The Williams Companies, Inc. (WMB) Q4 2015 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to The Williams/Williams Partners 2015 Year-End Earnings Conference Call. Today's conference is being recorded. And at this time, for opening remarks and introductions, I would like to turn the call over to Mr. John Porter, Head of Investor Relations. Please go ahead, sir. John D. Porter - Director-Investor Relations, Enterprise & Planning: Thank you, Angel. Good morning and thank you for your interest in Williams and Williams Partners. Yesterday afternoon, we released our financial results and posted several important items on our website. These items include yesterday's press releases and related investor materials, including the slide deck that our President and CEO, Alan Armstrong, will speak to momentarily. Our CFO, Don Chappel, is available to respond to questions. And also we have the five leaders of Williams' operating areas with us: Walter Bennett leads the West; John Dearborn leads NGL & Petchem Services; Rory Miller leads Atlantic-Gulf; Bob Purgason leads Access Midstream; and Jim Scheel leads Northeast G&P. In our presentation materials, you will find an important disclaimer related to forward-looking statements. This disclaimer is important and integral to all of our remarks and you should review it. Also included in our presentation materials are various non-GAAP measures that we reconcile to generally accepted accounting principles. These reconciliation schedules appear at the back of the presentation materials. Over the past many months, we've taken many questions related to the merger between Williams and Energy Transfer. The focus of our call today is our fourth quarter results and business outlook. So we're not going to take questions on the pending merger or other related matters. However, before we discuss our fourth quarter and year-end 2015 results, I can provide a brief update on the transaction. Williams' Board of Directors is unanimously committed to completing the transaction with Energy Transfer Equity per the merger agreement executed on September 28, 2015, as expeditiously as possible and delivering the benefits of the transaction to Williams' stockholders. Completion of the pending transaction remains subject to the approval of Williams' stockholders and other customary closing conditions. Integration planning is underway. As previously discussed in Energy Transfer Corp. registration statement on S-4 filed November 24, 2015 with the SEC, ETE and Williams received a request for additional information and material from the FTC pursuant to the HSR Act review. On February 1, 2016, Energy Transfer Corporation received additional comments from the SEC related to the first amendment of the S-4. Certain requests made by the SEC relate to information that will be included in ETE and Williams' 10-Ks, which the companies expect to file the final week of February 2016, so next week. Therefore, the companies now expect to file a second amendment of the S-4 shortly after filing those 10-Ks. With that update, I want to reiterate that we won't be taking questions regarding the pending merger or other related matters. As always, please feel free to contact our Investor Relations teams for questions you may have. Thank you all in advance for your cooperation. And with that, I'll turn it over to Alan Armstrong. Alan S. Armstrong - President, Chief Executive Officer & Director: Thank you, John, and good morning, everyone. Thanks for joining us. This is going to be a fairly brief presentation, we do want to – we will take a look at the fourth quarter results and also drivers for the full year. We'll offer our perspective this morning on one of our very important customers, Chesapeake, and a lot of concerns have been raised there. And we'll look at upcoming drivers that'll drive 2016 along with our 2016 capital plan. And then, finally some thoughts on the strength of our strategy in this difficult commodity price environment. We're very pleased with the way our business is holding up and as well, the kind of opportunities that continue to come at us in our effort to continue to connect these low price natural gas supplies into growing demand markets. So with that, let's look on slide two here. We recorded another strong quarter demonstrating our continued project execution, reliable operating performance and the resilience of our business to grow despite sharply lower commodity prices and what turned out to be a very mild start to the winter here in the fourth quarter. Even with the reduced producer activities in the supply areas, we enjoyed continued growth in fee-based revenues, primarily from demand-driven projects and expansions that were brought into service during the year. Our continued focused on a clear strategy, project execution and cost management are evident in our results. And very importantly, despite the pressures impacting the industry, we once again saw the dramatic growth in our fee-based revenues offset the impact of continued lower commodity prices. In fact, our adjusted EBITDA was up 25% over 4Q 2014, and our full year adjusted EBITDA was up a total of 26% despite very low NGL and olefins margins. In fact, I think impressive status across all of our system. Just on our gas gathered volumes, we were up off a very big number in terms of our total gathered volumes. We were up 6% on total gathered volumes for the year despite a lower producers activities and a lot of very significant curtailments that continue to exist. Looking directly at the fourth quarter, the WPZ DCF of $718 million produced a coverage ratio of 0.99x and, of course, this is before we would – if you were to include the substantial impact of the $209 million IDR waiver. This would lift our coverage up to 1.39x. And of course, this is not insignificant and certainly provides support for funding our 2016 growth capital program. Highlights for the fourth quarter of 2015 to the fourth quarter of 2014 comparison, I'll just give you the highlights here. First of all, fee-based revenues were up $139 million or 12% and that was driven primarily by Atlantic-Gulf and with a lot of fee-based assets that came online during the year and as well as growth at Access. Our olefins margins were up $43 million to $71 million, and this was strong operating performance at our Geismar plant with low per-unit margins due to low olefins prices. So, great results on the operating side at Geismar and actually across all of our NGL & Petchem Services during the quarter, but relatively low olefins margins there in the fourth quarter. The proportional EBITDA of equity method investments were up $37 million or 22% and most of that was coming off of our Discovery asset where the Keathley Canyon Connector continues to perform very well. There was a little bit of maintenance during the period, but those volumes remain very strong out there on that system. NGL margins were down $45 million or 52% and NGL prices now in the fourth quarter were 13-year low. And the full year 2015 NGL margin was only $160 million, which represents less than 4% of our consolidated EBITDA during 2015. And I did want to make a note have here on the impairment. We took some very large impairments in the fourth quarter, and these were largely a result of dramatic decline in the market value of WPZ and some tests required there up against the full market value and in the fourth quarter. So that was the value of WPZ in the fourth quarter and then the implied market values of the investments and associated goodwill. So looking at the total market value of WPZ up against the implied market values of our investments and associated goodwill. Of course, as you'll recall, the impaired equity method investments and certain of the impaired goodwill relate primarily to the acquisition of Access Midstream Partners, which we were required to book a significant $2.5 billion gain in 2014 and this reflected our purchase price allocation to these assets in 2014. So, as you'll recall, we had a big gain in 2014 associated with that acquisition and a lot of that goodwill then was taken out with this new test against the market value. And so, now, just a few thoughts on the result by segment. Atlantic-Gulf had another great quarter, up $122 million all on fee-based revenues and so very impressive growth continued there in the Atlantic-Gulf. And for the full year, Atlantic-Gulf was actually up $453 million and a lot of this is coming off of projects like Gulfstar One as well as the Transco expansion projects, and again the Keathley Canyon Connector on our Discovery system, so tremendous growth there in our fee-based revenues. This was offset a little bit by lower NGL margins, of course, but overall really very impressive performance. You might have noticed as well that Atlantic-Gulf had a little bit of higher cost in the fourth quarter and most of this was just related to – we had some repairs on the Leidy Line, as well as some additional testing required by the regulators there. And so, we continue to work on the Leidy Line there where we had a rupture on that line earlier in the year. And so a lot of continued work there that shows up in our O&M expense. On the Access or what will now be the Central OA, we reported fourth quarter of 2015 adjusted EBITDA of $351 million and that was compared to $325 million, and a lot of this was just driven by a continued growth in the business. But we did as well have an increased ownership interest in the Utica East Ohio Midstream joint