© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good day, everyone and welcome to The Williams Company’s 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, and thank you for your interest in The Williams Company. 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, Micheal 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 and you should review it. Also included in our presentation materials are non-GAAP measures that we reconciled to generally accepted accounting principles. And these reconciliation schedules appear at the back of today’s presentation materials.
And so with that, I’ll turn it over to Alan Armstrong.
Great. Well, good morning, everyone. Thanks, John and thanks for everybody joining us. I know it’s a busy time right now. As we discussed 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 we’ve questioned, we’ve been hearing from our investor base. So let’s move right into the presentation and take a look at our second quarter of 2019 results.
Here on Slide 2, 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, we went up by double digits and those we’ve been working to reduce, it went down. So this growth continues to reflect very little direct commodity exposure, so we remind you. And in fact, year to date our 2019 gross margin is 98% fee-based versus only 2% coming from direct commodity margin. And I’ll remind you with that is a very predictable set of cash flows making this be 14th quarter in a row that we have been in line or been at least in line with Street consensus and our own guidance.
So 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. And I’ll have more to say about what drove the adjusted EBITDA performance here in the next couple of slides.
And you can see our continued strong growth and 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 and 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 1.8x 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 4.75x and we currently sit at 4.43x, and we’ll discuss our revised leverage guidance in a moment. And finally, crisp execution on our projects continues keeping our capital spending in line with our expectations. So 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 3, 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. The normalizing for those items you see adjusted EBITDA growing about 14%.
Now moving over to look at the financial performance at 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%. But we also saw double digit growth rates in all of our other operated Northeast franchise 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%.
And so as we 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 declined to now a very healthy incline. So overall we continued a very nice start to the year in the Northeast. And finally, we have the West, which is pretty flat to the prior year where a sharp drop in NGL margins was offset by nice growth and fee-based service revenues.
And we’re excited to see as well a new plant at Fort Lupton quickly fill up this quarter in the DJ Basin. As we – we’ve now exceeded about 200 million a day of new inlet volumes coming into that plant. So 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. So great growth going on there in the DJ Basin.
Moving on to Slide 4 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 grey, you can see the unfavorable of $78 million comparability adjustment from the various asset sell transactions and then a $13 million favorable item reflecting the pickup of an incremental 38% UEOM interest again. And so 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 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 tracks well with our overall business plan from last fall despite the decline 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. And before I dig into the items on this slide, I just want to remind you a few things. First of all, we just recently announced the reorganization and some other cost reduction initiatives that we have going on at the company right now. As you may have noted from our recent 8-K after more than 30 years of service, Jim Scheel 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 focus 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 have more to say in recognition of the fine work Jim has done for Williams on the third quarter call. But 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. So 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.
But we will continue to provide supplemental disclosures to assist in the modeling of our non-regulated business, but 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, 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. And really narrowing our focus down to the natural gas infrastructure space is allowing us to take full advantage of the scale. And I can tell you the entire management team is very focused on us being – having the very best operating margin ratio in the business. And so 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. And these efforts are taking us closer and closer to that point.
So 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% to 7% per year.
Turning now to our leverage. We achieved the debt to adjusted EBITDA ratio of 4.43x at the end of the second quarter and we announced that our year end 2019 debt to adjusted EBITDA to be less than 4.5x, as you’ll recall, our original guidance was to be less than 4.75x for the same period. The effects of our transactions along with our recently lower 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 4.2x that we plan to hit by the end of 2021 and we continue to evaluate transactions that could potentially allow us to reach the 4.2x 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 BBB flat stable rating and 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’ve seen continued delays in the startup of nearly all of the LNG terminals that were planned to come online in the first half of 2019, but that just means we’re going to see an even stronger pool 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 of U.S. natural gas and U.S. low cost NGL prices.
Components 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.
Our near 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 length and supply. And 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 this reduce to us going 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 producers disciplined approach.
So 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 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, but 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 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% to 15% gathering volumes CAGR. It seems that folks maybe missed the frontend impact that was present in the CAGR and instead thought we were assuming more of an annual or equal annual growth rates.
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 rates resume in 2021, but that of course, will be dependent on it better balance in the natural gas market.
