Good day, everyone, and welcome to The Williams Companies' second quarter 2019 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.
Thanks, Patrick. Good morning, thank you for your interest in The Williams Companies. Yesterday afternoon, we released our earnings press release and the presentation that our President and CEO, Alan Armstrong, will speak to momentarily. Joining us today is our Chief Operating Officer, Michael Dunn, our CFO, John Chandler, and our Senior Vice President of Corporate Strategic Development, Chad Zamarin. 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, you should review it. Also included in our presentation materials are non-GAAP measures that we've reconciled to generally accepted accounting principles, these reconciliation schedules appear at the back of today's presentation materials. With that, I'll turn it over to Alan Armstrong.
Great. Well, good morning, everyone. Thanks, John, thanks for everybody joining us. I know it's a busy time right now. As we discuss the second quarter financial performance and the key investor focus areas, we're going to hit, as we have in the past, some of the areas that questions we've been hearing from our investor base. Let's move right into the presentation and take a look at our second quarter 2019 results. Here on slide two, we provided a clear view of our year-over-year financial performance. As you can see, we continue to enjoy very healthy growth in all of our key measures. In general, all the metrics we want to go up went up by double digits, and those we've been working to reduce went down. This growth continues to reflect very little direct commodity exposure, as we've reminded you.
In fact, year to date, our 2019 gross margin is 98% fee-based versus only 2% coming from direct commodity margin. I'll remind you with that is a very predictable set of cash flows, making this the 14th quarter in a row that we have been in line or been at least in line with street consensus and our own guidance. Let's take it from the top with our GAAP cash flow from operations, which increased 20% for the quarter and 16% year to date. Our business continues to demonstrate significant free cash flow, and as you can see, our CFFO exceeded CapEx by over $360 million and $625 million for the quarter and year to date periods. On the next line, we show 12% and 9% growth for Adjusted EBITDA, which is impressive in the face of significant asset sales affecting the period.
I'll have more to say about what drove the Adjusted EBITDA performance here in the next couple of slides. You can see our continued strong growth in adjusted EPS metrics, posting excellent 53% and 33% increases. Our EPS continues to be burdened with substantial non-cash charges, and I encourage you to take a look at slide 12 in the appendix to appreciate the true power of our cash flows underlying these earnings. Our DCF was up about 36% and 21% with strong growth in the per share calculation and the related dividend coverage ratio moving up above 1.8, with the second quarter being boosted by a cash tax item that we disclosed. We're making great progress on bringing leverage down.
Our original guidance was to finish the year at less than 4.75, and we currently sit at 4.43, and we'll discuss our revised leverage guidance in a moment. Finally, crisp execution on our projects continues, keeping our capital spending in line with our expectations. Really nice improvement in our various earnings and cash flow metrics despite the impact of significant asset sales. As we move on here to slide three. For the quarter, Adjusted EBITDA increased just over 12%, or 14% if you adjust for the bigger transactions that affect the year-over-year comparison.
On the left side of the slide in gray, you can see an unfavorable $37 million comparability adjustment, which includes removing the Adjusted EBITDA from the various asset sale transactions completed during the last 12 months, and then taking out the $11 million favorable item reflecting the addition of the incremental 38% UEOM ownership interest. Normalizing for those items, you see Adjusted EBITDA growing about 14%. Moving over to look at the financial performance of the continuing business. Similar to the first quarter of this year, Atlantic-Gulf led the increase with a 23% increase in Adjusted EBITDA, driven by top-line Transco revenue growth from new expansion projects, including Atlantic Sunrise and the Gulf Connector. Next up, looking at the Northeast G&P area, we had a 20% increase in year-over-year Adjusted EBITDA, driven by 17% higher gathering volumes and higher gathering fees associated with expansion projects.
Volume increases were led by the Susquehanna supply hub area, which grew about 23%. We also saw double-digit growth rate in all of our other operated Northeast franchise area except the smaller Laurel Mountain JV that we have with Chevron. Probably one of the more impactful changes that we had there was the Utica volumes up about 15%. As we've mentioned in the past, the Encino transaction out there has really been important to us to see the volumes in the Utica really start to turn around from what previously had been declines to now a very healthy incline. Overall, we continued a very nice start to the year in the Northeast. Finally, we have the West, which is pretty flat to the prior year, where our sharp drop in NGL margins was offset by nice growth in fee-based service revenues.
We're excited to see as well, a new plant at Fort Lupton quickly fill up this quarter in the DJ Basin, as we've now exceeded about 200 million a day of new inlet volumes coming into that plant. As we told you, that just started up right around the end of the first quarter and into the second quarter, and that new train there has already filled up. Great growth going on there in the DJ Basin. Moving on to slide four and looking at the year-over-year results. Pretty similar story year-to-date as you heard for the second quarter. Once again, on the left side of the slide in gray, you can see that the unfavorable $78 million comparability adjustment from the various asset sale transactions, and then a $13 million favorable item reflecting the pickup of an incremental 38% UEOM interest again.
Normalizing for those items, you see Adjusted EBITDA growing about 13% for the first six-month comparison. Year-to-date, we see Atlantic-Gulf up 21% and the Northeast up 20%, driven by the same factors that we just discussed on the previous slide, namely Transco revenue growth and strong broad-based volume growth across the Northeast. The West is down about 3% on this comparison, reflecting much lower NGL margins and the effect of severe winter weather this year on volumes in 1Q of 2019. All in all, very happy with our second quarter performance, which tracked well with our overall business plan from last fall, despite the declines we've seen in natural gas and NGL pricing, and we are very well positioned to continue this growth here in the last half of the year. Next, let's revisit a few of the key investor focus areas.
