can you discuss a little bit what has to happen for you guys for it to move out from under the potential project umbrella and into development?

Yes, certainly. This is Allison Bridges. Yes, we are very excited for all of the progress that we are seeing on Jordan Cove and Pacific Connector. We have nonbinding agreements with shippers, so that would really exceed the total capacity. Before we would be ready to, I guess, move to approval for that project, we will be looking to turn those nonbinding agreements into binding agreements. We are hopeful that we will get the FERC certificate, perhaps by the end of this year or early next year. So that is another major milestone. I will say, with respect to the FERC certificate, the route that we have on Pacific Connector was actually previously approved by FERC, so we think it's just a matter of timing on that.

Well, I wasn't actually talking about FERC approval for the pipeline. I was talking about the FERC approval for the LNG project. But it sounds like, for you, it's just -- it has nothing to do with the LNG projects you're seeing, FERC or FID. It's, the customers just have to contract with you.

No. I mean, we certainly are working jointly and expect the same FERC approval timing and customer commitments for both Jordan Cove and Pacific Connector.

Okay. And then last question for me, the Gulf Trace project, is that like just Zone 3 max rates? Is that how we should think about that?

Rory, you want to take that please?

Yes. This is -- Christine, this is Rory Miller. That project is a -- it's a negotiated rate. It will eventually be rolled in, and so it's a little bit lower than what the postage stamp rate would be, and therefore, it's required to be rolled in.

We'll hear next from Ted Durbin with Goldman Sachs.

Just wanted to talk about use of cash a bit at WMB now that you've canceled Bluegrass. How should we think about the disposition there, whether it's the path of the dividends? Maybe it's M&A or obviously, you do have a big backlog of projects that you're developing potentially up at WMB. Can you talk us through that?

Ted, this is Don. Yes, one, we do have -- obviously, we have dividend, but in terms of the excess cash flow at Williams, beyond the 20% annual dividend increase that we've guided to, we do have some projects that are in development that we've highlighted here. And that cash is earmarked for those projects. Beyond that, we'll have a high-class problem of choosing whether or not we have any additional projects or if we just roll that cash into an even greater dividend. So we're moving more and more to a, call it, pure-play HoldCo model. And as WPZ financial capacity grows, we would expect more of the organic growth to be funded at WPZ and less so at Williams. And again, so moving more and more the a GP HoldCo, where Williams can put all -- substantially all of our excess cash flow into the business.

Got it. And then if I can ask about Geismar 2, can you just give us some more color about what that exactly is? Is it an expansion? Is it a greenfield? How big is it? What's the capital? Just maybe some rough numbers there.

Yes. Thanks for the question. Geismar 2 is we're out in the market right now trying to assess the market's interest in participating in an investment there. Our concept, and we're going to be talking more about this at the analyst meeting coming up or analyst day coming up in New York, but our concept there is to build a cost advantage, large cracker. It would be greenfield. We have expanded Geismar, if I could call it Geismar 1 for the moment, about as big as Geismar 1 could be expanded. I think we're about done with expansion save for perhaps some incrementals there. So that's a concept between -- about what we're thinking on this -- another investment on the river in ethylene.

But you would do it as a JV? Or you would do it, a standalone by yourself?

Yes, the current concept is we're considering a JV with perhaps 1, at most 2, other partners that would build derivative capacity alongside it, so creating new demand. And then we would take our volumes and sell them into the market on a fee-for-service basis.

I see, okay. And then if I can just ask one more. As we're thinking about Transco and the ultimate -- and the growth in the Marcellus, even in the Northeast, as you look out 3 to 5 years here and the ability to do backhauls down to the Southeast, what do you think is the ultimate capacity that Transco could move in that direction? And then maybe can you talk about the incremental capital you might need to spend to achieve that throughput?

Rory, could you take that please?