I’d also just mentioned that as we think about the Northeast pricing environment, it is important to remember that even if today’s pricing environment reduce our net backs are still better than they were in the 2015 and 2016 timeframe, when production was constraining 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 our capital during this timeframe.
So 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.
Now let’s move onto our – 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 competence will set them up and our 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 in the 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.
And as always, I’ll remind you that we don’t have any upside from the rate case reflected in our financial guidance. So 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 and New Jersey has indicated that our application is administratively complete. These are very important milestones in the re-filing 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 date. The enhancement of the existing infrastructure is critical and 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 and it’s service carry in Brooklyn, Queens, and Long Island. This means they will not provide any additional connections from service until there certainty that the NESE project can move ahead. Local, commercial, residential and political support for the project is strong as the need for gas on in both in economic and 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 2020/2021 winter peaks.
Next, I want to touch on a couple of key 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.
Also our FERC certificate per Southeastern Trail project is pending approval and the Southeastern Trail project is a 295 million cubic feet 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.
And 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. The facility is required to provide 140 million cubic feet per day have already been completed and the remaining facilities are ahead of schedule targeting the September in-service date, two months ahead of schedule.
Also, our most recently announced Transco project Regional Energy Access concluded its open season and our team is finalizing negotiations with this customer base. So 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, so lots of great effort going on by our engineering and construction teams with both the permitting and the construction and continued great performance on the capital execution efforts here.
And lastly, let’s move onto 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 position 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 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 contractual capacity remaining available for future produced times of existing discoveries in that area today.
So our discovery system is also seeing new volumes from the Hadrian North and Buckskin tiebacks, which achieved first productions on our systems in 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 in our Paradis fractionator. These tieback opportunities are high return projects and our 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 and on the near Blind Faith, we continue to be excited about Chevron and Total value more dedication to us where first production could be seen as early as 2023, and in the very active Western Golf facility planning for Shell’s well prospect is on a fast track and we could see FID for our system expansion here in the fourth quarter of this year.
So we continue to see opportunities for significant incremental cash flow in the 2020 to 2023 timeframe from our deepwater operations. And we are really excited about the very substantial growth that we’re seeing both on acreage that’s already dedicated to it and as well new acres that we’re very confident that we’re going to be able to pick up given our expenses network.
So 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 deleveraging and the progress we’ve made on our many growth opportunities. And so with that operator, I’ll turn it over to you.
Perfect. [Operator Instructions] We’ll take our first question from Spiro Dounis with Credit Suisse. Please go ahead.
Good morning, everyone. First question just around the financial guidance and being able to reiterate the 5% to 7% long term growth, I think, we were a little surprised there, just given the slight haircut on the Northeast volume outlook. And Alan, I totally understand your point on the expected slowdown and embedded in the 10% to 15% CAGR. But just still seems like something is in there, maybe offsetting some of that. So maybe just walk us through some of the drivers and how you’re able to maintain the 5% to 7%, and if you’re able to maybe even pull forward some demand driven projects as an offset.
Yes. Thanks, Spiro. Well, I would just say, obviously when we laid that out, we were that 5% to 7% – we were counting on a certain level of returns from our projects. And I would just say that some of those things have gone better than that. So in other words, we’ve had quite a bit of improvement if you think about it, since we laid out that 5% to 7%. We’ve had quite a bit of improvements in areas like the Utica within see now and the UEOM transaction. That gives us some synergies and ability to keep our costs even more under control there in the Northeast. So we’ve actually, we said that 5% to 7% some time ago. And just like in any big company like Williams, there’s been some things they go down a little bit, but there’s also things that go up and of course, and we’re continuing to put pressure on our costs as we talked about.
So I would say, we are being agile and responsive to those changes. And we’re also picking up advantages like Bluestem, like – you might’ve 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. And so 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. And then just on the faster than expected deleveraging, obviously the asset monetization played a big part in that. And it sounds like you expect that to continue. But I guess you’d just look at somebody announcements made by some of your E&P customers in the Northeast recently. Just curious if you’ve seen any shifts or reduction in appetite there from potential buyers and JV partners? Are they still looking like they want to invest more?
Yes, I would just say, well, that has not slowed down a bit. I think that – the distinction out there, this becoming more clear to us is that, there 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. And so as long as, you have that 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. But it’s clear to us that that’s people just are being 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 got 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?