venture that helps drive some of that as well. On the Northeast G&P, flat fourth quarter 2015 to fourth quarter of 2014, but a 30% growth year-over-year. So, we were at in 2014 full year was $276 million and we were up $80 million to $356 million here in 2015 and for the full year. So, really driven by continued increased service fees at Ohio Valley Midstream, higher overall volumes and those were offset by some higher operating expenses, including some line repairs that were required earlier in the year as well there. Really important note here, we did sign a new gathering agreement with an existing customer during – here very recently and we were really excited about this that it's going – we do – it does produce a lower rate for the customer, but we've got some incremental volumes that are coming on associated with that agreement as well as some much larger acreage dedications that came with that. So, really excited about this new agreement. And we're not counting on any new drilling anticipated here for 2016 on that. And even without that new drilling, we expect our revenues to be held flat for 2016 despite the lower rate just because there are some new volumes that come to us as a result of transaction and some new wells – or some new production that's being tied in. So a lot of similar story in the Northeast where we continue to tie in production that's already been drilled. We're really not relying in the Northeast. We're really not relying on new drilling rigs out there. We're really just relying on tying in, continued tie in of production. But the real key force there will be when we start to see some of the takeaway projects take hold because that clearly is the constraint out here. It's not a matter of rigs running in the area; it's simply a matter of seeing some these big bottlenecks open up and then us tying in a lot of this already completed production and seeing that flow for us. In the fourth quarter – sorry, on the NGL & Petchem side, really great operating results for NGL & Petchem from an operating standpoint, but we did have lower unit margins during the period. So really pretty good operating stint, both in Canada and Geismar in terms of volumes, but again very low unit margins. Just to remind you there, for the year, we were $216 million lower, but this was due to the lack of the insurance proceeds and about $89 million lower commodity margins. So a big step down, but again most of that was just due to the loss of some assumed business interruption proceeds that we booked in 2014. In the West, great continued focus on cost management in the area. We were off about $15 million versus fourth quarter of 2014, and that was really driven by $27 million lower NGL margins as compared to the fourth quarter of 2014. And again, I'll remind you, NGL margins are now at a 13-year low. But really proud of the team out there and their continued focus on cost management and able to continue to generate very significant EBITDA despite low prices. Moving on to slide three, this is a really important slide here we wanted to show you. We certainly had a lot of questions about Chesapeake and our relationship and a lot of focus by investors on the credit risk related to Chesapeake. And so we really wanted to just take this opportunity to walk everyone through some facts and some of our perspective as a midstream service provider that plays a critical role in getting the natural gas production from a wellhead to marketable condition and location. So, first, I note that we have a very strong relationship with Chesapeake. We appreciate them as a great operator in the nation's very best shale resources. They have some of the very best acreage in large contiguous blocks, and we are very pleased to have the opportunity to serve them as a key customer and one of the best large scale operators from our perspective. So, I tell you, we are constantly impressed with the way this team continued to be able to lower their cost and work out creative solutions with us and other parties, and really thankful for the relationship. They are paying their bills in a timely manner as usual and including, we just recently got paid for the minimum volume commitment related to the Haynesville, and we fully expect them to pay the MVC invoice on the Barnett when it's due. It's not due yet. But we're excited about continue to work with them on that and fully expect that to come through as well, just as they paid the Haynesville on time. So, from our view, they continue to reduce their costs and operate efficiently and effectively to maintain liquidity. And nevertheless, though, we are mindful of the credit risk that these continued low prices pose for many producers, including Chesapeake. And so here's how we think about the risk. First of all, we have long-term dedications with strong contractual conveyances of interest in unproduced gas. We like our argument that we hold a current real estate interest in unproduced gas and that our covenant running with the land not subject to the rejection and bankruptcy. We certainly are following current bankruptcy cases like Sabine where the general question is at issue, but people should understand that the ultimate outcome in individual cases will turn on specific facts and circumstances. Regardless, even if the court were to rule we don't have such legal rights, our gathering lines are physically connected to Chesapeake's wellheads and pads and we provide a very critical service, conditioning and connecting Chesapeake's production to points where they can then choose the best markets for the long-haul transportation alternatives. In exchange for the dedication of production, we invested capital to build gathering lines that are uniquely positioned to serve Chesapeake's well. So all these systems were built out specifically for their needs and generally at their direction and to the size and scale that they needed to be able to produce volumes on a projected basis. In most cases, there are not other gathering lines nearby because these are big contiguous areas and these systems were built specifically for their production. And in many cases, our pipelines have been built on populated places such as beneath the city of Fort Worth and it would be very costly for others to replicate our gathering lines. And the rates of return that we generate from these investments and assets are very typical for a midstream provider. Likewise, our gathering lines have been in place for some time and thus the reserves behind them are now partially produced. To continue to produce such gas, Chesapeake and its creditors, if it ever came to that, would want and need to utilize our gathering lines to deliver gas to the markets. So, such gathering lines are very distinguishable from long-haul transportation service because the intra- and interstate pipeline initiate service after the gas has already pooled at marketable points. Producers then have many options to receive cash for their products other than transportation on any one particular interstate pipeline. If it did come to a bankruptcy, a producer can argue that it can reject certain types of contracts and we believe gathering contracts such as ours are not the type of contracts that would be rejected. But even if a gathering contract were allowed to be rejected, a producer and its creditors would continue to need the gathering service to be able to produce gas and create revenue. If a producer rejects the gathering contract in a bankruptcy, the gatherer will no longer be obligated to provide the gathering service. Furthermore, rejection of a contract is all or nothing. Therefore, the analysis of the risk of any producer's bankruptcy is best analyzed contract by contract and really understanding that the particulars of the services being provided and how unique those services are that are being provided. As any prudent midstream service provider would do, we have studied each of our Chesapeake contracts and considered the value of Chesapeake's reserves, our physical connection to their wells and their alternative options for delivering gas to market, and we believe that we understand much better than anyone the real value of our assets if it ever came to a bankruptcy process. But let me be very clear on this matter, we have great confidence in Chesapeake in their assets and more importantly, in their tremendous operating capabilities and management team. Thus far, they have continued to do all the right things in very difficult circumstances and we look forward to helping them be very successful for years and years to come and we have great confidence in their ability to do that. We will continue to find win-win solutions that align our interest and to support them where we can in their asset sales. And as you can see in the table on this slide, Williams' scope and scale of gathering in all of the key natural gas basins is significant. And there are significant non-Chesapeake working interests in basins as well that also give us confidence and the continued cash flows from these assets. So, overall, we'd just tell you we are very proud of our relationship with Chesapeake. We're very impressed with them and – but we also don't have our head in the sand and we are looking very closely to these alternatives. And we feel very strong about our position if it ever were to come to a bankruptcy. Moving on to slide four, this is just an overview here of some of the recent developments and what we see coming soon. First of all, I want to reiterate that the demand side of the natural gas market is really driving our capital investments and you can just see that as you look at some of these projects, the Transco Leidy expansion just came in and that – first part of that started up on December 8. And then we continue to bring segments on in-service through the month of December and now here in January, we are fully completed with all segments in service now for the Leidy Southeast expansion. Great work by the team under some difficult circumstances, but really great performance by the team that manage that project. The Transco Gulf Trace project, this is a project to serve the Cheniere's Sabine Pass LNG facility. Construction is underway with a target in-service of first quarter. 