Good day, everyone, and welcome to the Williams and Williams Partners third quarter earnings conference call. Today's conference is being recorded. At this time, for opening remarks and introductions, I'd like to turn the call over to Mr. John Porter, Head of Investor Relations. Please go ahead.

Thank you, Divona. 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 our Atlantic Gulf area; 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'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, everyone, and thank you, John. Starting here on Slide 4. I love this cover that our IR team came up with beginning. It really depicts all the tremendous amount of activity and construction and project development that we have going on right now at the company and are currently managing. And certainly, this is what is -- will support the tremendous cash flow growth that supports our 20% dividend growth at WMB. It also -- I think it's important to note, this heavy CapEx burden also weighs heavy on our coverage during this supercycle of investment opportunities that we're thrilled to be a part of right now. But before I get into the slide, let me just very quickly remind you of our strategy that continues to guide all of our actions and certainly our investment decisions. And so our strategy, which is to be the premier provider of large-scale infrastructure to design, to maximize the opportunities created by the vastly greater supply of natural gas and natural gas products now known to exist in North America's unconventional resource plays. This is underpinned by our scale, which we see as a competitive advantage in all the areas that we operate. So wherever we are, you'll see us be big. And if we can't be the #1 or #2 in an area, you won't see us playing in a space like that because we think to have superior returns, you've got to have the advantages of scale that allow you to connect to your customers to the best markets. So we want our supply connected to the best markets, and we want our markets connected to the best supplies. And we want to be the infrastructure in between that continues to fuel this tremendous opportunity here that we…

[Operator Instructions] And we'll go to Christine Cho with Barclays.

In last quarter's data book, you guided towards $110 million to $200 million of segment profit plus DD&A for the WMB NGL and Petchem Services in 2014. Can you help us reconcile between that number and the $200 million DCF number you gave for the dropdown? Is most of that driven by the higher propylene prices you are now using in commodity assumption?

Don Chapelle. Yes, it's largely an improvement in margins in Canada as well as lower expected corporate allocated costs. And that's just based on formulas that we continue to implement. So our new organization structure that we announced at the beginning of the year is, I think, bearing some fruit. And our costs are somewhat less than perhaps what we expected before in the Canadian business. It's getting a bit less of that. So I think those are the -- or the NGL Petchem Services business, excuse me in making a more broad statement, is getting a bit less of that. So those are the primary drivers.

Okay. And then how should we think about the potential timing for the additional dropdown that Canada, the 2 other off-gas processing contracts, the 1 -- maybe 2 PDH facilities, maybe Bluegrass. Would you be open to drop it as soon as it's cash flow generating, which may not be a lot in the beginning? Or would you wait until it's a little more mature?

I think it's too soon to answer that question. I think certainly, be eligible to drop at any time quite frankly. But we think that the right answer is to build it at Williams and then drop it once it's in service. And I think we have to take a look at the cash flow profile and determine if it's right on start-up or if it's some time after start-up as the cash flows ramp up. So I think that's a question that's a ways out. It's couple of years out at the earliest, and we'll continue to study that.

Okay. And then what are the tax implications for dropping the Canadian assets? Are you guys subject to any repatriation tax?

We expect -- and I think you'll see it on our 10-Q, to record a tax provision of just over $200 million, cash taxes of about $140 million in the near term. And so it's really an acceleration. We expected that at some point that we'd have repatriation and we'd have a tax to pay. This will accelerate those cash taxes to the tune of $140 million. We'll be able to use excess cash balances, cash balances we have on hand to pay the $140 million. And then after that, we'll have the Canadian tax. Right now the Canadian tax rate is very low, perhaps 0 because much like in the U.S., we have high capital spend and accelerated depreciation that's shielding taxes. But at some point, we'll pay Canadian taxes, and we'll get a U.S. tax credit for the taxes paid in Canada, and we'll pay the differential of U.S. tax. So fairly -- so the onetime cash tax cost is about $140 million, and then beyond that, it will be some incremental amount of U.S. tax over and above what we would typically pay in Canada. Canadian statutory rate is 25%. So again, it's factored, but it's not huge relative to the value of the assets.

Okay, very helpful. How comfortable are you with the new numbers at OBM? Are we largely derisked here? And also the other segment costs in the Northeast segment seem to be really high. Is there anything onetime here in nature? Or is this kind of more of a run rate we should be going off of?

