威廉斯 (WMB) 2015 Q4 法說會逐字稿

Good day, everyone and welcome to Williams, Williams Partners 2015 year-end earnings conference call. Today's conference is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to Mr. John Porter, Head of Investor Relations. Please go ahead, sir.

Thank you, Angel. Good morning and thank you for your interest to 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 fiver leaders of Williams' operating areas with us, Walter Bennett leads the West; John Dearborn leads NGL and 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 are 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 executed on September 28, 2015, as expeditiously as possible and delivering the benefits of the transactions 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 an Energy Transfer court 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 the 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 team for questions you may have. Thank you all in advance for your cooperation. And with that, I will turn it over to Alan Armstrong.

Thank you, John, and good morning, everyone. Thanks for joining us. This is going to be a fairly brief presentation but 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.

We will look at upcoming drivers that will 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 are 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.

With that, let's look on slide 2 here. We recorded another strong quarter, demonstrating our continued project execution, reliable operating performance and 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 focus 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 over 26% despite very low NGL and Olefins margins.

In fact, I think an impressive stat is across all of our systems on our gas gathering 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 the lower producer activities and a lot of very significant curtailments that continue to exist.

Looking directly at the fourth quarter, the WPZ's 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 $290 million IDR waiver -- this would lift our coverage to 1.39x. 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 will give you the highlights here. First of all, fee-based revenues were up $139 million or 12%. That was driven primarily by Atlantic-Gulf with a lot of fee-based assets that came online during the year and as well as growth of Access. Our Olefins margins were up $43 million to $71 million. 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 and Petchem services for 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%. 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 at a 13-year low. The full-year 2015 NGL margin was only $160 million which represents less than 4% of our consolidated EBITDA during 2015.

I did want to make a note here on the impairment. We took some very large impairments in the fourth quarter. These were largely the 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; that was the value of WPZ in the fourth quarter and then the implied market values of the (technical difficulty) 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, if you'll recall, to the impaired equity method investments and certain of the impaired goodwill relate primary to the acquisition of Access Midstream Partners which we required to book a significant $2.5 billion gain in 2014. This reflected our purchase price allocation to these assets in 2014. 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.

Now just a few thoughts on the results by segment. Atlantic-Gulf had another great quarter, up $122 million, all on fee-based revenues. So very impressive growth continued there in Atlantic-Gulf. For the full year Atlantic-Gulf was actually up $453 million. 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 systems. 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 Atlantic-Gulf had a little bit of higher costs 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. So we continue to work on the Leidy line there where we had a rupture on that line earlier in the year. 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 Low A, we reported fourth-quarter 2015 adjusted EBITDA of $351 million and that was compared to $325 million. A lot of this was driven by 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 and we were up $80 million to $356 million here in 2015 for the full year. Really driven by continued increased service fees at Ohio Valley Midstream, higher overall volumes. 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 very recently and we were really excited about this. It does produce a lower rate for the customer but we have 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.

We are not counting on any new drilling anticipated here for 2016 on that. Even without that new drilling we expect our revenues to be held flat for 2016, despite the lower rate because there are some new volumes that come to us as a result of the transaction and some new production that's being tied in.

A lot of similar story in the Northeast where we continue to tie in production that has already been drilled. We're really not relying -- in the Northeast -- we're really not relying on new drilling rigs out there, really just relying on tying in continued tie-in of production. But the real key force there will be when we start to be some of the take-away projects take hold because that clearly is the constraint out here. It is not a matter of rigs running in the area, it is simply a matter of seeing some of these big bottlenecks open up and then us tying in a lot of this already completed production and seeing that flow for us.

On the NGL and Petchem side, really great operating results for NGL and Petchem from an operating standpoint. But we did have lower unit margins during the period. Really pretty good operating stint, both in Canada and Geismar in terms of volumes. But again, very low unit margins.

For the year -- 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 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. Again, I will remind you those NGL margins are now at a 13-year low. But really proud of the team out there and their continued focus on cost management. Able to continue to generate very significant EBITDA despite low prices.

Moving onto slide 3. This is a really important slide here we wanted to show you. 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. So we really want to 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 the well head to marketable condition and location.

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. I tell you, we are constantly impressed with the way this team continues to be able to lower their costs and work out creative solutions with us and other parties. Really thankful for the relationship.