As far as – this is Micheal Dunn, those contracts are dedicated to us and we – I don’t have the exact time frame on when you’re a language about when they might roll, but all that acreage is dedicated to us and we are continuing to work with Chesapeake there. And they’ve been active in there and we’ve been bringing on additional production from them, but we’ve also been very successful in capturing other business in the Haynesville besides Chesapeake that is coming into our systems there. So volume in the Haynesville is up for us. And we’re pretty pleased with what we’re seeing there right now.
Yes. I would just say, they’re 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, so that was one of the benefits we got out of that transaction when we renegotiated that a couple of years ago. So the Eagle Ford is as similar long term timeframe, so there’s not any re-ups coming in either of those areas.
Got it. I appreciate all that color. Thanks guys.
We’ll take our next question from Gabe Moreen with Mizuho. Please go ahead.
Good morning, everyone. I was wondering if you can talk a little bit overall about the ability to reflex 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 reflex that downward? Maybe you can speak to that? Or is that kind of 50% reduction sort of where it goes regardless of the environment?
Yes, Gabe, good question. Yes, I would just say, there are the capital that we have out there today is backed by rate increases or MVCs. And so 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 its underpinned by obligations on the other side. So 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 – just further improved by low gas prices. So we don’t really see any change there. And then we still got capital going into DJ Basin, and the Wamsutter area and those who mostly getting driven off of oil prices. So we don’t see much change going on there. And of course, the deepwater is such a long term play. It didn’t really get driven by the shifts – short term shifts in commodity prices.
Thanks Alan. And I guess as a related follow-up. I was wondering, if you can comment a little bit on the headlines that are crossed on the Blue Racer system over the last couple of weeks. And 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 community speak to that as well?
Yes. No. The answer is – 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 pinot investment that we have with Rivers – midstream up there, that is a really small interest and there is not really any opportunity there for us. So there’s really nothing on that front. We do think there’s some good consolidation opportunity up there that we think will like some 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. But 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. And so we continue to see our businesses mark well below that, those kind of multiples that are being paid. So we were impressed by it and we are obviously we’re paying close attention to that.
I’m going to have Lane Wilson, our General Council responds to you on the Blue Racer question.
Hey, Gabe, as you’re talking about the news lately regarding the litigation in Delaware. I will think about it. 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 efforts. And the litigation is really just effort on our part to protect those rights. Beyond that, I think we just want to wait for the court to rule probably it occurs on time in August.
Thanks, Lane. I’ll let that rest. And last one for me is, it seems like a little bit of pushing out to the right on timing on some of the Rocky’s processing expansions. I think Alan, you mentioned oil – being a function of oil prices, it seems like the processing picture is pretty dynamic out there in the DJ. Can you maybe speak to that and the timing going on there?
Yes, we’re really pretty encouraged by the continued steady growth rate that we’re working with on producers out there. We did push out Keansburg II plant and our Milton Train. We did push those out in our schedule. But 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. And so we were 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. And so that flattening out a little bit with the same amount of reserves back. We actually picked up a very large dedication in East Greeley from extractions since we did that deal earlier.
And so 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. So overall, despite all the regulatory concerns, which is not to be dismissed, we actually think the basins 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. So I would be contrarian perhaps, but I am pretty – have a pretty positive perspective about the DJ and the actions going on out there right now.
Great. Thanks, Alan.
[Operator Instructions] We’ll take our next question from Chris Sighinolfi with Jefferies. Please go ahead.
Good morning, Alan. Thanks for all the announcements, really helpful. I did want to follow-up on a couple of areas. The leverage guidance change last night, I noticed obviously it came down at touch without any subsequent change in the EBITDA or CapEx ranges. So 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 like that we should pay attention to it?
Well, yes, great question and 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 CapEx guidance. So that’s a piece of it. And as well, I would just say we’ve got more confidence around the way that quarter has gone. And one thing is pretty interesting if you think about it, we always show our CapEx and that’s like gross CapEx number. And so when we – for instance, the JV we have now with CPP, that’s our gross CapEx that’s embedded there as that is our gross. But our capital burden obviously, is less with CPP picking up some of that capital load from us. And so that actually helps that as well a little bit.