Sure, this is Frank. I think on the -- relative to the Northeast in the volume, I would say that we have probably derisked that some. And really, what I would say is the primary factors. I would call 2013 kind of the lost year. I mean, we really didn't get much volume growth. And basically, what we've -- we're anticipating and what our producers are projected is kind of push, kind of what we were expecting in '13 and kind of roll in most of the drilling plans forward. On the cost side, if you look quarter-to-quarter, we did have -- looks like a pretty significant increase in quarter-to-quarter, other segment costs and expenses around $22 million. But in that number is -- some of that 9 -- the $9 million adjustment that's down below, and we had the continued liability that we booked. We also had some slip repairs that hit us in the third quarter as well as some writeoffs of some investments that we started to undertake in OBM but then did follow through with those. Or we much changed the project scopes, though we had some costs that we had to -- that we're capitalizing, we've had to take to expense. So I think going forward, we'll have a run rate that's less than what we saw in the third quarter. In OBM, we have a liquids system, a gas system, processing plant and fractionation. And we've really kind of set up our organization to have some of those assets in place in 2013. Those assets aren't place in 2013. We won't be looking at material or much staffing increases as we get into '14. So really, we're going to kind of hold and redistribute our [indiscernible] once our assets [indiscernible] and we'll have better defined after the construction and commissioning is completed. So we did have some items in Q3 that drove that number up, but our run rate should be less than that.

Okay, great. And then last question for me. The spread between Texas and Louisiana ethylene prices have obviously been a focus given the pipeline between the 2 states that's down. How are your insurance proceeds going to account for this? I think it was initially thought that the pipeline will be down through year end, but now I'm hearing that it's going to be pushed out further than that.

Christine, this is Don. The insurance policies provide coverage in terms of the lost value in production. So we'll calculate the -- we know what the lost production is. We'll take a look at the market prices, and that would be the basis for our claim. With respect to the pipeline, that's something we're continuing to study to determine what effects it may or may not have. So I'll just pause there and perhaps -- I don't know if Alan or John want to add anything regarding pricing on the pipeline.

Well, just because I asked because are you going to be getting Mont Bellevue pricing or Louisiana pricing? I mean, there's like a $0.20 spread between the 2 points, last time I checked.

Yes, and perhaps I could make some comments there. This is John Dearborn. If we look at the dynamics in the market there, right, with our plant down and Chevron's Evangeline pipeline out of service, the Texas market has got length, and Louisiana is short, right? So that's what we always see, and that's what's driving the premium between the 2 markets. As we look forward and we bring Geismar back up and we expect that some time, Evangeline will be back in service, that same market dynamic is going to diminish in its significance. But let's remember also that second quarter next year, we move into the industry's ethylene cracker turnaround season, and I believe there are about 4 crackers that go into turnaround then. And so as we take a look at all that, in total, we're looking forward at strong demand [indiscernible], which I think is going to support very strong ethylene margins into next year and through next year if we could take you into that line of reasoning, Christine.

Again, this is Don. And I just remind everyone that this pipeline outage is a short-term issue. And we don't expect that to extend all that long.

And recall also that's a Chevron asset. So I think for -- the true story that you'll have to look to Chevron for that as well.

And we'll go next to Holly Stewart with Howard Weil.

Just maybe a high-level question on the Northeast infrastructure issues. I think you guys are probably in one of the better -- or have one of the better vantage points on the pipe side. So what are you seeing in the Northeast, what alleviates the differentials, and what's your view of the differentials going forward?

Holly, I'll take that. This is Alan. First of all, I think there's been a lot of focus on just the Northeast dry area. And certainly, there is more infrastructure over in the Southwest and over in the Utica area, but we're certainly seeing continued a lot of development over there as well. And I would say a lot of pressure has come on -- came on here in the third quarter from 2 factors, one being that certain pipes were not yet opened. So Tennessee expansion wasn't online yet, and so that, we think, will help alleviate. But as well, a lot of new gas came on in the quarter that wasn't necessarily from drilling, but it was from infrastructure tie-ins, not necessarily on our systems. But some of the adjacent systems really worked off a lot of the well connects and a lot of the pending completions. So we saw a tremendous amount of gas come on -- trying to come on in the third quarter, and it was coming into the face of the market that was lower. And so the Northeast Supply Link Project is now up and running, and so -- on Transco, so that's 250. I can tell you that's hardly a drop in the bucket compared to the kind of demand that we're seeing for the infrastructure being built out of the area. But I do believe that the fall shoulders out there are going to be a little worse than the spring shoulders because this is kind of a rare situation up here where you have the Leidy Storage, which is a very large market area storage that refills in the spring but, of course, was full in the fall. And so nowhere for that gas to go either into those local…

Got it, okay. And then I guess you gave an explanation for the, I guess, weakness in the Northeast volumes compared to maybe what you'd initially forecasted. Are -- in terms of these new customers or now the majors, are -- what are you assuming for growth in '14 and '15? I guess my point, are you comfortable that your new targets have some of their plans factored in?