They are paying their bills in a timely manner as usual, 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. We are excited about continuing to work with them on that and fully expect that to come through as well, just as they paid the Haynesville on time.

From our view they continue to reduce their costs and operate efficiently and effectively to maintain liquidity. Nevertheless, though, we are mindful of the credit risk that these continued low prices pose for many producers, including Chesapeake.

Here is how we think about the risk. We have long-term dedications with strong contractual conveyances of interest in unproduced gas. We like our argument that we hold the current real estate interest in unproduced gas and that our rights, our covenants 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 a 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 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 wells. All these systems were built out specifically for their needs and generally at their direction 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. In many cases our pipelines have been built on populated places, such as beneath the City of Fort Worth and it would be very possible for others to replicate our gathering lines. 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 gathering lines to deliver gas to the markets.

Such gathering lines are very distinguishable from long-haul transportation service because the intra- and interstate pipeline initiate service after the gas is 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. We believe gathering contracts such as ours are not the type of contract that would be reject. However, but even if a gathering contract were allowed to be rejected, a producer and its creditors will continue to need the gathering service to be able to produce gas and create revenue.

If a producer rejects a 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 the 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. We believe that we understand much better than anyone the real value of our assets if it ever came to a bankruptcy process.

Let me be very clear on this matter. We have great confidence in Chesapeake and 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 interests and to support them where we can in their asset sales. As you can see in the table on the slide, Williams' scope and scale of gathering in all of the key natural gas spaces is significant. There are significant non-Chesapeake working interest in basins as well that also give us confidence in the continued cash flows from these assets.

Overall, we'll just tell you we are very proud of our relationship with Chesapeake. We are very impressed with them but we also don't have our head in the sand. 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 4. 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. You can 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 continued to bring segments on in service through the month of December. 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 managed that project.

The Transco Gulf Trace project. This is a project to server the Cheniere Sabine Pass LNG facility. Construction is underway with a target in-service of first-quarter 2017. I would 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 forward as well.

The Transco Gulf Connector project, which is a 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.

Then just a note here quickly 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 was markets available that could actually be flowing. We continue to see that grow behind our systems and we also saw significant price related to (technical difficulty) in the quarter. 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 demands in the areas.

But I think it is important to know that we now have over 33% of the gathered volumes in the area. This really leaves us with great exposure once the bottlenecks are cleared. I think what is really important to note there is that we are not relying on drilling capital for those volumes. All we need is some of those bottlenecks to open up and we will have volumes flowing without the need for a lot of additional drilling capital.

This is very different in most areas of the country where there is 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.

Finally, our Geismar plant. Really proud the way the team operated the plant. We exceeded our production expectations for the quarter there and are off to a good start here in 1Q of 2016 as well.

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. It has begun 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 have some remaining work at Redwater to fractionate all those liquids and we expect that to be coming on in March. A lot of new revenues that will show up there on WPZ as those volumes hit both the pipeline and the Redwater fractionator. I will 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 to our Devil's Tower platform. 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. 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, this 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 little bit higher in the first quarter than we saw in the fourth quarter, due to some well work overwork that was going on out there. So we are 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 pipelines from 10.8 Bcf to more than 17 Bcf per day by the end of 2017. In fact, by 2017 we expect to double the capacity of the Transco system from its 2010 level. Once again, these projects just keep coming and we have got great transparency into our predictable growth. 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 projects remain robust and the demand-side projects keep coming at us with amazing pace and consistency, and in particular, along the Transco system. These are fully contracted demand pool projects and we will continue to high-grade these opportunities as we balance constrained funding sources up against continued robust backlog. Our issue is not a matter of backlog. We have plenty of great investment opportunity; it really is a matter of getting better funding sources and low-cost funding sources to supply all these opportunities. We are in an envious position of having plenty of opportunity, and again, just a matter of getting those funded appropriately.

Moving on to slide 5. As we've 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 are working to unlock the tremendous value of the Marcellus and Utica areas by providing market access via the Constitution and Atlantic Gulf projects.

Our strategy remains intact and the underlying fundamentals of our business are strong despite reduced producer activities in the supply areas. 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. The non-interested pipeline growth that's embedded here totals about $700 million. 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 awaiting connecting infrastructure.

As I said earlier, really not depending on a whole lot of drilling here in 2016. We are really just focused on connecting and getting volumes that are already connected flowing.