2017. We'd just tell you it's nice to be able to be doing construction in more friendly environments like Louisiana and the teams did a great job of bringing that project board as well. The Transco Gulf Connector project, which is the new long-term contract we just announced for 475 million a day of new expansion service that will also serve Cheniere's Corpus Christi and Freeport LNG facilities, that would be in 2019. And then just a note here quickly on the Marcellus and Utica volumes. The real story going on in the Marcellus and Utica is that we are seeing both growth in available production. So, what do we mean by available production? We mean the production if there were markets available that could actually be flowing. We continue to see that grow behind our systems and we also saw significant price-related shut-ins in the quarter. So this bottleneck, if you will, continues to grow in size with available production growing up behind a very constrained outlet and lower-than-usual regional demand in the areas. But I think it's important to know that we now have over 33% of the gathered volumes in the area and this really leaves us with great exposure once the bottlenecks are cleared. And I think what's really important to note there is that we're not relying on drilling capital for those volumes. All we need is some of those bottlenecks to open up and we'll have volumes flowing without the need for a lot of additional drilling capital. And so, this is very different in most areas of the country where there's a lot of concerns about producers not having the capital to drill. In this area, it's just a matter of the infrastructure being built out in front of it. And then, finally, our Geismar plant. Really proud of the way the team operated the plant and we exceeded our production expectations for the quarter there and are off to a good start here in 1Q of 2015 as well there – or, sorry, 1Q of 2016 as well. Just looking forward some things that are going to drive us looking forward. The Canadian Offgas Processing business, the Horizon project that you've heard us talk about quite a bit. That plant is now the Fort McMurray plant, so that's the plant that actually extracts the liquids out of the offgas is now rolling and it has began extracting liquids, but that will be a process here over the next three weeks or so to get that up to full production. And then, finally, we've got to some remaining work at Redwater to be able to fractionate all those liquids and we expect that to be coming on in March. So a lot of new revenues that will show up there on WPZ as those volumes hit both the pipeline and the Redwater fractionators. And then I'll remind you that the margin side of that business is left at WMB at the Horizon facility upstream. As well our Kodiak tieback, this is a tieback for Devil's Tower platform, and that project is being brought online and has been in the testing phase here for the last couple of weeks and is just about to begin to really add some very significant cash flow here in the first quarter. And then, the Gunflint tieback, which we expect to come on now in the second quarter, which will be our first big tieback to the Gulfstar One project and this is – will also be contributing very substantial cash flow growth with very minimal additional capital investment on our part. We do expect the Gulfstar production to be a little bit higher in the first quarter than we saw in the fourth quarter due to some well workover work that was going on out there, and so we're excited to see some of the benefits of that work that will start to improve things here into the first quarter and beyond. Last year, we announced plans to increase the capacity on our Eastern interstate pipeline from 10.8 Bcf to more than 17 Bcf per day by the end of 2017. And in fact, by 2017, we expect to double the capacity of the Transco system from its 2010 level. So once again, these projects just keep coming and we've got great transparency into our predictable growth and it provides clear evidence that Williams has a truly unique position in terms of our asset footprint, especially in challenging market times. Our backlog of project remains robust and the demand side project just keeps coming at us with amazing pace and consistency and, in particular, along the Transco system. These are fully contracted demand pull projects and we will continue to high-grade these opportunities as we balance constrained funding sources up against continued robust backlog. So, our issue is not a matter of backlog, we have plenty of great investment opportunity; it's really a matter of getting lower – better funding sources and low cost funding sources to supply all these opportunities. So, we're in a envious position of having plenty of opportunity and again just a matter of getting those funded appropriately. Moving on to slide five. So as we said before, much of the attention in the industry is focused on producer shut-ins and commodity prices. We remain focused on serving and capturing the growing demand for natural gas. This focus is especially important in the Northeast where we're working to unlock the tremendous value of the Marcellus and Utica areas by providing market access via the Constitution and Atlantic-Gulf projects. Our strategic remains intact and the underlying fundamentals of our business are strong despite reduced producer activities in the supply areas. And just a few weeks ago, we announced our revised business plan to address the realities of our current market environment while continuing to invest in our business. In addition to significantly lower operating expenses in 2016, the revised 2016 plan includes growth capital funding needs of around $2.1 billion, which is about $1 billion or 32% less than our previous plans. The plan includes $1.3 billion for Transco expansions and other interstate pipeline projects. And the non-interstate pipeline growth that's embedded here totals about $700 million, and this is primarily reflecting additional investments across our gathering and processing systems where capital spending for gathering and processing in 2016 will be limited to really new producer volumes, including mostly wells that are already drilled and completed, but that are waiting connecting infrastructure. So, as I said earlier, we're really not depending on a whole lot of drilling here in 2016; we're really just focused on connecting and getting volumes that are already connected flowing. Moving on to slide six here just to close out. First of all, the fourth quarter results certainly demonstrate the resilience of our fee-based assets. Approximately 93% of PZ's gross margin were from fee-based revenues. The continued growth in Atlantic-Gulf segment continue to be driven by great expansions on our Transco system, as well as our deepwater volumes. And sequential growth in the Marcellus and Utica volumes really was impressive; in fact, total operated volumes in this key region were up 8% as you compare the fourth quarter to the third quarter. While the total volumes in the regions, so not just ours, but looking at the total industry production, actually declined a little less than 1%. So again, total region declined a little less than 1%, but our volumes were actually up by 8%. So really continue to grow our market share in this very important region. Our 2016, WPZ business plan really did address the realities of our current market environment and continues our investments in growing the demand side of our business. Certainly, we continue to high-grade our opportunities and a lot of that capital is going towards really important demand-driven infrastructure projects that serve long-term natural gas needs of local distribution companies, electric power generation, LNG and industrial sources. And so, just to reiterate, this quarter's results and our continued strong backlog of projects are a direct reflection of our strategy to uniquely position Williams to connect the best natural gas supplies to the best markets regardless of significant market swings and cycles. And so, as we move to questions, I'd like to highlight what John mentioned in the opening. The Williams' Board of Directors is unanimously committed to completing the transaction with Energy Transfer for the merger agreement executed on September 28, 2015 and delivering the benefits of the transaction to Williams' stockholders. Beyond that, though, we're only discussing our fourth quarter and year-end results and we ask that you keep your questions focused on our results. We will not take questions related to the pending transaction between Williams and ETE or related matters, and we thank you in advance for your cooperation for that request. And so now, operator, let's please move on to questions.