Okay. No, I think maybe I had a not quite paid attention to that latter part, so I appreciate that. I’m also pivoting a little bit wanting to follow up on Spiro’s earlier question, right? You’re 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, 2016 timeframe, I think an often instances you received an upfront cash payment and then subsequently lowered the rate as per 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’m not – 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 interest out there. And so they’re certainly on that, but I don’t know of anything where there’d be an upfront payment kind of situation out there. And really the only thing, as we had that really was the Barnett that Total now the operator on. And so we’re constantly working with Total and 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 very positive one with Total there in the Barnett.
Okay, great. And then a final question for 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 is going to make a decision here next week and I’m just curious if I could 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 may be dovetails into some of your ESG efforts.
Yes, great question. When it truly is one of those things where it just doesn’t, frankly, from our perspective make a lot of sense. But 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. And so though the cost of that – those assets remains in that cost of service calculation under the Chesapeake agreement. And so just because they sold it didn’t mean it, it changed the nature of that. The gas was physically connected to our system and had previously flowed. And so this isn’t a situation where we’re saying, hey, our pipelines sitting out there and we could connect it to you. It literally is connected. And so given that this is our gas and therefore puts off a lot of H2S – has a lot of H2S component in it. And we would put off as SO2. We think, there is lot of good reasons to be making sure 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. And so we are working on continuing to improve that relationship and be constructive as we always would. So I do think, we’re going to wind up at a constructive place on that, but it is a complex issue because that actually was – is under an old Chesapeake agreement and the cost of those facilities that we installed were under that cost of service agreements.
So but as far as I’m going to take that one but we are – 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. So you shouldn’t assume that this gets extended to further actions in the area, because it’s specifically prohibits that. So don’t really see any follow on from this.
Okay. Well, thanks again for the time and congrats on a steady execution. It’s certainly not been lost on us.
Thank you very much. I appreciate it.
We’ll take our next question from Jeremy Tonet with JPMorgan. Please go ahead.
Hi, good morning. Wanted to pick up on the balance sheet situation here, it seems like you guys been quite busy has been noted on the call with asset sales and strategic JVs, really accelerating that deleveraging process here. I was just wondering, if you could expand a bit more on how you see leverage kind of progressing here. I mean, if you’re bringing in 2020 CapEx coming down, as you noted, I want to see, the potential to continue to maybe divest assets in the West that don’t have – that are not contiguous and can’t have value chain integration? And possibly the ability of moving forward, hitting that 4.2 leverage target, if things come together there.
Yes. Jeremy, good question. I would just say, we’re always looking at that and I would say another driver for that, which is more value than just deleveraging because I think we’re on a very clear path in our mind to get there anyway. And so 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 cash flows, 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. And so I would say, even if it wasn’t for that for the deleveraging benefit that comes from that, we would be looking at those kinds 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. So we’ll continue to take advantage of that spread. And of course, it does have the benefits of continuing to do collaborate pretty rapidly as well.
That’s helpful. Thanks. And just turning over to Regional Energy here, I appreciate that you’re at a kind of commercially sensitive point in the development, but just wondering if you could expand a bit more as far as kind of a shipper interest and how you see that progressing?
Yes. 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 we’re optimistic that will 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 receive and configuring, various scenarios to ultimately make a great project for a Transco and our customers there.
That’s helpful. That’s it for me. Thanks.
We’ll take our next question from Shneur Gershuni with UBS. Please go ahead.
Hi. Good morning, guys. Maybe just 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 volume metric growth rate versus EBITDA growth rate. And 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 zero percent growth, would there still be some EBITDA carryover that would roll into 2021 in a scenario of zero growth?
I don’t know that we have evaluated that. I would tell you we run a pretty precise model that gets us to that. But I don’t know per certain, so I don’t want to speak out of school on that. We have competence in model we have, but I don’t want to get out on a limb without the benefit of the detailed model behind 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. And then secondly on the Northeast, if I read your tone correctly, it sort of sounds like you’re trying to shift towards a harvest cash flows from the Northeast and kind of adjusting time kind of CapEx approach. Is that in fact correct? And as you sort of think about projects you’re noodling, where do you expect to spend the majority of your CapEx kind of on a go forward basis?
Yes. I would say, I think we’ve always been on adjusting 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. And 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 their checkmark pipeline. Our Monarch pipeline, which is an NGL pipeline that goes to our Harrison fractionation complex.