It is. It's really kind of built from the ground up, looking at the drilling plans that we've discussed with the producers. And so we feel pretty comfortable. I would certainly -- wouldn't try to tell anybody it's not without risk because there's a lot of continued infrastructure development to be built out there. But I would tell you that we feel pretty comfortable with the schedule and the detail that we built behind the volumes at this point. And so it really is kind of a grounds-up review from each of our producers and their drilling plans out there. I do think there -- perhaps there's some opportunity to improve on that. If we saw some better pricing signals and people become convinced the Bluegrass is going to be -- get built, we might see some even better development into the '15 timeframe as people gear up for that.

Okay. And then you kind of led me into my final question. Can you just maybe explain the open season for Bluegrass and how these commitments will really work on the Bluegrass pipeline and the LPG terminal?

Well, I would just say that the open season for the pipeline is completely separate from the fractionation and the export terminal discussions. Having said that, we recognize that customers don't want a pipeline to nowhere. And so that's why we've been working so hard at developing both the storage, the terminal and the export facilities is that we've got to be able to provide customers with a comprehensive solution. And I would -- the thing I'm fairly encouraged by in that regard is with the discussions we're having on the export side, we're seeing interest in customers wanting to know where that supply is going to come from as well. And so I think the market's really starting to come together in terms of the supply side and the demand side. And we see that as one of our critical roles in the industry right now is bringing together that strong demand that we're seeing from international players back upstream to our customers on the upstream side and being the party providing the infrastructure in between.

Okay. So it's not all comprehensive in terms of at all getting built.

Well, I would say that at the end of the day, people are going to want to know what their frac deal is. But that's a -- just because of regulatory process, that's a bifurcated process. So we deal with them in the open season, and we make sure that everybody has a chance to weigh in on the capacity that they want and the terms of the capacity they want on the regulated side. And so we make sure that's a nondiscriminatory process. And then second to that, then there's a discussion around what people's needs are for storage, fractionation and export capacity. But I would say that most customers are going to want to know what their deal is on both sides of that. So on one hand, they're separated for regulatory purposes, and on the other hand, people need to know what their downstream services are going to be.

We'll take our next question from Stephen Maresca from Morgan Stanley.

Just sticking on Laurel Mountain and OBM for a second, and to be more specific, you took Northeast adjusted segment profit and DD&A down about 20% in '14 and '15. Can you help us understand what changed so materially in such a short period from last quarter's forecast to now? I know touched upon it, Alan. But is it as simple as just your drilling plans are off because of the change in ownership? And as a subset to that, it seems like you dropped the '16 and '17 kind of bar chart forecast you had in your slide deck in terms of gathering volumes for the Marcellus. Did -- is that a sign or do you not feel as comfortable forecasting that anymore in light of the changes in ownership from private equity to bigger majors?

I would just say our -- what we're seeing from the majors is, as I said, just a more careful effort on their part to make sure they maximize the NPV of their reserves and not just to quick-drive towards IPs [ph] and volumes. And so -- sorry, IPs and reserve growth. And so I would just say that we've -- what shifted really was having -- sitting down and wanting to make sure that we weren't investing capital too far out in front of the reserve packages that we're seeing there and not taking on additional risk. And so that resulted in sitting down and getting very detailed granular analysis on what their drilling plans were. And as you know, that's a little harder to predict because the motives of the majors are more around allocating capital around, and so it's a little harder to predict than somebody who just has one resource to go develop. And so I would just say we've gotten a lot more conservative in our approach towards that forecast, and it's just built from the ground up. And that probably is -- the major shift that we made, Stephen, was moving from a resource capability play to a detailed analysis of what the producers are actually doing and their actual drilling plans.