Before I dig into the items on this slide, I just want to remind you of a few things. First of all, we just recently announced a reorganization and some other cost reduction initiatives that we have going on as a company right now. As you may have noted from our recent 8-K, after more than 30 years of service, Jim Shea will be leaving the company in December of this year, and we're taking the opportunity to further reduce our operating areas to two. One focused primarily on our FERC-regulated gas pipeline business led by Scott Hallam, and the other focused on our non-regulated business being led by Walt Bennett, who leads our West Gathering Business today. I'll have more to say in recognition of the fine work Jim has done for Williams on the third quarter call.
For now, I'll just say the reorganization to two operating areas represents another step toward becoming further simplified and centralized as we seek to be the very best operator in the natural gas infrastructure business. These moves are basically taking advantage of the scale that we have in these very similar businesses and continuing to drive common processes and common systems across our operations. We will continue to provide supplemental disclosures to assist in the modeling of our non-regulated business, so don't worry about losing any of the transparency that we provide today. Our supplemental disclosures will provide at least as much visibility as you have today and will continue to highlight the Northeast volume and EBITDA growth that continues to occur.
Beyond the consolidation of the operating areas, we have also initiated a voluntary separation program and are looking at other cost reduction opportunities, given the $5-plus billion of asset sales that we've had over the last three years. Really narrowing our focus down to the natural gas infrastructure space is allowing us to take full advantage of the scale. I can tell you the entire management team is very focused on us having the very best operating margin ratio in the business. We continue to push hard on that as a team, and we really believe given the scale that we have, we ought to be the very best in the industry on this measure. These efforts are taking us closer and closer to that point.
Let's look now at the first item we'll be discussing, which is our financial guidance and progress on deleveraging. First off, we are reaffirming our current financial guidance for 2019 and now guiding to a further improvement in our year-end 2019 leverage target. You can find the various elements of our 2019 financial guidance in the appendix of this presentation. Additionally, we are also affirming our longer-term EBITDA growth rate of 5%-7% per year. Turning now to our leverage. We achieved a debt to Adjusted EBITDA ratio of 4.43 at the end of the second quarter, and we now expect our year-end 2019 debt to Adjusted EBITDA to be less than 4.5. As you'll recall, our original guidance was to be less than 4.75 for the same period.
The effects of our transactions, along with our recently lowered capital expenditure forecast, has allowed us to significantly improve our 2019 debt to Adjusted EBITDA expectations for 2019. There is no change to our long-term target of 4.2 that we plan to hit by the end of 2021. We continue to evaluate transactions that could potentially allow us to reach the 4.2 times at a faster rate. As an affirmation that we are making the right moves on the leverage front, we recently saw some favorable rating agency actions where S&P improved its outlook to a triple B flat stable rating. Fitch put us on rating watch positive. Shifting now to discuss the expected growth in our Northeast G&P business. We'd like to first emphasize that we still believe in the strong natural gas demand growth fundamentals that underpin our strategy.
We have seen continued delays in the start-up of nearly all of the LNG terminals that were planned to come online in the first half of 2019. That just means we're going to see an even stronger pull on natural gas in the back half of this year. It really is easy to see that the natural gas demand growth outlook remains very strong, driven by LNG export growth, continued power generation, and major industrial investments that continue to come online trying to take advantage of low-cost U.S. natural gas and U.S. low-cost NGL prices.
Confidence in low-cost U.S. natural gas reserves will continue to drive strong natural gas demand growth over the long term, and as a result, we believe that there will have to be a call on natural gas-focused supply areas, given the continuous growth in natural gas demand and the stronger than ever capital discipline being demonstrated by the producer community. However, nearer term, we continue to see commodity price headwinds for our producer customers in the area, and we believe that producers are responding appropriately to the current market conditions. Continuing to plan around or hope for higher prices would only exacerbate the lengthened supply. We are also very focused on closely matching our capital programs with these latest forecasts.
Our Northeast growth capital for 2020 probably ends up being about half of what it was in 2019 due to us pulling back capital as well as the synergies that we're realizing from the UEOM transaction. While also making significant near-term reductions in 2019, as we continue to respond to the producer's disciplined approach. With that being said, let's take a closer look at our current expectations for the Northeast G&P business through 2020, built on the backs of our most recent producer customer feedback. Starting with 2019, you can see that we are currently forecasting gathering volume growth of about 13%, which should result in Adjusted EBITDA growth of 19%, for a total of about $1.3 billion.
Year to date, we've generated about 16% gathering volume growth. We do expect that overall annual growth to moderate in the fourth quarter, mostly just since because our fourth quarter comparison will be up against volumes that grew rapidly after Atlantic Sunrise came on in the fourth quarter of 2018. Looking forward, our 2020 very latest forecast shows about a 5.5% gathering volume growth over 2019, generating about 11% Adjusted EBITDA growth to get to about $1.45 billion. I might just note that we had always expected a slowing in the growth rate for 2020 versus 2019 with respect to our prior 10%-15% gathering volume CAGR. It seems that folks maybe missed the front-end impact that was present in the CAGR and instead thought we were assuming more of an annual or equal annual growth rate.