Thank you. Our first question will come from the line of Christine Cho of Barclays. Please go ahead.

Good morning, everyone. I was wondering if we could start with any insights that you guys have from your talks with the rating agencies and your commitment to the investment grades rating at WPZ, given all the agencies had taken action before your press release detailing reduced CapEx. Any color on how they feel about your CapEx cut, deferrals, your Chesapeake exposure, your asset sales, et cetera? Also, if you could talk about where they would like to see your debt/EBITDA ratio to get to? I mean, are they still okay with that 5 times? Donald R. Chappel - Chief Financial Officer & Senior Vice President: Christine, this is Don. Good morning. Great question. We've been in regular dialogue with S&P and the other agencies. And I really can't speak for the agencies, but I think we've had a very constructive conversation and I think they appreciate the strength of our business, as well as some of the challenges ahead, and we're continuing to work with them and look forward to their decision. And again, we're very much focused on maintaining that investment grade rating, but obviously it's their call.

Okay. I guess in that context, you stated at least $1 billion of asset sales in the first half of 2016 in the original press release. What kind of asset sales are you assuming? And I'm curious to know if you started the process for this and what type of parties you're talking to. Is it utility, midstream guys, financial guys? And should we expect to see any announcements before the deal closes or do we need to see the deal closed first? Donald R. Chappel - Chief Financial Officer & Senior Vice President: I would say that we're preparing for the asset sales. We've not launched anything as of this date, yet we're confident that we can sell the assets and generate the liquidity that we previously outlined kind of in the second quarter. But at the same time, we're not identifying the assets at this point. We don't think it's in our interest to do so. We have quite a few assets that we could in fact monetize, so we're going to keep our options open, but we remain confident in our ability to do so. The merger does not need to close. So we'll execute on that either before or after the merger, depending on the exact merger timing.