And, Steve, we ceased to project '16 and '17 given the challenges we've had in projecting the next couple of years. So we've -- we're really focused on projecting '14 and '15 and just conforming the volume forecast to our guidance period and really not trying to get too far out given all the variables that we see in the Northeast.

Okay, appreciate that. Moving to Bluegrass, I just have a couple of questions here. Alan, do you have the same level of confidence in this project getting completed as you did on the last call given the large competitor project proposal? And can you talk at all -- ballpark types of project returns you would expect? And then I have a second one just on the funding after that.

Well, I would say on the confidence level, I think this might surprise some people. But the confidence -- my confidence level is not really all that driven at this point by the competition, by the competing project just because we think we're so far ahead in terms of development of the project and details and how far ahead we are in terms of getting project developed. I think the -- so I would just say that's not really that big a factor frankly. I think the challenge that still remains is producers knowing their drilling plans, being committed to the drilling plans. And so I think we may get a lot of commitment, but we're going to need to be weighing how solid that those volumes will be and how much we can count on those volumes being there. And so that's what we're in the process of doing with the open season. And as I've said before, we're very excited about Bluegrass. We think it's a really key piece of infrastructure for the Marcellus and the Utica. And we think that it really, really needs to be installed at the end of 2015 to protect our investment on the upstream side and other investments or other more indirect investments that we have up there. So we think it's very important, and we think Bluegrass is the only one that can really meet that kind of time line. So that gives us a lot of confidence, but we're also -- we got a lot of projects to invest in, and we're going to make sure that it's a sensible investment for us before we plow -- start really plowing the big money into it in the first quarter of 2014.

And, Steve, this is Don. In terms of financing, again, we have a partner at Bluegrass. And I'd also note that we've been approached by others, industry players and financial players that would like to invest in the project, and we may or may not choose to partner with others. But beyond that will be a combination of debt and equity to maintain our credit rating goals, which we have previously consistently espoused as investment-grade ratings.

Okay. One follow-up there. Have you thought about something at all, doing something with your Access GPL [ph] stake, to monetize that and create some liquidity? Or is that not something that's on the table right now?

All right. I think all of our assets are things that we evaluate all of the time, and certainly, those are assets that we continue to look at as well. So I certainly don't want to create an expectation, but we certainly look at all the levers that we have to pull as we look at potential financing.

And we'll go next to Ted Durbin with Goldman Sachs.

Not to stay too much on the Northeast GMP, but we do have a pretty significant cut in EBITDA but not really any change in the CapEx forecast, from what I can tell from last quarter. So we're effectively saying we're getting lower returns on capital. I must -- I'm missing. Is there any reason why the CapEx budget may not have gone down given the slower volume ramp?

Yes, this is Frank. What we've done is we basically cut more of the capital out in the out years. We've taken out the third train, frac train. We've pushed out the second, third and fourth processing plants. So we've kind of -- basically, we're focused on installing the -- let's say those foundational assets, the second frac expansion, the stabilization plant, the deethanizers, the ethane pipeline. Once we get all of those assets in place in by 2Q of '14, we'll -- pretty much of that, majority of those what I would say is the foundational assets in place. Some of the assets have installed costs, have gone up some, so that's part of the reason we've kind of had -- we haven't had the 2014 capital change. If you look, most of it shifted from '13 to '14, and that's the representative of the shift in in-service date. And then most of our growth capital has been pushed out to match the volumes being pushed out.

Okay. That's helpful. The -- just shifting over to Geismar. Can you give us an update on where you are with some of the regulatory side of that in terms of the -- whether it's OSHA or [indiscernible]the other folks sitting there, looking at it?

Sure. I'll have John Dearborn answer that for us.

Sure, and thanks very much for the question. Our relationship with both the agencies remains extremely strong and excellent. And we're committed to keeping it up certainly that way. With the government shutdown that we all witnessed here the last few weeks or so, we've suffered a bit of a delay, all right, as that shut down the CSB and the OSHA work for a bit of a while. However, prior to that shutdown, we had all the necessary protocols in place to continue our work around the propane propylene fractionator that was damaged. And so we've continued our work, and we don't expect to suffer any delay in what we're doing as a result. One of the other things, though, that I'd like to bring to your attention in order to continue to build this relationship with OSHA and CSB is, you might have noticed that we've released the findings of the Williams investigation, and we're taking care to communicate those findings to all of the important stakeholders, of course, our employees being one of them. But we took the time and effort to communicate that to OSHA and CSB, and of course, they were grateful to that -- to us for that. Bottom line is we still expect the OSHA to issue their report around the beginning of the New Year, and that's the next important milestone, I think, relative to the federal regulatory agencies.