That was never the case, and the unequal growth rates across the 2018 to 2021 timeframe were indicated given the strong growth that we have been expecting and we are seeing in 2019. Beyond 2020, we do see an opportunity for stronger growth rate to resume in 2021, but that, of course, will be dependent on a better balance in the natural gas market. I'd also just mention that as we think about the Northeast pricing environment, it's important to remember that even in today's pricing environment, producer netbacks are still better than they were in the 2015 and 2016 timeframe when production was constrained and commodity prices were more a function of the basis differential than the Henry Hub prices.
Since then, incremental gas takeaway capacity has come online, improving realized prices in the region, and the producers have become significantly more efficient and disciplined with their capital during this timeframe. Overall, we are encouraged to see the level of EBITDA growth our Northeast G&P business can continue to generate even in the weak natural gas price environment we're currently experiencing, and we remain very focused on cost reduction and capital discipline as we await long-term fundamentals to balance. Let's move on to discuss our Transco growth projects. First, let me give a quick update on the Transco rate case, although not a lot of new information to pass along here as our confidential settlement process continues. We've now had five conferences, and we continue to work the issues like ROE with our customers.
Last quarter, we stated that the settlement negotiations were likely to continue for many months. They have done that, and resolution could extend into next year. We are cautiously optimistic that a settlement can ultimately be reached without the need for litigation, and the settlement would include the $1.2 billion emissions reduction tracker that will allow Transco to significantly reduce emissions from our existing compression fleet along the eastern seaboard. As always, I'll remind that we don't have any upside from the rate case reflected in our financial guidance. Let's touch on the status of Transco's major growth projects, starting with the Northeast Supply Enhancement project. This quarter, we quickly reapplied for the 401 water quality certification in New York and New Jersey, and promptly received notice of complete application from New York. New Jersey has indicated that our application is administratively complete.
These are very important milestones in the refiling of this and taking on some of the technical issues that were raised by both of those states. Obtaining both of these 401 certifications is essential to begin construction this fall in order to meet the project and service dates. The enhancement of the existing infrastructure is critical in connecting much needed natural gas supplies to folks in New York, and while improving the airshed and system reliability in New York and New Jersey. In May, our customer, National Grid, had to announce that they will not be able to process new gas service requests in its service area in Brooklyn, Queens, and Long Island. This means they will not provide any additional connections for firm service until there is certainty that the NESI project can move ahead.
Local, commercial, residential, and political support for the project is strong, as the need for gas on both an economic and an environmental improvement basis is clear and compelling. We fully expect a positive decision will come in time for us to maintain our end service date just ahead of the 2021 winter peaks. Next, I want to touch on a couple of key FERC milestones that were met recently for a couple of our Transco projects. We recently applied for a FERC certificate for our Leidy South project. As a reminder, Leidy South is a proposed 580 million cubic feet per day expansion of Williams' existing Pennsylvania infrastructure that will further connect Appalachian gas with growing demand centers along the Atlantic seaboard in time for the 2021, 2022 heating season.
Our FERC certificate for Southeastern Trail project is pending approval, and the Southeastern Trail project is a 295 million cubic feet per day expansion of the Transco pipeline system designed to provide additional pipeline capacity to serve growing markets in the Mid-Atlantic and Southeastern states by November of 2020. Additionally, we received permission in June to place a portion of the Rivervale South to Market project into early service. This project is Transco expansion of 190 million cubic feet per day to service additional customers in New Jersey and New York City. Facilities required to provide 140 million cubic feet per day have already been completed, and the remaining facilities are ahead of schedule, targeting a September in-service date, two months ahead of schedule. Our most recently announced Transco project, Regional Energy Access, concluded its open season and our team is finalizing negotiations with its customer base.
All in all, continued tremendous amount of activity on Transco, both in terms of completing existing projects that we've got underway, like Hillabee Phase 2, which is also ahead of schedule, and a long list of projects that we have in the permitting phase. Lots of great effort going on by our engineering construction teams, but with both the permitting and the construction, and continued great performance on the capital execution efforts here. Lastly, let's move on to the Deepwater Gulf of Mexico, where we're seeing a pickup in activity and significant new discoveries in and around our assets that has us positioned for significant free cash flow growth for years to come. Beginning in the third quarter of 2019, you'll start seeing contributions from our Norphlet Deepwater Gathering System investment.
Norphlet delivers gas into Williams Transco's system located on one of our Gulf of Mexico platforms, and from there, the gas will be transported to our recently expanded Mobile Bay processing facility. First gas production on the system began in late June, and we acquired the $200 million Norphlet Pipeline in early July. The Norphlet Deepwater Gas Gathering System is extremely well-positioned for even more growth than the existing Appomattox system, with approximately 50% of the pipeline's contractual capacity remaining available for future produced tie-ins of existing discoveries in that area today. Our Discovery system is also seeing new volumes from the Hadrian North and Buckskin tiebacks, which achieved first productions on our systems during the second quarter. The Hadrian North and Buckskin liquids-rich production flows to our Discovery system via the Keathley Canyon connector, and ultimately to our Larose processing plant and our Paradis fractionator.
These tieback opportunities are high-return projects and are an example of many more to come in the Deepwater. Looking forward, we are very active right now discussing multiple tieback prospects around Devils Tower, our Deepwater platform where production could begin as early as 2021. On the near Blind Faith, we continue to be excited about Chevron and Total's Ballymore dedication to us, where first production could be seen as early as 2023. In the very active Western Gulf, facility planning for Shell's Whale prospect is on a fast track, and we could see FID for our system expansion here in the fourth quarter of this year.