Yes, I'd be happy to take that. With -- if you think over the last couple of years, we've had a series of projects that were primarily designed to move Marcellus supply into the traditional market areas on Transco. The first ones are Northeast Supply Link. The second one was Leidy Southeast. The third was Constitution. Now that's not impacting the Transco system at all, but it's certainly pulling reserves out of that area. And then the fourth project is Atlantic Sunrise. And all of those projects -- or at least the 3 Transco projects, had the feature of taking advantage of some of the latent capacity or latent capabilities that existed on the system to be backhauled or to be designed to change the flow from north to south. As we start moving beyond the volumes that we currently have contracted, the costs do start to go up. And so I think the big question there is where's the market for service for producers in that area to get to an end user that they can contract with, take their gas. And the market's going to have to be higher than, say, the market that was established for Atlantic Access for us to do more. However, if you start looking at new greenfield projects out of the area, you'll be looking at rates far in excess of the rates that we contracted for in Atlantic Sunrise. So I know that's a little bit unclear on -- as to the question you asked, but on a per-unit basis, the capital required is going to be higher on future projects than it has been on the projects in the past.

We'll go next to Sharon Lui with Wells Fargo.

With regards to Bluegrass, do you anticipate that this could be a project you would revisit within a year or 2? And I guess, do you have the contracts set up with Boardwalk to enable you to do this. Especially on, I guess, their ability to, I guess repurpose part of their pipeline?

Yes, certainly, we have a great relationship with Boardwalk, and I would tell you that we're working to make sure that if there is a project there that makes sense, we're -- we got the ability to move forward with the project. And at the same time, Boardwalk's got the rights -- under certain conditions, has the rights to utilize that capacity for gas if they see a demand or a higher value in that direction after a certain period of time here. And so I think we've struck the right balance between us in terms of how to move forward on the project. And so I think it's really kind of a matter of time. I think for the meantime, I think there is plenty of alternative uses or alternative ways to move gas south and quite a bit of capacity to do that on various lines, including the existing -- 2 other existing Texas gas lines that would still be in gas service. So -- or on Boardwalk's system. So I would leave that to Boardwalk to answer a little more -- in a little more fine manner. But from our vantage point, we've struck the right balance that allows us to keep Bluegrass on the table and also, under certain conditions, allows them to move forward with something that makes sense for Boardwalk.

Okay, that's helpful. And I guess, any estimate on the potential financial impact of the Opal incident?

Sharon, this is Don. We expect a $10 million impact on property damage with the excess property damage covered by insurance. We expect the -- I'll call it the business interruption loss to be very modest, particularly given that we already have 2 of the plants back up in operation, and we're hopeful that we can bring the other 2 undamaged plants into operation in the not-too-distant future. So expect $10 million in property damage and a very modest loss related to the downtime.

Okay. And any update on the regulatory front for Constitution and perhaps the timing of that project?

Rory, you want to take that?

Sure. Yes, on Constitution, we have started getting into some of the typical project milestones. The FERC issued a favorable draft environmental impact statement back on February 12, and they'd asked for comments by April 7. A lot of parties were asking to get that date extended. The FERC did not do that and held fast with their schedule, and we appreciated that. I would say, in general, that the FERC has been very workmanlike in terms of laying out a plan and sticking to it. So we're very satisfied with what the FERC has been doing so far. They've been trying to, I think, do their part in terms of helping us get the projects built. Right now we're working with FERC and the New York DEC in a coordinated fashion to try to get any of the remaining questions answered and the details checked off with the hope that we're going to get a final decision sometime later this year. But it is part of a process, and I'd say it's moving well. But at the end of the day, there's probably more things that are uncontrollable in terms of going through the regulatory process than there are in terms of doing just the actual physical construction. In terms of in-service date, I think right now I'd say that what we've guided so far is -- those are still good assumptions.

We'll hear next from ISI Group, Timm Schneider.

I just had a follow-up question on the maintenance CapEx. Obviously, it was $36 million. In Q1, you addressed so many weather issues. But if I go off your full year guidance of $340 million, does that kind of imply -- I just want to get the arithmetic right, that this actually jumps to $100 million over the next 3 quarters?

It actually -- if you look at our pattern of spending on that, Timm, you'd see that second quarter is always kind of our highest because we've got a lot of work going on, kind of winding up, waiting for a thaw out. And so I would say, generally, you'll see our heaviest spending on maintenance capital in the second quarter followed by fairly high third quarter, and then it tends to taper off in the fourth quarter because winter starts to impact our ability to get work done there again. So I think if you look back to our historical patterns, that's what you should expect.

But there's no change at this point to that $340 million?

That's -- that is correct.