Very helpful. And then last one for me just on the costs. You did actually take out a lot of costs, it looks like out of the West segment. And I'm just wondering if we should think of that as a sustainable new run rate? Or is there any kind of onetime lower OpEx you may have had there?

I think -- this is Allison Bridges. Yes, we have seen some lower cost especially as a result of some of the reorganization that Don spoke about earlier, and some are the allocated costs that we get in the plants.

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

Just actually a few clarifications of things that were said prior and maybe first starting on the Northeast on OBM. And, Frank, I think you mentioned this, but just to be clear that essentially, the pushout that we have seen in some of the milestones, the Moundsville fractionator, et cetera, that is all very deliberate with respect to matching up to industry activity, right? That's got nothing to do with execution, is that correct?

I would say that the Moundsville frac train 3 is probably associated more with preserving that decision to be in line with the Bluegrass decision when we make that determination. I would say that moving the Moundsville frac train from 3 or 4Q of '13 into 2Q '14 is a function of just physical execution of the projects that we've seen in that area.

So to be clear on that, the demand is there for the first expansion or the Phase 2 Moundsville, and it's a matter of getting that project completed. The decision for laying down third is just because we think Bluegrass will reduce the need for local fractionation. And so we think that we're becoming more and more confident on the timing of Bluegrass such that we don't need to have both the local frac and a Bluegrass solution.

Yes, definitely, the second frac train at Moundsville with 30,000 barrels a day is definitely needed as well as the stabilization plants and the deethanizers. So those are all on track for completion in '14 to support the drilling programs in place.

Okay. No, I -- that's helpful. And then, Alan, just to kind of go back to the Bluegrass and understanding the commercial sensitivity of where we are right now, but I guess, as you guys have opened the biddings -- the open season here. Is the general approach a minimum take-or-pay type of commitment? Or isn't there something where, for the right price, you're willing to take volume risk?

Yes, because that's a regulated asset, we offered out a, I think, very intelligent response to the market that allows us a considerably higher rate for people that are just wanting to dedicate acreage but not make volume commitments. And then a very attractive rate to the degree people are willing to make a volume commitment. And there's various steps in between that. And so we basically provided a menu for customers, and then we still -- once we get all that built into our analysis in terms of those options, then we can decide whether that we think that degree of support justifies the investment and the project. So it is a menu, and it's, like I said, a very attractive rate if you compare it to, like, an ATEX ethane where it's a pay -- ship-or-pay kind of obligation on one hand. Then on the other hand, up to a volume dedication with -- or sorry, an acreage dedication have much higher rate but one that gives producer flexibility.

Okay, appreciate the clarification. And then maybe just last question back on Geismar and the business interruption insurance. And I guess now that we have $50 million recorded agreed to, I guess, by the insurance companies, and I guess the number is refined a little bit more from sort of the initial preliminary estimate. Don, do you feel more comfortable around the uncertainty range, if you will, around that number today versus, say, for instance, on the second quarter call? Meaning, have there been deliberations with the insurance companies that have tightened perhaps the deviation of where that number can go to? Or is it basically, each time a new claim is filed, it's a new claim, a new process, so to speak?

No, I think we feel comfortable with our claim amount. Clearly, we have a good read of the policy, and we certainly know the lost production, the actual amounts to be determined based on the market prices and we would have realized. So that'll be dependent on what happens on the market over the coming quarters. But certainly, in terms of the volume, the lost production, we know that pretty darn well. So we think we've got a solid basis for our estimate here. I think the initial $50 million payment evidence is good faith on the part of the insurers. They stepped up and paid us $50 million in advance of our actual claims because our out of pocket around the physical damage was not that substantial yet and we only had 13 days of covered loss under business interruption during the month of August. So they actually, I think, made a good-faith early payment. So I think that's a good sign. Our next covered loss under business interruption would be for a partial month in October, so kind of the end of October. That's when we assume that the expanded plan will come back to service. So we'll file a claim for the month of October during the month of November, and then we would to expect it will take the insurers a month or so to respond to us. And we're -- and that will be the process every month. So partial month in October filed in November, give the insurers a bit of time to review that claim and respond to it. And then we'll have a full month loss in the month of November, file that claim in December, and again, the insurers, a bit of time to respond to that. So I think from a process standpoint, it's pretty well established. I think volumetrically, we know what our losses are, and we're mitigating the losses to the best of our ability, the economic losses. And then I think we'll see where market prices turn out. But again, we've outlined in our guidance what we expect the lost profits to be and the market price assumptions we've used there, and that's really what's guiding this claim.