We continue to see opportunities for significant incremental cash flow in the 2022-2023 timeframe from our Deepwater operations. We are really excited about the very substantial growth that we're seeing, both on acreage that's already dedicated to us, and as well new acreage that we're very confident that we're going to be able to pick up given our expansive network. With that, we will transition to our Q&A session. Thank you again for your time today. We're pleased to share with you our very strong second quarter performance and continued focus on de-leveraging and the progress we've made on our many growth opportunities. With that, operator, I'll turn it over to you.
Perfect. If you'd like to ask a question, please signal by pressing star one on your telephone keypad. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Once again, press star one to ask a question. We'll take our first question from Spiro Dounis with Credit Suisse. Please go ahead.
Hey, good morning, everyone. First question, just around the financial guidance and being able to reiterate the 5%-7% long-term growth. I think we were a little surprised there, just given the slight haircut on the Northeast volume outlook. Alan, totally understand your point on the expected slowdown embedded in the 10%-15% CAGR. Just still seems like something is in there, maybe offsetting some of that. Maybe just walk us through some of the drivers on how you're able to maintain the 5%-7%, and if you're able to maybe even pull forward some demand-driven projects as an offset.
Thanks, Spiro. I would just say, obviously, when we laid that out, that 5%-7%, we were counting on a certain level of returns from our projects. I would just say that some of those things have gone better than that. In other words, we've had quite a bit of improvement. If you think about it, since we laid out that 5%-7%, we've had quite a bit of improvements in areas like the Utica with Encino, and the UEOM transaction that gives us some synergies and ability to keep our costs even more under control there in the Northeast. We set that 5%-7% some time ago, and just like in any big company like Williams, there's been some things that go down a little bit, but there's also things that go up.
We're continuing to put pressure on our costs, as we talked about. I would say we are being agile and responsive to those changes, and we're also picking up advantages like Bluestem. You might have noticed our Conway NGL and frac business was up pretty significantly this quarter, which was on the backs of us building up for some of those Bluestem volumes. We're continuing to take advantage where the opportunities exist, and those tend to offset things where things change a little bit to the negative. Just the benefit of having a big portfolio.
Got it. That's helpful. Just on the faster than expected deleveraging, obviously the asset monetizations played a big part in that. It sounds like you expect that to continue. I guess as you just look at some of the announcements made by some of your E&P customers in the Northeast recently, just curious if you've seen any shift or reduction in appetite there from potential buyers and JV partners. Are they still looking like they want to invest more?
Yeah, I would just say, that has not slowed down a bit. I think the distinction out there that's becoming more clear to us is that the interest rates are so low out there, and so much available to that money up against these very certain cash flows and very predictable cash flows that we have. As long as you have the predictability of those cash flows, that kind of low-cost money is going to be available, and we continue to be impressed by that in terms of various transactions that we're involved in. It's clear to us that that's people just arbing out these very low interest rates against these very predictable cash flows, and I think we're going to continue to see that with lower interest rates.
Got it. That's also helpful. Last quick housekeeping one. We've had a few inbounds on this lately, but just with respect to Chesapeake and Haynesville contracts you've got there, could you just remind us again when those contracts roll and what your appetite is at all to renegotiate anything here?
Spiro, this is Micheal Dunn. Those contracts are dedicated to us, and I don't have the exact timeframe on when, your language about when they might roll, but all that acreage is dedicated to us and we are continuing to work with Chesapeake there. They've been active in there, and we've been bringing on additional production from them. We've also been very successful in capturing other business in the Haynesville, besides Chesapeake, that is coming into our systems there. Volume in the Haynesville is up for us and we're pretty pleased with what we're seeing there right now.
I would just say there in the Haynesville, when we renegotiated that several years ago there, we did extend the life of that contract, and I believe that contract extends out into the 2030s. That was one of the benefits we got out of that transaction when we renegotiated that a couple of years ago. The Eagle Ford is a similar long-term timeframe, there's not any re-ups coming in either of those areas.
Got it. Appreciate all that color. Thanks, guys.
We'll take our next question from Gabriel Moreen with Mizuho. Please go ahead.
Hey, good morning, everyone. I was wondering if you can talk a little bit overall about the ability to flex CapEx higher or lower in response to the natural gas pricing environment. You gave a preliminary outlook for CapEx guidance for 2020. To the extent gas prices go maybe sub $2, is there even more ability to flex that downward? Maybe you can speak to that, or is that kind of 50% reduction sort of where it goes regardless of the environment?
Gabe, good question. I would just say the capital that we have out there today is backed by rate increases or MVCs. If there was a further pullback that occurred, today, I would just say that a lot of that capital that we're talking about really wouldn't move all that much unless there was some kind of renegotiation, because most of it's underpinned by obligations on the other side. I really wouldn't expect it to move too much. I would tell you that the outside of the Northeast, obviously, these demand pool projects, which will be the bulk of our capital in 2020, of course, are just further improved by low gas prices, so we don't really see any change there.
We've still got capital going into the DJ Basin, and the Wamsutter area, and those are mostly getting driven off of oil prices. Don't see much change going on there. Of course, the deep water is such a long-term play. It doesn't really get driven by short-term shifts in commodity prices.
Thanks, Alan. I guess as a related follow-up, I was wondering if you can comment a little bit on the headlines that have crossed on the Blue Racer system over the last couple of weeks. I think related to that, there was a fairly substantial Marcellus gathering transaction that happened about a month ago, and I think Williams had ownership in a couple of those systems. Was there an opportunity to maybe piggyback on that transaction, and can you maybe speak to that as well?