Okay. And then, I just wanted to touch upon the bankruptcy comments that you guys had. Alan, you talked about with respect to a rejection, it's all or nothing. And so, I'm curious to know, let's say, the bankruptcy court says that these contracts cannot be rejected, does that mean legally, you guys aren't required to mark to market the rate at all or let go of the MVCs or is that debatable? Alan S. Armstrong - President, Chief Executive Officer & Director: Yeah. No, that is right. It is everything. Those contracts are all-in-one and it's all the terms of the contract, so there isn't ability to cherry pick the terms the contract.

Okay. Great. Thank you so much. Alan S. Armstrong - President, Chief Executive Officer & Director: Thank you.

And your next question will come from the line of Brandon Blossman of Tudor, Pickering, Holt & Company. Please go ahead. Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc.: Good morning, gentlemen. Alan S. Armstrong - President, Chief Executive Officer & Director: Good morning. Donald R. Chappel - Chief Financial Officer & Senior Vice President: Good morning. Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc.: Alan, I'll start off on a bright note. Transco expansion projects, some puts and takes in the backlog, but it looks like, by and large, that looks like on track for a multi-year period. Would you care to contrast Transco's projects with others that are on the project list across the board and the peers in terms of likelihood of going ahead and maybe benefit on an incremental basis to Transco as some of those more heavily producer-backed projects that don't show up in 2016 and 2017? Alan S. Armstrong - President, Chief Executive Officer & Director: Yeah. I think we really don't have those risks in our projects right now. They're fully contracted and they're very secured credit standing behind those contracts. So we really don't have that kind of risk in the projects that we are utilizing with Transco. And so there are a lot of producer-pushed projects out there with very different kind of credit rating standing behind them, but in our case, we feel very strong about the credit and the term standing behind our projects. And there's certainly great push to move ahead with those and a lot of volumes packed up behind those systems ready to flow if and when we get those projects completed. Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc.: And this is looking into a crystal ball, but do you think there's any possibility of some incremental counterparties that are on projects that may not go forward that would eventually accrue to the Transco system? Alan S. Armstrong - President, Chief Executive Officer & Director: Well, perhaps. The only thing I would say to that is there would have to be expansions likely because we have a really clear idea where all those volumes are going to come from that are supporting those projects that we have and they're completely sold out. So it would have to be in the form of expansions beyond what we have today. Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc.: Fair enough. On the gathering and processing CapEx more than cut in half, is there any incremental risk to or possibility to that $700 million getting cut further for 2016? Alan S. Armstrong - President, Chief Executive Officer & Director: Yeah, to a certain degree. For instance, some of that capital is out in the Permian, and in that case, we're going off of the operators' indication on how much capital will be spent out there; operator being the operator of the midstream assets. Most of that's non-operator investment for us and so we're depending on both the producers and the midstream operator forecast of that and that continues to be a moving target in many basins. So I would say in those areas, those more oil-driven basins could be some movement down. I would say in the areas like in the Marcellus or the Utica, we're managing that very closely and trying to optimize the timing of the capital right in line with the opening of new projects coming out of the area. And so there's probably some room to optimize, if you will, and the way some of that capital until the projects are specifically coming on time. So, we could see a little bit of that slip, but a lot of that is already underway and the work is ongoing. Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. Actually, that's helpful color. And then just finally from me on that last point, Marcellus and Utica volumes. You said you saw some shut-ins fourth quarter. Any indication that those are coming back online with winter demand in the first quarter? Alan S. Armstrong - President, Chief Executive Officer & Director: Yeah. We saw a little bit pickup and we certainly saw interest from producers who shut in and were bringing back online. So we actually have seen some people taking advantage. We've seen some these cold weather surges. What you have to really remember about the demand in the Northeast there is it's driven by two things. First of all, its capacity to get out of the region and that's pretty fixed. In other words, those pipelines are completely full getting out of the region and so that doesn't move a whole lot. But what does move in a regional demand based on weather loads in the area where gas is consumed in the region. And so that'll be either driven by cold weather, which we've seen a little bit here in the first quarter, or it'll be driven by very hot weather in the summertime and those are the two things that will drive the variable. Until some of these projects – new projects come online, that will be what drives the volumes in the Northeast. There's plenty of gas ready to meet that demand as it opens up. Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc.: All right. Thank you, Alan. Appreciate it. Alan S. Armstrong - President, Chief Executive Officer & Director: Thanks.