And next, we'll go to Bradley Olsen with Tudor Pickering. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: We saw on the Leidy Southeast project, most of the shippers on that project were downstream or LDC. Are you seeing more upstream demand as you've gone out with the open season on Atlantic Sunrise?

Yes. Alan, would you like me to take that?

Please, Rory. Thank you.

Yes, Bradley, this is Rory Miller. It has been changing, and there was an earlier question about pricing in the Northeast. Of course, we're looking through a knot whole, a bit there. But certainly, what we've on the -- our current Leidy system that moves about 3 Bcf a day, there's much more gas than that trying to get into that line every day. We've got 8 Bcf a day of interconnections there. And so there's a lot of gas-on-gas competition for things that are playing in the spot market, and the prices have been at huge discounts to the Henry Hub. So I think that really is leading up to the answer to your question, and that's that we've seen a lot stronger response from the producer community. That being said, the people that made requests within the open season were fairly balanced between the market side and the supply side. But the producers were definitely stepping up in a much bigger way than what we've historically seen on Transco. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, great. And you alluded earlier to having interest from potential partners in the Bluegrass project. And in the past, with projects like Constitution, you've obviously brought E&P partners into the project to secure volumes. Have you found so far that there are E&P shippers who are maybe making their participation in Bluegrass contingent on getting a significant equity stake in the project?

No, we really haven't seen that from the key customers that we're talking to because it's such a big investment. Mostly -- usually, when we have the parties that are wanting to take equity, it's a project that's fairly specific to their needs. So for, instance, Constitution with Cabot. That project was mostly -- capacity mostly taken by Cabot, and they wanted to make sure they were involved and had a stake in making sure the project was executed well and as well enjoyed some of the economic benefit of their capacity obligations. I think in Bluegrass, we've got a variety of different shippers such that it's not enough -- nobody has a dominant position in the pipeline, like we've seen on some of those other assets. Having said that, I would tell you there's a lot of interest from more strategic players, I would say, in wanting to have an interest. But it's likely not going to be the -- from the E&P side for the reasons I stated. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Got it. And the MOU that you alluded to last year when you acquired the ACMP interest that Chesapeake would -- at least intended to commit volumes, is that still an agreement that's in place as it pertains to Bluegrass?

Yes. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, great. And then just jumping to the Canadian side, just in rough numbers, maybe when you think about the top line in the Canadian off-gas processing business, how much of the revenue is there? And I realized it's kind of a key polar arrangement in the off-gas processing, but what percentage of that margin is coming from the olefins side versus from just the NGL side?

We'll have to get back to you on that. It's -- that mix has moved a little bit just recently as now we're starting up the ethane recovery plant. And that business, as I remind you, is a floor -- has a margin on it that has a floor that we're operating at because ethane is it's based off of Bellevue ethane. And therefore, that will be a fixed fee that will not be commodity-sensitive. But we can get back to you some detail. I don't have that right off the top of my head here.

That would -- and it is John. The precise number for the majority would be NGLs and the minority being the -- being olefins up in Canada today. Bradley Olsen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, great. And just one final one. Looking through the guidance, and there are a couple of other questions that alluded to this point, in the Western segment, you mentioned some of the things in the field that you were doing more efficiently. And certainly, it looks as though there was a big move up in 2013 full year EBITDA guidance, and fairly sizable move in '14 and then a little bit smaller move revising upwards in 2015. Maybe just qualitatively, if you could talk about why is it that the benefit from those cost-cutting or efficiency gain initiatives that you're taking gave a larger -- provided you with a larger step-up in guidance in '13 and '14 than it did in '15?

Well, I think what you're really seeing there is just a lack of confidence in drilling volumes continuing out West is really what's driving most of that. And so the cost savings, I think, are very apparent to us there. But I would just say I think most of that is driven by an expected decline in volumes out West.

And we'll go next to Curt Launer with Deutsche Bank.