Got it. And then next question, on OVM, can you just kind of give us a sense of what utilization rate these assets were running at in the first quarter and what is kind of implied to get to your 2014 guidance?

Well, OVM was running, during the first quarter of this year. We -- let me look at this real quick. We were running at about 271 a day. We obviously have a lot more capacity coming online than that. I'm really not focused on the capacity issue right now. We can take everything that customers can bring to us. We're anticipating having that growing to over 400 by the end of the year. What I'm the most focused on as it relates to capacity really are those issues related to the new assets coming online this year. That will help us both from increasing our fee-based revenue to also maximizing our customer netbacks. And so as you can see the second and third quarter come online with those incremental assets, that's what we'll be really focusing on. And then we'll be taking all the gas that the customers can produce out of OVM.

Got it. And last question for me is on Atlantic Sunrise, is there any read-through on the regulatory front that you guys have picked up from Constitution versus that? Or is it just a completely different ballgame because it's more looping and just compression?

Yes, Timm, I'll take that. First of all, I think one of the major differences is we're dealing primarily with a big chunk of that, will be through the state of Pennsylvania. And I would tell you the state of Pennsylvania has been very businesslike and approached things in a fashion that's very cooperative. And so I think that's probably one of the biggest differences frankly. It is not all along existing right of way, though, just to be clear. There is some greenfield route coming south of the Leidy diamond, if you will, or the Leidy lateral. Where it ties back into our main line is a greenfield. And so we certainly will have routing issues to deal with there that we don't get to enjoy along with looping our existing lines. So there is some existing looping on there, but there's also some greenfield expansion there. But I would just say the area that we're going through does not deal with some of the New York DEC permitting issues that we're facing on Constitution.

And actually, I have one more quick one. In the slide deck, you moved the opportunity set you outlined with PEMEX in the Atlantic-Gulf segment from 2019 to kind of 2017. And I was just wondering if you could talk about those opportunities in a bit more detail.

Sure. That is gaining some steam I would say. I think PEMEX is very focused on developing those deepwater reserves in a very timely manner for a number of reasons I think. I think their elections are in 2018, and I think they certainly want to show that. But I would remind you there that, that 2017 is actually 2017 plus, so not as big a change that we were intending to indicate there. But I would say, at the same time while you ask the question, that they are going to try the accelerate that as much as possible, and that's why a project like or system like Gulfstar, with our existing pipelines in the area and our capabilities, is really important to that in terms of speed to the market. So we're very excited to be positioned well for that opportunity.

We'll hear next from Becca Followill with U.S. Capital Advisors.

On WPZ and your discussion of not issuing any equity in 2015 and minimal equity in 2014, can you talk about how far you're willing to lever up at WPZ in terms of debt to EBITDA?

Now Becca, this is Don. That implies, call that, up to a 4x debt-to-equity -- excuse me, debt-to-EBITDA ratio, so again, well within the BBB investment-grade band that WPZ enjoys. So really nothing in terms of levering up. It's just really the cash flows are growing at such a rapid rate that it creates substantial additional debt capacity.

And does that -- can we translate that over to WMB? And can you discuss your willingness to go non-investment grades there?

I think our position is that this management team and the board chosen to maintain investment grade at Williams, and that's where we're at. But having said that, we'll certainly always be open to looking at what kind of value we can create and balance that with risk. But again, the management team and the board have chosen investment grade at both WPZ and Williams. So it mitigates some risk during more challenging financial times, and puts Williams in a more opportunistic position during challenging financial times. And while things are rolling pretty nicely in the capital markets, we know that, on a pretty regular basis, the high-yield market does shut down. So that's the advantage that having both WPZ and Williams at investment grade provides us.

And then last question is on -- once again on the Northeast volumes and your guidance for the year. The $195 million of EBIT for the year, it's -- should we start to see a material ramp-up in the second quarter? Or is this going to be very much a back-end loaded kind of thing?

Again, this is Jim Scheel. As we look at the second and third quarters, just again to reemphasize, we'll be bringing on substantial new assets during the end of the second quarter. That would be driving additional fee-based revenue. We do see a pretty significant ramp-up during the second -- or during the third and fourth quarter. I've mentioned earlier, I think, in our package that we've provided, we're showing an average of about $335 million a day for OVM. I think that will be a little bit short of that as far as the yearly average goes. Right now we're anticipating about $327 million but ending the year at a much higher rate. So in excess of the $400 million that we're showing there is our current thoughts around that. So yes, we do have a pretty significant ramp-up. And I think that's in line with what you see from others, whether that be ACMP or Blue Racer also showing pretty significant volume growth, as producers take advantage of this gas environment we're in today.