Yeah. I'll just answer the simple part of that first, and then I'll turn it over to our General Counsel to answer the more complex question you started with. On the Pennant Midstream investment that we have with Three Rivers Midstream up there, that is a really small interest and there's not really any opportunity there for us. There's really nothing on that front. We do think there's some good consolidation opportunity up there that we think will likely come our way even with that asset. We think there's some good opportunity around the liquids that come off of that plant that do come over to UEOM. Again, I'd just say, we were impressed with another high multiple being paid in the space out there, and I think we continue to see that.
We continue to see our businesses marked well below those kind of multiples that are being paid. We were impressed by it, and we obviously were paying close attention to that. I'm going to have Lane Wilson, our General Counsel, respond to you on the Blue Racer question.
Hey, Gabe. I assume you're talking about the news lately regarding the litigation in Delaware, and kind of think about all we want to say there is that we are cooperating and supportive of the efforts to IPO the Blue Racer business. That said, there are a number of rights around the structure and scope of certain filings that we have related to that IPO effort, and the litigation is really just an effort on our part to protect those rights. Beyond that, I think we just want to wait for the court to rule. We anticipate it'll probably occur sometime in August.
Thanks, Wayne. I'll let that rest. Last one for me is, it seems like a little bit of pushing out to the right on timing on some of the Rockies processing expansions. I think, Alan, you mentioned oil being a function of oil prices. Seems like the processing picture's pretty dynamic out there in the DJ. Can you maybe speak to that and the timing going on there?
Yeah. We're really pretty encouraged by the continued steady growth rate that we're working with on producers out there. We did push out our Keenesburg two plant and our Milton train. We did push those out in our schedule. We are really impressed with the growth that we're seeing out there and the fact that we've already filled up, just here in one quarter, we filled up that one new train we placed in service first part of April. We're really pleased with the way that's going. Actually, I would tell you, one of the risks I didn't like about that basin was the peaky nature of the production growth, that flattening out a little bit with the same amount of reserves. We actually picked up a very large dedication in East Greeley from Extraction since we did that deal earlier.
We continue to build dedicated acreage behind the system, and a little slower growth rate with less capital going in wouldn't hurt my feelings at all in terms of the long-term return on capital that we would see out of that area. Overall, despite all the regulatory concerns, which is not to be dismissed, we actually think the basin's doing very well, and the producers are doing a nice job of following through on the permits, and a lot of which were already grandfathered in the area. I would be contrarian perhaps, but I have a pretty positive perspective about the DJ and the actions going on out there right now.
Great. Thanks, Alan.
If you find that your question has been answered, you may remove yourself from the queue by pressing star two. We'll take our next question from Chris Sighinolfi with Jefferies. Please go ahead.
Hey, good morning, Alan. Thanks for all the updates.
Good morning.
It's really helpful. I did want to follow up on a couple areas. The leverage guidance change last night. I noticed obviously it came down a touch without any subsequent change in the EBITDA or CapEx ranges. I'm just wondering, is that sort of a feeling that you're going to be at the higher end of the EBITDA range or the lower end of the CapEx range or both? Or is it some other cash flow item, like a working capital change or something of the like that we should pay attention to?
Well, great question, a very fair one. I would just say that on the CapEx side, we're probably coming in towards the lower end of that range on the CapEx guidance, that's a piece of it. As well, I would just say we've got more confidence around the way the quarter has gone. One thing that's pretty interesting, if you think about it, we always show our CapEx, that's a gross CapEx number. When we, for instance, the JV we have now with CPPIB, that's our gross CapEx that's embedded there, as that is our gross. Our capital burden obviously is less with CPPIB picking up some of that capital load from us, that actually helps that as well a little bit.
Okay. No, I think maybe I had not quite paid attention to that latter part, appreciate that. Also pivoting a little bit, want to follow up on Spiro's earlier question about your gathering contracts, perhaps frame it more broadly than he did. As you had referenced, you renegotiated some agreements in select areas and with select counterparties in the 2015 and 2016 timeframe. I think in often instances, you received an upfront cash payment and then subsequently lowered the rate to spur activity and preserve, I think, in total, your NPV. I'm just wondering, given the pullback now and the intense focus on producer activities, if you're having similar conversations with anybody anywhere.
No. Not that I'm aware of, Chris. I don't see anything out there right now. There's certainly a lot of desire, as we always have. There's always desires with our producers to further streamline and align our interests out there. They're certainly on that. I don't know of anything where there'd be an upfront payment kind of situation out there. Really, the only thing as we had that really was the Barnett that Total is now the operator on. We're constantly working with Total in alignment and especially in a low gas price environment. We work closely with them on reducing costs between the two of us out there. Very healthy relationship and a very positive one with Total there in the Barnett.
Okay, great. A final question from me, Alan, is we've obviously paid attention to what you guys are seeking in Texas with the EXCO situation. It feels like the RRC's going to make a decision here next week. I'm just curious if I can get a little bit more color from you on maybe the background there and if that's a situation that might be replicated elsewhere if you have a producer that's flaring on a system that already exists, and how that maybe dovetails into some of your ESG efforts.
Yeah. Great question. It truly is one of those things where it just doesn't, frankly, from our perspective, make a lot of sense. It is very complex background. That was originally, that acreage was dedicated under the Chesapeake agreement. Chesapeake sold their mineral interest to EXCO but didn't move the dedication. The cost of those assets remains in that cost of service calculation under the Chesapeake agreement. Just because they sold it didn't mean it changed the nature of that. The gas was physically connected to our system and had previously flowed. This isn't a situation where we're saying, "Hey, our pipeline's sitting out there, and we could connect it to you." It literally is connected.