And your next question will come from the line of Ted Durbin of Goldman Sachs. Please go ahead. Theodore Durbin - Goldman Sachs & Co.: Thanks. Appreciate all the color on the Chesapeake contract. I guess I'm just wondering about – it seems like I'm sensing a tone change from you around your willingness to renegotiate the contract. I think you'd already done the one in the Haynesville. Does that now change your view there? And there's an argument out there that such as commodity prices that's pressuring Chesapeake it's also the above-market gathering contracts. I just love your thoughts there. Alan S. Armstrong - President, Chief Executive Officer & Director: Yeah. No, our – I'm sorry if I gave you that impression. We continue to work with Chesapeake in areas to help in negotiating and I would say nothing has changed on that. Our relationship with them is very strong. And the concept of the rate – we keep hearing this above-market rate and I think what people need to remember there is that the rates get set based on the capital that we spent and the returns that are very normal returns in the market. And so, we hear this term above-market rates a lot of the time, but in fact, really the returns that we're generating are very normal. What's occurred that caused the rates to go higher in some areas is where the volumes haven't shown up, but we're still the asked return on our invested capital is very normal for the space. But certainly no indication – or no, I didn't mean to indicate that our tone with Chesapeake has changed. We're simply – and I want to make really clear on this, all we're trying to address is all the concerns that have been expressed by the investors and media, not necessarily our own. We've always kept an eye on the issue as we do with any big customer, but our relationship with Chesapeake and our confidence in them remains very high. Theodore Durbin - Goldman Sachs & Co.: Appreciate that. Maybe just a couple of other ones from me on Chesapeake issue. What is the returns revenue or EBITDA you're earning right now in the Barnett, in the Haynesville and then can you give us a sense of the overall contribution from Chesapeake to your EBITDA? Alan S. Armstrong - President, Chief Executive Officer & Director: We'd take on that first part in terms of our return. Yeah, those returns were set kind of in the mid-teen range on all of those assets and that's what we continue to try to seek out like in our renegotiations in the Haynesville and so forth. We continue to seek out that type of return there. So, that really hasn't changed. The overall contribution of Chesapeake to our EBITDA, I'll have Don maybe take that one. Donald R. Chappel - Chief Financial Officer & Senior Vice President: Yeah. I think it's around 20% plus or minus. It depends on the period, but somewhere in that zipcode. I think 18% was the most recent. Theodore Durbin - Goldman Sachs & Co.: Got it. That's helpful. And then lastly from me on the financing side, you did the Transco bond recently. Is that another tool that you think like you can use more, I hate to call it a stand-alone leverage at Transco, relative to other financing sources that are out there? Donald R. Chappel - Chief Financial Officer & Senior Vice President: Yeah. I think our plan is to keep Transco in the sweet spot for its rate-making purpose. So we are not inclined to put more leverage on Transco. Now, Transco has a lot of growth so, certainly, it'll naturally absorb some additional debt as it continues to build out its projects. But in terms of just adding leverage to Transco, that's not our plan. Theodore Durbin - Goldman Sachs & Co.: Great. That's it from me. Thank you. Donald R. Chappel - Chief Financial Officer & Senior Vice President: Thank you.

Your next question will come from the line of Becca Followill of the U.S. Capital Advisors. Please go ahead.

Good morning. Few questions for you. One, can you quantify the lower OpEx that you're looking for the reduction in terms of dollars for 2016? And then the second one is on the contract that you recently renegotiated with a customer for lower rates in exchange for higher volumes. Are you looking at doing other of the – more of those with customers that are not Chesapeake? Alan S. Armstrong - President, Chief Executive Officer & Director: Becca, I will take the second half of that and I'll let John take the first part of that. As to the contracts in any negotiation, that was a situation where the rate from a legacy cost of service contract was so high that there was no way the reserves in the area would ever be produced and so it was a matter of rate being even in excess of the price of gas. And so, this was a matter of actually getting the gas flowing and assuring ourselves that the gas would continue to flow in exchange for some additional volumes and additional dedication in the area. So, whenever we have opportunities like that that we can bring increment to our gas – or, sorry, our cash flows as we look on a long-term basis, we certainly will try to take advantage. And there are plenty of win-win opportunities out there to increase our cash flows to get gas flowing that's not flowing today. Obviously, we have to be cognizant of the fact because I mentioned earlier that there is only so much gas that's going to get out of the region. And so we want to maximize those revenues on our system because we realized that when Mcf starts flowing in one place, it likely means that it didn't come off a competitor system; it would come off of our own system. So we certainly are cognizant of that issue and the strength getting out of the basin. John R. Dearborn - Senior VP-Natural Gas Liquids & Petchem Services, Williams Partners GP LLC: On the cost question, Becca, we've not put an exact number out there, I guess, for significant cost production that we're committed to. We're already implementing some of those cost reductions. We'll continue to implement additional cost reductions prior to the merger date. And then, we would expect even more significant cost reductions to follow the merger. So the merger date is a variable in that, as well as our joint planning with the ETE team in terms of such cost reduction. So we're not prepared to put a number out there at this point, but we will as we get further along in the year.