Our next question comes from Bradley Olsen with Tudor, Pickering. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I just want to stay on the Northeast and maybe push a little bit harder on Timm's question, which was related to the utilization rate. Just trying to tie together the kind of disparate commentary that you hear from the upstream and your midstream peers in the Marcellus. We're hearing some midstream guys talk about utilization rates for processing assets in the Marcellus that are kind of in the 60% to 70% range. But at the same time, we're hearing upstream guys continue to mention that they do have wells that are waiting on pipe or stuck behind infrastructure constraints. And so maybe just to kind of go back to that question of utilization rate and just to make sure I understand Jim's comments, talking about the $327 million a day average moving to above $400 million by the end of the year. Am I right in thinking that that's -- you've got the $500 million at Fort Beeler, another $200 million at Oak Grove by the end of this year and I should kind of think of utilization in excess of $400 million across that asset base?

That's right. Not to -- again, I haven't really focused on the ultimate capacity of the system. We're working to fill up what we've got today. But as we look at Oak Grove coming online with TXP-1, we've got the ability to add significantly more cryo capacity at that facility. We can have up to 10 cryos at that facility. We have a great piece of flat land. We'll talk to you a little bit more about this at analyst day. But when I think of the total capacity for the OVM system, were really in excess of 2 Bcf a day. So it's really -- we will be able now, with these foundational assets, to stay ahead of our customers. And so as we see their drilling profiles coming online, we'll be adding additional infrastructure if necessary. It's not going to be near as much pipe. We'll be connecting to the CRPs, making sure that we have the processing and the compression in place in order to meet their needs. And what is so nice now is where we have struggled in the past around some of those challenges, as we've come into 2014, we're well positioned to do that. Customers have recognized the increased reliability and our ability to get their gas to market. So we will build to meet our customers' needs, and we can meet all of the needs that they have today through our assets as we bring on the stabilization, the deethanizer. The ethane line, the additional 24-inch line on the West side and then TXP-1 at Oak Grove, we've got a great story of growth to tell and the ability to meet the customer needs.

So Brad, just to add a little color. That's a great job by Jim kind of describing the situation out there. But it is not as simple as just do I have processing capacity out there. It depends on do you have the trunk line laterals to be able to reach out and get the gas. Do you have the air permit requirements to set compression to pick up the gas? Do you have ethane, deethanization capacity to be able to not get constrained into the interstates and backup gas that way? And so it's a tremendous amount of planning required between the producers and the midstream companies to not have underutilized capacity but to be able to be drilling where the capacity is. And I would highlight a perfect example of that great planning that goes on between us and Cabot in the Northeast. And if you looked at the utilization of our facilities there, you would see it very high, and you'd also see a limited constrain limited to their activity, limited constrained production on Cabot's part, again, relative to their tremendous growth profile that they're on. And so that's a great example of the kind of planning that can be done and that we'd certainly try to encourage with customers. And as Jim mentioned earlier, he's had -- that's starting to be recognized because he's had customers coming into his office wanting to sit down and make sure that they've got capacity for things like some of this burgeoning Utica drilling that is really starting to gain some attention right there in the footprint of OVM.

Yes. And I guess, and even a follow-up to Alan, as we talk about the Susquehanna Supply Hub or formerly ABA market area, up in the Northeast, our capacity will be going up towards the top end of that as we go through the course of 2014 into '15. And we're already thinking ahead of how do we continue to expand that capacity through compression in order to meet our customer needs across the board. Those investments in that incremental volume isn't in guidance but those discussions have already started taking place as working with our customers in order to facilitate all of their needs. And it is a complex issue. As Alan was pointing out, it's one that, I think, across the Northeast, we're getting much better at. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Yes, that's great color. I appreciate those comments and the one -- I guess, the one final question, which kind of relates to the comments about the development of the dryer gas portion of the Utica. Do you think -- you mentioned that you have more of a 2 Bcf a day system in OVM, which I assume refers more to the aggregate gathering capacity. Do you think that you'll be more focused on gathering -- high-pressure gathering services as opposed to incremental processing once you're done with the Oak Grove build-out just due to the fact that the drill bit does seem to be moving towards the dryer areas around that kind of northern West Virginia area? And then just one final one, which is it looks like the kind of per Mcf margin implied by your guidance in Northeast G&P is significantly higher in the latter half of the year than it is currently. And is that just kind of the resulting higher fees that you're able to collect with stabilization, ethane and the addition of the trunk line that you've got laid out here in your presentation? And that's all.