Moving on to slide 6, to close out. First of all, the fourth-quarter results certainly demonstrate the resilience of our fee-based asset. Approximately 93% of WPZ's gross margin were from fee-based revenues. The continued growth in the Atlantic-Gulf segment continues to be driven by great expansions on our Transco system, as well as our deepwater volumes.

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 region -- so not just ours but looking at the total industry production -- actually declined a little less than 1%. So again, total region decline 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. 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.

As we move to questions, I would like to highlight what John mentioned in the opening. The Williams Board of Directors is unanimously committed to completing the transaction with Energy Transfer per the merger agreement executed on September 28, 2015 and delivering the benefits of the transaction to Williams' stockholders. Beyond that though, we are only discussing our fourth-quarter and year-end results and we ask that you keep your questions focused on results. We will not take questions related to the pending transaction between Williams and ETE or related matters. We thank you in advance for your cooperation for that request. Now, operator, let's please move on to questions.

(Operator Instructions)

Christine Cho of Barclays.

Good morning, everyone. I was wondering if we could start with any insights that you guys have from your talks with 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 cuts, 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, are they still okay with that 5 times?

Christine, this is Don, good morning. Great question. We've been in regular dialogue with S&P and the other agencies. I really can't speak for the agencies but I think we've had a very constructive conversation. I think they appreciate the strength of our business as well as some of the challenges ahead. We're continuing to work with them and look forward to their decision. Again, we are very much focused on maintaining that investment-grade rating but obviously it is their call.

Okay. 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? 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? Should we expect to see any announcements before the deal closes or do we need to seal the deal close first?

I would say that we are preparing for the asset sales. We have not launched anything as of this date yet we are confident that we can sell the assets and generate the liquidity that we previously outlined in the second quarter. But at the same time we are not identifying the assets at this point. We don't think that's in our interest to do so.

We have quite a few assets that we could in fact monetize so we are going to keep our options open. We remain confident in our ability to do so. The merger does not need to close, so we will execute on that either before or after the merger, depending on the exact merger timing.

Okay. I wanted to touch upon the bankruptcy comments that you guys had. Alan, you talked about, with respect to a rejection, it is all or nothing. So I'm curious to know, let's say the bankruptcy court says that these contracts can not be rejected. Does that mean legally you guys are not required to market the rates at all or let go of the MVCs? Or is that debatable?

That is right. It is everything. Those contracts are all in one and it is all the terms of the contract, so there is not ability to cherry pick the terms of the contract.

Okay, great, thank you so much.

Brandon Blossman of Tudor, Pickering, Holt & Company.

Good morning, gentlemen.

Good morning.

Alan, Let's 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? It appears in terms of likelihood of going ahead and maybe benefit on an incremental basis to Transco some of those more heavily producer-backed projects that don't show up in 2016 and 2017?

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. There are a lot of producer push projects out there with very different kind of credit ratings standing behind them.

But in our case we feel very strong about the credit and the terms standing behind our projects. There's certainly a 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 the projects completed.

This is looking into a crystal ball, but do you think there's any possibility of some incremental counter-parties that are on projects that may not go forward that would eventually accrue to the Transco system?

Perhaps. The only thing I would say to that is it 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 are completely sold out. So it would have to be in the form of expansions beyond what we have today.

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? (multiple speakers)

To a certain degree. For instance, some of that capital is out in the Permian and we are going off of -- in that case -- we're going off of the operator's indication on how much capital will be spent out there. Operator being the operator of the midstream assets. Most of that is non-operated investment for us. So we are depending on both the producers and the midstream operator forecast of that. That continues to be a moving target in many basins.

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 and the Utica, we are 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. There's probably some room to optimize, if you will, and delay some of that capital until the projects are specifically coming on time. We could see a little bit of that slip but a lot of that is already underway and work ongoing.

Okay, actually that's helpful color. And then finally for 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?

Yes, we saw a little bit pick up and we certainly saw interest from producers to bring back online. So we actually have seen some people taking advantage. We've seen some of these cold-weather surges. producers.

What you have to really remember about the demand in the Northeast there is it's driven by two things. First of all, it's capacity to get out of the region. That is pretty fixed. In other words, those pipelines are completely full getting out of the region. So that does not move a whole lot.