Two questions if I may, one more back to the Marcellus. In the 10-Q, you're referring to less favorable economics in the Western region. And I think that's been discussed a lot already in this call. But from the standpoint of the lower volumes in '13, what are the conditions, what are you seeing relative to your discussions with producers that could make that materially better in '14 and '15? Clearly, we think about it from the standpoint of NGL takeaway capacity boosting the netbacks. Or is it a question of natural gas prices needing to be higher that would spur that activity?

Yes, this is Frank. I'm assuming you're referring to the Western part of the Marcellus...

That's correct.

Or our Eastern business up there? I would say that the biggest thing we see relative to the Western area and volumes is more a function of what the ultimate netback might be for those areas, especially as you get into Northwest Pennsylvania, Northeast Ohio, some of those areas that are very infrastructure-challenged. I think in the -- our area, especially in the OEM area, I think we have -- we saw an improvement in the netbacks when we brought our fractionation train on, and we're going to see continued improvement in the netbacks to the producers when we bring this stabilization plan and the next fracturing as well as rail load facility. So for us in OBM, I think it's going to be able to show its consistent ability to get the commodities sold into the market. And I think that's what's going to support in our area we're currently operating. But I do think the Western part of the Marcellus, it's going to see -- and even Ohio, it's going to see -- we'll see some -- some of us could see some of the same pinching of basis relative to net gas sales and NGL prices as supplies outstrip, being able to get those commodities out of there.

Okay. And switching gears to the Canadian assets. I wanted to ask if there's anything you could tell us that will help us model that into the outlook here. You mentioned the PIK units certainly, but what would be the expectation relative to debt as being part of the financing package as the assets are dropped down?

Curt, this is Don. Again, I think, as Alan mentioned, we expect the multiple not to exceed 7x on the purchase price. We expect it to be all equity. That's advantageous from a tax standpoint to Williams. Again, we defer taxes on that basis other than this tax that's triggered by changing the ownership -- structure of the Canadian assets to WPZ. So that's really the driver there. I hope that responds to your question.

And we'll go next to Becca Followill with U.S. Capital Advisors.

Is there a fine on Northeast -- I'm sorry to keep harping on it. But I think you talked in all those slides, you're deferring $200 million a day processing out of '15 into later period and 30,000 barrels a day of frac. Yet we don't see CapEx go down. Can you reconcile that?

Yes, I think what we've done is we need the second fractioning. If you look at our 2014 volumes, our 2015 volumes in OBM, we will need to start to put the second $200 million a day train that drove in. But a lot of that balanced plant work has been done as far as the initial work. So we don't have a significant, significant requirement. But we have pushed it out to where we may not have to spend those dollars until 2016 given the current volume forecast that we have today. So you have -- that's probably the only asset that we've kind of shoved out of the '15 into '16 relative to kind of assets that you've seen before.

I think the frac capacity sound like 30,000 barrels a day also.

That's the other thing, yes, that I mentioned earlier.

So are you saying that the CapEx -- you've already spent the dollars on that, and so that's why we don't see CapEx coming down?

Well, we purchased the frac train. So we have that in our inventory, wasn't going to redeploy that in either some of our other opportunities that we have going on today whether it be up to 3RM [ph]. But today, most of the CapEx -- to get the kind of the investments that you see as -- on the slide, Slide 8, most all of that capital will be deployed in 2014. We have a little bit of capital in 2015 that prepared to get the second Oak Grove facility on. That one would be in our 15 plan. But beyond that, we've pushed out frac train or processing plants 3 and 4 and some of the other things that we've had in our 15 plants.

Okay. And then this is -- it's smaller in the scheme of things and I don't have all the numbers in front of me. But looking at the maintenance CapEx, in this guidance, it's down by $85 million over the 3-year period and it looks like the last -- probably the last 4 quarters, maintenance CapEx keeps coming down. In an aggregate, it's material relative to the size of maintenance CapEx. Can you talk about what is it driving that and your thoughts behind the maintenance CapEx?

Sure. As I mentioned earlier, we're still spending a very large amount of our profit particularly within the pipes. In fact, over 35% of our segment profit, we're putting back into maintenance CapEx if you take the 3-year maintenance CapEx and put that over the -- our segment profit. And so very significant amounts still going into that. But I would say that we invested very heavily in both '11 and '12 in catching up and beating the deadline that we had relative to some regulatory requirements for getting some of the asset integrity work done on the pipeline. So we had kind of a lot of that capital squeezed in to the '11 and '12 period. And as well, we also had things like we had some work that we had to get done for the Clean Air Act on -- so on our compression, on our major pipelines that we had to get done as well. And so again, those kind of culminated in '11 and '12. And so we've been working that hard in terms of getting done what we needed to get done for those timeframes. But it's allowed us a little bit of relaxation here in terms of that heavy capital spending in the guidance period that we have before us.