Okay. Well, there are a lot of questions there. Let me start out and let's make sure I don't miss one. Starting out as it relates to the opportunities around the dry Utica, I would say we still continue to be very excited about the wet Marcellus, obviously. We've built a wet system at OVM. It's one where we have the ability to continue to expand our cryo facilities in order to meet that need and maximize netbacks for our customers. Yes, the incremental improvement in fee-based revenue will come through both increased gathering, as well as the additional services provided to our customers. So that will improve our overall revenue position for OVM. As it relates to the dry gas area, I think we're perfectly positioned to go, in the near term, put some of that dry gas into our existing system. Obviously, we won't -- we'll be running that through the plant where we won't be getting any liquids, but with surplus plant capacity right now, we have the ability to do that. And let -- and work with our customers in order to help them identify what they've got. And as far as the resource potential in the dry area, we're all very excited about that potential to the extent we need to have a duplicate dry gas system built because I believe, again, I believe a lot in the wet area. And to the extent where we continue to build out that, it would really be a separate dry gas system. As we think about putting in some of the 24-inch lines, well, there is the potential, I guess, to repurpose some of our lines. Those will be -- that would be on our planning horizon as we talk to the customers. Again, this all really comes back to making sure we're planning with our customers about what they need and when they need it. I think that dialogue is beginning to open up as they learn more about this. And because of our great competitive position in that marketplace, I think we're well positioned to meet any of those requirements as they evolve. Again, a big dry gas build-out though is not contemplated in any of the numbers that you're seeing here today. I don't know if that was every one of the questions, but I think it was. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: No, that's great. And the only other one was just am I right in thinking that margin per Mcf is set to increase in latter portion of the year in the Northeast?

Yes. Yes, it is because the margin will increase because of the additional services we're providing through OVM. In addition to that, we have some higher revenues coming from the recontracting around ABA.

We'll hear next from Chris Sighinolfi with Jefferies.

Just one quick cleanup for me, and actually, it's probably for Don. And this is really just tied to NGL and pet chem. Lots of moving parts in the quarter with BI and the drop-down. But just wondering if you guys could quantify the DCF impact from the dropped assets for the period owned, and sort of how that compares to the guidance you gave us earlier in the year. I think you were looking for 130 to 160 on the full year and so just wondering how sort of initial 1 month of owned DCF sort of stacks up against that.

I think our initial guidance, Chris, contemplated 3 months of ownership of PZ. And as it turned out, there was 1 full month of ownership because the drop-down happened a couple of months later than what we expected when we put out that guidance in the first place. The good news, Williams enjoyed those earnings for January and February instead, and the -- yes, the 1 month was about $15 million to $20 million.

Okay. And then you guys -- just quick follow-up on that. You guys had flagged some tie-in issues and third-party disruptions in 4Q up there. Just wondering if all that's resolved at this point.

Yes. That is a great question now. And yes, we did through the first quarter, but we're tight-lined to Suncor up there. They did have some operating issues at the upgrader, which reduced our volumes approximately by about 20%. At the end of the quarter, all of those issues were resolved, and we're back to full volume. So looking forward, we can expect Canada to deliver at its full potential.

With no further questions in the queue, I'd like to turn the call back to our presenters for any additional or closing remarks.

Okay, well, great. Thank you, everybody, for joining us this morning. As you can tell, a lot of excitement about the quarter and the growth prospects that we have in front of us. And we'd just say we look forward to seeing you at analyst day and sharing a little more of that with you and particularly as we look further in beyond '15. So thanks again for joining us, and we're excited -- we very much look forward to seeing you at the upcoming analyst day.

Ladies and gentlemen, that does conclude today's call. Thank you all for joining.