Given that this is sour gas, and therefore puts off a lot of H2S or has a lot of H2S component in it, and would put off SO2 when burnt. We think there's a lot of good reasons to be making sure that that's going on. I will say that our team has worked in a very positive manner out there with EXCO, despite the conflict. We've been working with them in a positive way to try to contain the gas and be buying the gas from them. We are working on continuing to improve that relationship and be constructive as we always would. I do think we're going to wind up at a constructive place on that.
It is a complex issue because that actually is under an old Chesapeake agreement, and the cost of those facilities that we installed were under that cost of service agreement. That's about as far as I'm going to take that one, but I would say our move out there was just one of protecting our rights, and the contract for the Chesapeake acreage out there prohibits flaring. You shouldn't assume that this gets extended to further actions in the area, because it specifically prohibits that. Don't really see any follow-on from this.
Okay. Well, thanks again for the time and congrats on the steady execution. It's certainly not been lost on us.
Thank you very much. Appreciate it.
We'll take our next question from Jeremy Tonet with J.P. Morgan. Please go ahead.
Hi, good morning. Wanted to pick up on the balance sheet situation here. It seems like you guys have been quite busy, as been noted on the call with asset sales and strategic JVs really accelerating the de-leveraging process here. I was just wondering if you could expand a bit more on how you see leverage kind of progressing here. If you're bringing in 2020 CapEx coming down, as you noted, wanting to see the potential to continue to maybe divest assets in the West that are not contiguous and can't have value chain integration. Possibly the ability of moving forward, hitting that 4.2 leverage target, if things come together there.
Jeremy, good question. I would just say we're always looking at that. I would say another driver for that, which is more value than just de-leveraging, because I think we're on a very clear path in our mind to get there anyway. We feel pretty confident just on the natural path we're on to getting there. However, given the value spread between what the private space is willing to pay for these very certain cash flows versus what the public equity is valuing that, it just continues to provide an opportunity for us to gain value for our shareholders. I would say even if it wasn't for that, for the de-leveraging benefit that comes from that, we would be looking at those kind of opportunities anyway, just because we don't feel like our gathering and processing assets are valued appropriately.
In fact, I would question where we are today. I would question if our pipeline assets are being valued appropriately. We'll continue to take advantage of that spread. Of course, it does have the benefit of continuing to de-lever pretty rapidly as well.
That's helpful. Thanks. Just turning over to Regional Energy here. Appreciate that you're at a kind of commercially sensitive point in the development, just wondering if you could expand a bit more as far as kind of shipper interest and how you see that progressing.
Yeah.
Yeah. Micheal Dunn here. We had a lot of interest in that project. We are working through the scenarios of delivery points and supply points, and are optimistic that we'll ultimately have a very nice project there. There were several paths that were available there to shippers submitting under the open season, and we're just evaluating the submissions that we received and configuring various scenarios to ultimately make a great project for Transco and our customers there.
That's helpful. That's it for me. Thanks.
Thanks, Jeremy.
We'll take our next question from Shneur Gershuny with UBS. Please go ahead.
Hi. Good morning, guys. Maybe to start off on the Northeast guidance, just to come back to it a little bit here. There's sort of a delta in the CAGR between the volumetric growth rate versus EBITDA growth rate. My understanding is that it's a function of timing with respect to the contracts and the contract structure and so forth. In a hypothetical scenario where 2021, let's say, was 0% growth, would there still be some EBITDA carryover that would roll into 2021, in a scenario of zero growth?
Shneur, I don't know that we have evaluated that. I would tell you, we run a pretty precise model that gets us to that. I don't know for certain. I don't want to speak out of school on that. We have confidence in the model we have. I don't want to get out on a limb without the benefit of the detailed model behind me on that answer. I'm not saying it doesn't. I'm just telling you I'm not certain as we sit here.
Okay, that makes sense. Secondly, on the Northeast, if I read your tone correctly, it sort of sounds like you're trying to shift towards a harvesting cash flows from the Northeast and kind of adjusting time kind of CapEx approach. Is that in fact correct? As you think about projects you're noodling, where do you expect to spend the majority of your CapEx on a go-forward basis?
I would say, I think we've always been on adjust-in-time mode there in the Northeast for many years now, and making sure that we're staying aligned with the customers and producers up there that are coming to us wanting additional capacity. We'll still continue to do that. We're finishing up some pretty significant projects this year with the TXP-2 installation at Oak Grove that's now online, as well as our Checkmark pipeline, our Monarch Pipeline, which is an NGL pipeline that goes to our Harrison fractionation complex. We've got a lot of capital that we are deploying this year that we'll be rapidly filling. I guess in future years, I would say we're going to be very responsive to the customers there. We are still talking to them about expansions.
We're not just in harvest mode, but we are still continuing in each one of those franchises to talk to the customers about expansions and things they want to do up there. Encino's been very active on the Cardinal and Flint systems and evaluating their new acreage there that they bought from Chesapeake, and we're excited to work with them on that as well. I think we've got a lot of opportunities there to continue to look for expansions. It's certainly going to be dependent upon price with many of those producers.
Up there very keen on watching the price and what they can achieve there for their net backs.