Understand. Thank you. And then just to go back to the question on the rate reduction, are there producers – because we get these questions constantly, are the producers actively requesting rate reductions from you guys in order to help them out through this period? Alan S. Armstrong - President, Chief Executive Officer & Director: Yeah. Certainly that's the case, Becca, and I think what our decision is, is what benefit do we get out of that. Again, we have to look at it knowing that there's only a certain amount of gas that's going to get out of the region. And so, we have to determine what the benefit that they're willing to offer in exchange for us lowering the rate up against current prices in a way that provides the cash margin. So, we understand people's cash margins very well. Truly no secret in terms of what that looks like to producers because we get it from so many different people. And it really just boils down to who's got the best offer in terms of exchange for us in terms of us being incented to see their gas flows over somebody else's.

Got you. Thank you. Alan S. Armstrong - President, Chief Executive Officer & Director: Thank you.

And your next question will come from the line of Selman Akyol of Stifel. Please go ahead. Selman Akyol - Stifel, Nicolaus & Co., Inc.: Thank you. Good morning. Alan S. Armstrong - President, Chief Executive Officer & Director: Good morning. Selman Akyol - Stifel, Nicolaus & Co., Inc.: First question I guess for Don. Going back to sort of the credit rating agencies discussion, you said you look forward to a decision. Can you say when you expect to get a decision from them? Donald R. Chappel - Chief Financial Officer & Senior Vice President: I can't give you their timing. I think, again, you'll have to speak to the agencies on that. But again, we've been working collaboratively with them to provide the information that they need to make their rating decisions. Selman Akyol - Stifel, Nicolaus & Co., Inc.: All right. And then just in terms of the related shut-ins, just wondering if you could just put a quantity to that in terms of how much has been shut in on your system? Alan S. Armstrong - President, Chief Executive Officer & Director: Yeah. I'm going to ask Jim Scheel to chime in and give some specifics on that if he could, please. James E. Scheel - Senior VP-Northeast Gathering & Processing: Sure, Selman. As we began the fourth quarter, we had just under 1 Bcf a day shut-in primarily, as we've already talked about, due to lower pricing coming out of the summer and some lack of takeaway capacity. As we begin the year, we probably have right at about 1.1 Bcf a day or perhaps a little bit more shut-in behind the system as we've seen producers continue to complete wells but throttle the production due to price. So it's kind of hard to know until we see a full flow, but we're estimating right at the 1.1 Bcf. And really just to put that in perspective, if that was all flowing, the Northeast would go from about 6 Bcf a day to 7 Bcf a day and our incremental EBITDA would probably increase by about $180 million to $900 million, overall. Selman Akyol - Stifel, Nicolaus & Co., Inc.: All right. Thank you. That does it for me. Alan S. Armstrong - President, Chief Executive Officer & Director: Thank you.

Your next question will come from the line of Sharon Lui of Wells Fargo. Please go ahead.

Hi, good morning. You indicated, I guess, there are several projects slated for in-service during the first half of 2016. Can you just remind us what's the potential cash program for projects like the tie-ins? Alan S. Armstrong - President, Chief Executive Officer & Director: Yeah, I don't think we've provided – I'm looking at John here. John R. Dearborn - Senior VP-Natural Gas Liquids & Petchem Services, Williams Partners GP LLC: Yeah. Alan S. Armstrong - President, Chief Executive Officer & Director: I think, Sharon, we provided specifics on those, but I do think we've said that those are significant. And so you can look to the kind of revenues that we get off of facilities like Devil's Tower and Gulfstar One. And you can think about that from a volumetric standpoint as both the Kodiak tie-in that comes into Devil's Tower and the Gunflint tieback comes on to Gulfstar, but they're certainly very significant. Of course, just like any deepwater wells, they come on gangbusters and decline over time, but they will be fairly significant in terms of cash flow additions when they start up.

Okay. Thank you. And then, I guess just following up on Christine's question about discussions with the rating agencies and the distribution policy, just your latest thoughts on whether a distribution reduction would be an option you would take to defend the investment grade rating? Donald R. Chappel - Chief Financial Officer & Senior Vice President: Sharon, this is Don. We have a number of options. Obviously, we pointed at cost reductions, asset sales, potential partners on some of our projects to reduce capital needs and a variety of other tools. We certainly are mindful of the fact we've got significant cash flow that goes out in the form of distributions, but again we don't have any further guidance on that but that's always an option.