But what does move is regional demand, based on weather loads in the area where gas is consumed in the region. So that will either be driven either by cold weather, which we have seen a little bit here in the first quarter, or it will be driven by very hot weather in the summertime. Those are the two things that will drive the variable. Until some of these new projects come online that will be what drives the volumes in the Northeast. There is plenty of gas ready to meet that demand as it opens up.

All right, thank you, Alan, I appreciate it.

Ted Durbin of Goldman Sachs.

Thanks. I appreciate all the color on the Chesapeake contracts. I'm wondering about, it seems like I'm sensing a tone change from you around your willingness to renegotiate the contracts. I think you'd already done the one in Haynesville. Has that now changed as your views there? There is an argument out there that it is not just commodity prices, it's pressure in Chesapeake, it's also the above-market gathering contract. I'd love your thoughts there.

I'm sorry if I gave you that impression. We continue to work with Chesapeake in areas to help and renegotiate and I would say nothing has changed on that. Our relationship with them is very strong.

The concept of the rate -- we keep hearing this above-market rate and I think what people need to remember is that the rates get set based on the capital that we spent and the returns that are very normal returns in the market. You can hear this term above-market rates a lot of the time but in fact, really, the returns that we are generating are very normal. What has occurred to cause the rates to go higher in some areas is where the volumes have not shown up. But we are still -- the asked return on our invested capital is very normal for the space.

Certainly no indication -- I didn't mean to indicate that our tone with Chesapeake has changed. We are 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 investors and media, not necessarily our own. We have 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.

Appreciate that. A couple of other ones for me on the Chesapeake issue. What is the returns, revenue or EBITDA, you're earning right now in the Barnett and the Haynesville? Can you give us a sense of the overall contribution from Chesapeake to your EBITDA?

Let me take on that first part in terms of our return. Those returns were set in the mid-teen range on all of those assets. That is 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 has not changed. The overall contribution of Chesapeake to our EBITDA, I will have Don take that one.

I think it's around 20%, plus or minus. It depends on the period, but somewhere in that zip code. I think 18% was the most recent.

Got it, that's helpful. Last one for me. On the financing side, you did the Transco bond recently. Is that another tool that you feel like you can use more -- and I hate to go with the stand-alone leverage -- at Transco relative to other financing sources that are out there?

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. Transco has a lot of growth so certainly it will naturally absorb some additional debt as it continues to build out its projects. But in terms of just adding leverage to Transco, that is not our plan.

Great, that's it for me, thank you.

Thank you.

Becca Followill of US Capital Advisors.

Good morning. Two questions for you. Ones, 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 more of those with customers that are not Chesapeake?

I will take the second half of that and I'll let Don take the first part of that. As to the contracts and 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. It was a matter of rate being even in excess of the price of gas. This is 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.

Whenever we have opportunities like that, that we can bring increment to 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 is not flowing today. Obviously we have to be cognizant of the fact, as I mentioned earlier, that there is only so much gas that's going to get out of the region.

We want to maximize those revenues on our system because we realized if an Mcf starts flowing in one place, it likely means that if it didn't come off a competitor's system, it would come off of our own system. So we certainly are cognizant of that issue of strength getting out of the basin.

On the cost question, Becca, we have not put an exact number out there. There is a significant cost reduction that we are committed to. We are 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. We are 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 to go back to the question on the rate reduction, are there producers -- because we get these questions constantly -- are there producers actively requesting rate reductions from you guys in order to help them out through this period?

Yes, certainly that is the case, Becca, and I think what our decision is what benefit do we get out of that? Again, we have to look at it knowing that there is only a certain amount of gas that is going to get out of the region. 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 them cash margin.

We understand people's cash margins very well. It is really no secret in terms of what that looks like to producers because we gather from so many different people. It really just boils down to who has got the best to 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.

Selman Akyol of Stifel.

Thank you, good morning. The first question for Don. Going back to the credit rating agency's discussion, you said you look forward to a decision. Can you say when you expect to get a decision from them?

I can't give you their timing. I think, again, you'll have to speak to the agencies on that. Again, we've been working collaboratively with them to provide the information that they need to make their rating decisions.

All right. In terms of the related shut-ins, I was wondering if you could put a quantity to that in terms of how much has been shut in on your system?

Going to ask Jim Scheel to chime in and give some specifics on that, if you could, please.

Sure, Selman. As we began the fourth quarter we had just under a 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 take-away 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.