Great. Maybe one final question, I'm really not sure how much you can say about the pending rate case, but as I sort of think about the landscape out there, it's increasingly getting extremely difficult to build greenfield projects. I'm sure you're aware of everything that's going on and so forth. I'm sort of thinking about an outcome where your customers or interveners are pushing for, let's say, a lower ROE authorization. Wouldn't that disincentivize you to build any further? They can't force you to actually expand Transco. Does that factor into the process of the negotiations about coming to a win-win scenario? It's difficult to build and at the same time, you have a system in place. If they enforce a low return on you, then you have no incentive to actually build.
Just wondering if you can sort of comment about that and whether that's something that comes into the discussion process.
I would just say it's a pretty complex issue. Maybe to bring it home to something pretty simple, the emissions reduction program that we have, which is a $1.2 billion program that benefits everybody and including directly our customers in those areas because we reduce emissions in the areas which allows for further expansions of businesses in the area by reducing emissions, and so for their power plants, for instance. There's a lot of positives that come out of emissions reduction project, and obviously a lot of those customers have been making those similar investments in methane leak prevention and so forth. They've spent a lot of money on their systems under their PUCs to reduce greenhouse gas emissions, and I think everybody is in favor of us doing that.
Getting a low return up against our portfolio of other opportunities doesn't really get us very far on that because we need to have the economic incentive to make those investments. To your point, we have these other items and really where that nexus comes together is up against project expansions. If we have high return opportunities for expansion projects because things are so difficult to build, that is going to get the money up against a lower ROE. Said another way, because somebody can't force us to build at those lower ROEs, we will have negotiated rates that generally get us to a higher rate. That of course then just puts pressure on the capital allocation process on opportunities for those kind of investments and as well, things like cybersecurity and everything else that we need to invest on.
For the health of this industry, we've got to make sure that those ROEs are in line with the investment opportunities across the space. If we don't, the FERC really is veering away from its responsibility to make sure that those returns are attractive enough to incent investment in the space. That's certainly a key issue as we go into those negotiations.
I think it's clear to say as part of the discussion and negotiation, the difficulty with building new pipe risk that pipeline companies bear, build these new assets certainly goes into the reality that this isn't a super low return environment. We need an appropriate return to go along with the risk of some of the timing delays and other things that go into constructing pipelines today. That's certainly part of the argument.
All right. Perfect. Guys, really appreciate it. Thank you very much.
We'll take our next question from Christine Cho with Barclays. Please go ahead.
Morning.
Morning, Christine.
The lower Northeast guidance isn't that surprising, just given recent commentary out of Northeast producers. Can you talk about how you came to the lowering of your guidance? Some of your producers have publicly talked down numbers, but others less so. Can you just help me reconcile how much of it is your own estimates on what you think producers are going to do, and how much of it is what producers told you that they're going to do?
There are certainly small pieces in there, but I would tell you the vast majority of our information is directly in line with detailed work that we do with our producers. They can't surprise us and want production brought online. We have to plan well in advance with them. While there may be little pieces here and there, it's pretty detailed, and we keep that model up to date with the very latest work that we're doing with producers. Mike, I don't know if you'd add anything to that?
Yeah, Christine, we do detailed analysis with each one of our producers. Some of the producers we meet with weekly to plan our projects and plan activities associated with their either well connects that are coming online or their future expansion opportunities. We have a very robust planning process with nearly every one of our producers up there, and that's what we desire with every one of them and we strive for. We do a lot of work with them in order to make sure that we're not getting out in front of them, but we're also meeting their needs. We worked really hard to scale back a lot of our capital investment immediately with the producers when they told us that they were scaling back some of their turn-in lines for their wells.
We were able to very quickly take a lot of capital out of our Northeast investments that we had planned for. Therefore, that's why we're edging toward the lower end of our growth capital guidance, just because of that activity downturn.
Okay. Helpful. Thank you. Given the changes at EQT and their customer, can you just remind us how your contracts with them work, if there are volume commitments or acreage dedications? If you could confirm the tenor left on that contract and whether or not you expect the changes at that customer to be an opportunity or more neutral?
Well, I would just say the contracts are long-term in nature, and they do come with an MVC, and it's a MVC that ramps up over time. We do have that. I'm not going to get into a whole lot more detail beyond that. I would also just add that a lot of the acreage that the new management group is very focused on is in the West Virginia area, where we have a lot of the existing infrastructure in the area. We're encouraged to be working with them. We've got a lot to offer them, but our existing contracts are MVC-based, and they are long-term.
Okay. Last one from me. Can you just walk us through when do you need all your approvals by for the Northeast Supply Enhancement project in order to hit the winter 2020-2021 in-service date?
Yeah, Christine, thanks for the question. We are working through the 401 certifications with both New York and New Jersey right now. We would hope to have those in hand this summer in order for us to be able to achieve the 404 permit from the Corps of Engineers. We intend to start construction this fall on the project. Primarily, the compressor station construction would occur first. That is really the long lead pacing item here, and with all the environmental windows that are associated with the offshore construction, we slotted that construction in for next summer. The real pacing item here is the compressor station that would be on the critical path because it's a longer duration construction.
We would expect to have in hand the 401 certifications this summer, and then shortly after that, the 404 permit would have a very small public comment period that would open up, and we would have that 404 permit so that we could go to the FERC and then ask for a notice to proceed, and then begin construction in the fall.
Great. Thank you so much for the color.
We'll take our next question from Danilo Juvane with BMO Capital. Please go ahead. Caller, your line is open.
Good morning. Thank you for squeezing me in. I wanted to start with the Northeast, thank you for providing guidance for the segment for next year. To the extent that you have provided this information, beyond 2020, how should we think about volumetric sensitivity as it relates to the EBITDA? For instance, for a % change in the growth rate, what does that translate to from an EBITDA standpoint going forward?