Okay. And maybe this question is for John. In terms of looking at Geismar, I mean ethylene prices still remain pretty depressed. Just wondering what's your outlook for the balance of the year in terms of ethylene and propylene prices. John R. Dearborn - Senior VP-Natural Gas Liquids & Petchem Services, Williams Partners GP LLC: Yeah. Thanks, Sharon, for the question. As we take a look forward, I think it's rather well-known in the industry that there's a rather large turnaround season ahead of us here in the second quarter. And so, on the ethylene side, we think that's going to be up favorable to margins during the second quarter. But then as we look at the ethylene industry overall, in North America this past year, we set an all-time new record for ethylene production. And of course, our ability to export ethylene and ethylene derivatives is somewhat yet limited by bagging and terminalling particularly in the polyethylene case. And so we would expect that the second half of the year on ethylene reverts back to margins more akin to what we're experiencing today. On the propylene side, likewise propylene refinery turnarounds are happening right around now. They get those done in expectation of gasoline production for the summer season basically. And so, we have a rather stable outlook on propylene at the moment through the rest of the year.

Thank you.

And your next question will come from the line of John Edwards of Credit Suisse. Please go ahead. John Edwards - Credit Suisse Securities (USA) LLC (Broker): Yeah. Hi. Just wanted to clarify – going back to Chesapeake and how things work in a bankruptcy scenario. We're just curious with the MVCs then, would those stay or would those go? Or are they separate from some of the contracts? I mean, any color you can provide on that would be helpful. Alan S. Armstrong - President, Chief Executive Officer & Director: Yeah, sure. Just to be clear, those MVCs are part and parcel to the agreement. There's no separate agreement; it's all one agreement. And in a proceeding – any proceeding, the final decision there would be for the creditors to decide if they wanted to accept or reject the contract. And so that's how that would go. And it's all or none in terms of they don't get to again decide anything. So I know there's been a lot of talk about the MVCs being at risk, but that's somewhat – I'm not sure what's driven that assumption by the investor base, but that's not the way it works. And as well, the market-based rate issue, while that might occur during a short-term period, during the proceedings, there might be an ability to take something to market rates if all the other protections that we talked about were to fail. Then it would just be during the interim period prior to the settlement of the proceedings. John Edwards - Credit Suisse Securities (USA) LLC (Broker): Okay. So, I mean as a practical matter, would there be the possibility to renegotiate those and then submit it to the court for approval? Or is it just literally simply it's all or none, take it or leave it? Alan S. Armstrong - President, Chief Executive Officer & Director: Yeah. No, John. I think if there was a reason for us to negotiate, then, yes, that could be part of a settlement. But the decision really is to accept or reject. And really, our point is if the contract is rejected, then we no longer have an obligation to provide service. And because these assets are built uniquely for these reserves, the ability to duplicate these assets would be, from our vantage point anyway, in most of these cases just would not be feasible to build or duplicate all these facilities in these very heavily – particularly places like the Barnett where it's very heavily populated and very expensive to build in, especially when you've got less reserves than you started with to build the assets in the first place. So, anyway, it could come down to a negotiation if there was value to be shared between the parties in a better contract, but our point is just that there isn't any ability to just separate. If somebody accepts the contract, they accept the contract in its whole. And if they reject it, then they take the risk of not being able to get their product moved out of the basin. John Edwards - Credit Suisse Securities (USA) LLC (Broker): Okay. That's helpful. And then just following on the contracts that are up for renewal or renegotiation. So following an earlier question, I think it was Selman that was asking it and the answer was – $180 million to $900 million is the amount that I guess would be – I mean, is that a renegotiation or was that just the amount that's due to shut-in? So just for you to clarify on that. Alan S. Armstrong - President, Chief Executive Officer & Director: Oh, sorry, this is on Jim Scheel's. No, I think I can clean that up. All that is – Jim was saying, if the existing shut-in gas that's already contracted that's sitting behind our systems today, because it doesn't have anywhere to go, it's constrained in terms of bottleneck. It's already connected to our systems and ready to flow, so there's no additional capital required by anybody, but what has to happen is the markets in the downstream long-haul have to open up. And if that were to open up, that's the amount of – that $180 million is the amount of incremental income that we would see, or EBITDA. John Edwards - Credit Suisse Securities (USA) LLC (Broker): All right. That's helpful. And then just last question along those lines. In terms of contracts that are in current discussion or renegotiation, is there any kind of EBITDA-at-risk figure you can provide to us or how should we be thinking about that? Alan S. Armstrong - President, Chief Executive Officer & Director: Yeah. No, we really – so far in our negotiations, we've been able to hold our EBITDA steady under these contracts. And, of course, that's extremely important to us so we haven't backed up in these negotiations. We haven't backed up our EBITDA that we're getting in the current environment. So that hasn't occurred and we wouldn't expect it to. John Edwards - Credit Suisse Securities (USA) LLC (Broker): Okay. That's super helpful. Thank you.

And gentlemen, there are no further questions. At this time, I'd like to hand it back over to Alan Armstrong for closing remarks. Alan S. Armstrong - President, Chief Executive Officer & Director: Okay. Very good. Again, thank you all very much for joining us. Really pleased with the way the business continues to operate in this difficult commodity environment, and very excited about the amount of growth projects that are out in front of us that are consistent with our strategy of taking advantage of seeing these low price natural gas really develop a lot demand. And so, we're very excited about where we sit and we appreciate your interest in the company. Thank you for joining us.

Ladies and gentlemen, this concludes the conference call for today. We thank you for your participation. You may now disconnect your line and have a wonderful day.