I understand why it was higher in '11 and '12. But what I don't understand is why the guidance keeps coming down for '13 through '15 because I mean, that's past. So why would the guidance keep coming down?

I don't think I can -- sorry, I didn't follow your question there. Well, a couple of things. One, with the continued decline in volumes in the West, we have less maintenance CapEx. And we've made some decisions, as I mentioned earlier, for doing things like taking the Lybrook plant out of service. So some of our older fleets out West is a result of the volume reduction, and those older plants, as you can imagine, suck up maintenance capital. And so those changes have been made to our Midstream maintenance CapEx and on the gas pipes. One thing we did do -- and I'm not sure this is a major driver, but it's certainly embedded in here, is we had some pressure-testing obligations that we were trying to get all done by '18. We took a really close look at those in terms of really where we needed to reduce risk on the system and negotiate it with FEMZA [ph] to -- and got them to understand that really, the better risk reduction was spreading out that timeframe on some of that pipeline integrity work. So that spread things out a little more versus where we had some dollar spending in there in '18. So that's a little bit of that reduction on gas pipes. But I think the major reduction you see is really on the Midstream side. And it really is the teams out West working pretty hard to reduce our maintenance capital out West, and it's resulted in reducing volume.

Alan?

Yes.

One other item, too, that's probably worth mentioning to Becca here, the -- with the changing flow patterns on the Transco system, where we're now getting a lot of our supply or much of our supply from the Northeast as opposed to just the Gulf Coast. The middle portion of our system is the compression on that portion of the system is running much less frequently. So we're having a lot less hours on those units. We're having a lot less maintenance there, and our turbine change-outs are being able to pushed out in the future years. So as we kind of put that whole new dynamic into the equation, that's also a bit of a significant impact.

Great point. Thanks, Rory.

Yes, and this is Allison Bridges. And I would also just like to add to the lower sort of maintaining the facilities. We do have some pretty significant reduction in well connects than we had previously had. So at least for the next few years, that's continuing to come down.

We'll go next to Selman Akyol with Stifel. Selman Akyol - Stifel, Nicolaus & Co., Inc., Research Division: In terms of the Canadian assets, in your assumption there of the $200 million, what capacity utilizations have you guys assumed?

They're flexible. There are -- there's actually 3 assets there to be thinking about. One is the -- is liquids extraction plant up in Fort McMurray. The other is the pipeline, and the other is the fractionator. In terms of our operating in the next year and future years, the fractionator is going to be running near to full capacity. We'll need some incremental expansion in order to accommodate CNRL plant and the liquid extraction plant up in Fort McMurray when the upgrader is running -- be running pretty much full out because it's a dedicated to that facility.

I'll take recovery point.

I'm sorry?

I'll take recovery point. Can you do the other? Let's partner. I would also add to that. Normally, we build into that about a 97.5% run time. So in terms of how much, that's up and that's consistent with our typical capabilities. And perhaps, you can speak to the pipeline?

Yes, the pipeline will have a little bit of excess capacity as we -- we'll have some room on it as we bring on these other projects into the future. Selman Akyol - Stifel, Nicolaus & Co., Inc., Research Division: Great, And then just to confirm, are you still looking for an April 1 start on Geismar?

Yes, that is correct.

That concludes today's question-and-answer session. Mr. Armstrong, at this time, I'd like to turn the conference back over to for any additional or closing remarks.

Great. Well, thank you very much for joining us today. We are blessed to have such a great portfolio of growth -- major growth projects to pursue, and those keep coming on. And that gives us confidence in our ability to continue to grow our WMB dividend and our distributable cash flow at WPZ for many years to come. And we certainly are excited to make the step we're making on the Canadian asset dropdown, which moves us closer to a pure play. But we also retain the benefit of some very significant dropdown candidates for WPZ in the future. So we think structurally, we're very well positioned. And we think in terms of our business opportunities, they just couldn't be more robust. And the team is very excited about continuing to execute and deliver on this tremendous cash flow growth. So thank you very much for joining us this morning and for the great questions.

Thank you. This does conclude today's conference. We appreciate your participation.