Yeah, I think obviously it's dependent on what the growth is. It's not perfectly linear, obviously. I would just say with the ability to continue to have a higher EBITDA growth rate than volume growth rate will continue just because our cost structure is more and more efficient. Our unit cost continues to lower over time as volumes go up. That relationship, there's not really any reason that that would stop for us. Some of the pretty significant increase that we've got here in the front end is based on some higher rates associated with the capital we've placed, you wouldn't see a continuing increase to that rate. The basic fundamental piece of lower unit cost with higher volume will continue to benefit that relationship.
Thanks for that, Alan. Second one for me, the long-term 5%-7% target growth rate. To the extent that there may be ongoing issues with NESE, can we still sort of hit that growth rate going forward? How should we think about that?
I'm sorry, Danilo, I didn't quite understand which growth rate. You're talking about 5%-7%?
Correct. The 5%-7%. If there are any additional delays with NESE, for instance, from a timing standpoint, is that something that still kind of is intact going forward?
I would just say a lot of other variables to consider other than just NESI. NESI is a very attractive project for us, there are a number of other things. I would certainly say that we are confident right now in NESI occurring, and that is included as we think about that 5%-7% growth rate out there right now. That is included in that. As we've mentioned, we have a lot of other things that are variables in that as well, and we tend to find a way to offset if we did have a negative surprise on that of some kind. I would just tell you, we as a team are very confident right now in that going ahead, just because we know how critical it is to that area that it does go ahead.
Thank you. Those are my questions.
Thanks.
We'll take our next question from Jean Ann Salisbury with Bernstein. Please go ahead.
Good morning. Over the past year, you gained gathering market share in the Northeast, driven by Atlantic Sunrise. In your 2020 5.5% growth number, do you know if you're kind of expecting to gain market share, or is that the same rate that you would expect the basin to grow, and you're just in line with that?
Yeah, we're not counting on any new customers out there in that number. That's just off our existing base of customers, if that's your question. Obviously, different producers have different motives and different activities that go on out there, it's not perfectly ratable across the space, obviously. I don't really know what the broad base estimation is. I can tell you that's just from our existing customer base that we have out there in terms of our growth rate.
Okay. That makes sense. Just as a quick follow-up, I think in 2020, there are some Gulf of Mexico MVC roll-offs related to Gunflint. Can you just give any range that you have of the EBITDA decline that might be associated with that?
Yeah. We don't have any MVCs out there.
Okay, thanks.
We do have some deferred revenue step-downs that occur, and we had some fixed payments that actually declined. It's all that in the tune of $75 million, roughly in that range of step-down between 2019 and 2020.
Okay, perfect.
Yeah.
Thank you so much. That's all for me.
Thank you.
We'll take our next question from Becca Followill with U.S. Capital Advisors. Please go ahead.
Good morning, guys. Following up on the Northeast Gathering. If I'm looking at page 10 with your growth projects, is it fair to say that when you reference the MVCs that you have on this gathering, that the Susquehanna Gathering for 2019 and 2020, and then the Bradford Gathering, those are going forward regardless that those have MVCs associated with them?
Well, just to be clear, most of the Susquehanna gathering doesn't have MVCs. It has higher gathering rates. The gathering rates applied across all of the volumes, there's not MVCs to be clear in Susquehanna. Bradford, on the other hand, is a cost-of-service agreement, so that is dependent on the capital being placed, and once the capital is requested, then that goes into the rate of return calculation. To say it another way, it's not volume sensitive once the capital's been put in place.
With the pullback in producer activity, these projects are still going forward?
Yes.
Okay, no change at this point. On the Gulf of Mexico, can you quantify on the Norphlet pipeline that you acquired and then the incremental discovery volumes from Hadrian North and Buckskin tiebacks, what kind of EBITDA those contribute?
I don't believe we've provided that detail. I think we have said that the Norphlet was a 5 to 6 multiple project for us, so you can do the math on that $200 million. That is just against the base field out there. There are some other nice discoveries in the area that we are very well-positioned to serve. That isn't going to come on in the next couple of years. That'll be beyond that period.
Finally, you talked about Whale possibly being FID'd at the end of this year. On the page 10, it shows that as a 2022 plus. If it's FID'd this year, is it still 2022 plus?
Yeah, just to be clear, my comment was our infrastructure, so our system, I'm not speaking for the producers on that, but given our work with the producer, we would be looking to FID our work and our expansion associated. The dedication's already there. We would be taking action on our part based on the dedication. Just to be clear on that. Yeah, we're not going to get ahead of Shell and Chevron on their timing on the project out there. I would tell you, it is on a very fast track within both shops.
It would still be 2022 plus as per page 10?
Yes.
EBITDA goes on.
Yes.
Okay.
That page is intended to represent when we believe the project really will come into full service.
Yeah.
Okay. Gotcha.
We've got a lot of work to do out there, and so our FID is necessary to make sure that we're not on the critical path out there.
Gotcha. Thank you.
That concludes today's question and answer session. Mr. Armstrong, at this time, I will turn the conference back to you for your closing remarks.
Okay, great. Thank you for all the good questions. We're excited to continue to report on the overall breadth of our business and the growth going on really in all areas across Transco, across Northeast, the deep water, and I'm excited to see the DJ start contributing as well. We appreciate all the interest and the continued support for the company. Thank you.
The conference has now ended. Thank you for your participation. You may now disconnect.