It is kind of hard to know until we see a full flow but we are estimating right at the 1.1 Bcf. To put that in perspective, if that was all flowing, the Northeast would go from about 6 Bcf a day to 7 and our incremental EBITDA would probably increase by about $180 million to $900 million overall.

All right, thank you, that does it for me.

Sharon Lui of Wells Fargo.

Hi, good morning. You indicated there's several projects slated for in-service during the first half of 2016. Can you remind us what is the potential cash flow ramp for projects like the tie-ins?

I don't think we have provided -- I'm looking at John here -- I don't think, Sharon, we have provided specifics on those. I do think we 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 onto Gulfstar. They are certainly very significant.

Of course, just like any deepwater wells, they come on gang busters and decline over time. But they will be fairly significant in terms of cash flow when they start up.

Okay, thank you. And then following up on Christine's questions about discussions with the rating agencies and the distribution policy, your latest thoughts on whether a distribution reduction would be an option you would take to descend investment-grade rating?

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 is always an option.

Okay. And a question for John. In terms of looking at Geismar, ethylene prices still remain pretty depressed. I'm wondering what your outlook is for the balance of the year in terms of ethylene and propylene prices.

Thanks, Sharon, for the question. As we take a look forward, I think it is rather well known in the industry that there is a rather large turnaround season ahead of us here in the second quarter. So on the ethylene side, we think that is going to be 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. Of course, our ability to export ethylene and ethylene derivatives is somewhat yet limited by bagging and terminaling, particularly in the polyethylene case. So we would expect that the second half of the year on ethylene reverts back to margins more akin to what we are 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. So we would have a rather stable outlook on propylene at the moment through the rest of the year.

Thank you.

John Edwards of Credit Suisse.

Hi. Just wanted to clarify on the -- going back to Chesapeake and how things work in a bankruptcy scenario -- we're just curious, with the MVCs, would those stay or would those go? Or are they separate from some of the contracts? Any color you can provide on that would be helpful.

Yes, sure. Just to be clear, those MVCs are part and parcel to the agreement. There is no separate agreement, it is 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. So that is how that would go. It is all or nothing in terms of, they don't get to, again, decide anything.

I know there has been a lot of talk about the MVCs being at risk but that is somewhat -- I'm not sure what has driven that assumption by the investor base but that is not the way it works. And as well, the market-based rate issue, while that might occur during the short-term period, during the proceedings, there might be an ability to take something at 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.

Okay, so 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?

John, I think if there was a reason for us to negotiate then, yes, that could be part of the settlement. But the decision really is to accept or reject. Really our point is if the contract is rejected then we no longer have an obligation to provide service. Because these assets are built uniquely for these reserves, the ability to duplicate these assets would be -- from our vantage point anyway -- most of these cases would not be feasible to duplicate all these facilities in these very heavily-pop -- particularly places like the Barnett where it's very heavily populated and very expensive to build in, especially when you have 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.

Okay, that's helpful. Following on the contracts that are up for renewal or renegotiation, so following an earlier question. I think it was Selman was asking and the answer was $180 million to $900 million is the amount that would be -- is it a renegotiation or is that just the amount that's due to shut in? Just clarify on that.

Sorry, this is on Jim Scheel's -- I think I can clean that up. All that is, Jim was saying if the existing shut-in gas that's already contracted, it's sitting behind our systems today because it doesn't have anywhere to go, it is constrained in terms of bottleneck. It's already connected to our systems and ready to flow, so there is no additional capital required by anybody. What has to happen is the markets and the downstream long-hauls have to open up. And if that were to open up, that is the amount of -- that $180 million is the amount of incremental income that we would see.

All right, that is helpful. Last question along those lines. In terms of contracts that are in current discussion or renegotiation, is there any EBITDA at risk figure you can provide to us? Or how should we be thinking about that?

So far in our negotiations we have been able to hold our EBITDA steady under these contracts. Of course that is extremely important to us. So we haven't backed up in these negotiations and we haven't backed up in our EBITDA that we are getting in the current environment. That hasn't occurred and we wouldn't expect it to.

Okay, that is super helpful, thank you.

Gentlemen, there are no further questions. At this time, I would like to hand it back over to Alan Armstrong for closing remarks.

Okay, very good. Again, thank you all very much for joining us. Really pleased with the way the business continues to operate in the 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-priced natural gas really develop a lot of demand. So we are 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.