So we’ve got a lot of capital that, we are deploying this year that will be rapidly filling. So 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. And so we’re not just in harvest mode, but we are still continuing in each one of those franchises. We talk to the customers about expansions and things they want to do up there, and seeing who has been very active on the cardinal influence systems and evaluating. There are new acres that they bought from Chesapeake and we’re excited to work with them on that as well. So I think we’ve got a lot of opportunities there to continue to look for expansions and it’s certainly going to be depended upon price with many of those producers, they’re very keen on watching the price and what they can achieve there with their net backs.
Great. And maybe one final question. And I’m really not sure how much you can say about the pending rate case. 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. And so I’m sort of thinking about it, an outcome where your customers are interveners are pushing for – let’s say, a lower ROE authorization. Wouldn’t that disincentivize you to build any further? I mean they can’t force you to actually expand Transco. And does that factor into the process of the negotiations about coming to a win-win scenario? Because it’s difficult to build and at the same time you have a system in place. But if they enforce a little 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.
Yes. I would just say it’s pretty complex issue, but 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, businesses in the area by reducing emissions, and so for their power plants, for instance. So 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.
So they 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 economic incentive to make those investments. And so – and to your point, we have these other items and really where that nexus comes together is up against project expansions. And so 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.
And so said another way, because somebody can’t force us to build those lower ROEs, we will have negotiated rates that generally get us to a higher rate. But that of course then just puts pressure on the capital allocation process on opportunities for those kinds of investments. And as well, things like cybersecurity and everything else that we need to invest on. So we’ve got to make sure 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. And if we don’t, we’re not really – the FERC really is veering away from its responsibility to make sure that those returns are attractive enough to incentive investment in the space. And so that’s certainly a key issue as we go into those negotiations.
I think it’s clear to say as part of that discussion and negotiation, the difficulty with building new pipe, risks that companies, pipeline companies bear, they’ll build these new assets, certainly goes into the reality that this isn’t a super low return environment. I mean, we need an appropriate return to go along with the risk, some of the timing delays and other things that go into constructing pipelines today. So, that’s certainly part of the argument.
Perfect, guys. Really appreciate the color. Thank you very much.
We’ll take our next question from Christine Cho with Barclays. Please go ahead.
Good morning. So the lower Northeast guidance isn’t that surprising, just given recent commentary out of Northeast producers? But 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 though. 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’s 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. And so while there maybe 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. So Mike, I don’t know if you’d add anything to that.
Yes. 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 either they’re well-connects that are coming online or their future expansion opportunities. So 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.
So 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. And 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. And so 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. And then given the changes at EQT and their customer, can you just remind us how your contracts with them work, if they’re volume commitments or acreage dedication. And if you could confirm the tenure left on that contract and whether or not you expect the changes that customer to be an opportunity or a more neutral?
Well, I would just say, the contracts are long-term in nature and they do come with an MBC, and it’s a MBC that ramps up over time. So we do have that. I’m not going to get into a whole lot more detailed beyond that. And I would also just add that a lot of the acreage that they are – 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. So we’re encouraged to be working with them. We’ve got a lot to offer them, but our existing contracts are MBC based and they are long-term.
Okay. And then last one for 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?
Yes, Christine, thanks for the question. We are working through the 401 with both New York and New Jersey right now. We would hope to have those in hand this summer and order for us to be able to then achieve the 404 permit from the Corps of Engineers. And then we intend to start construction this fall on the project. Primarily the compressor station construction would occur first. That is the 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.
So the real pacing item here is the compressor station that would be on the critical path because it’s a longer duration construction. So we would expect to have in hand a 401 certifications the summer and then certainly 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 began 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 and thank you for providing guidance for the second financial year. To the extent that you have provided this information, beyond 2020, how should we think about volumetric sensitivity as it relates to EBITDA? For instance, for a percent change in the growth rate, what does that translate to from an EBITDA standpoint going forward?
Yes. I think obviously it’s dependent on what the growth is. It’s not perfectly linear obviously. But I would just say, the ability to continue two 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, and so as volumes go up. So 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 placed. And so, you wouldn’t see a continuing increase to that rate, but the basic fundamental piece of lower unit costs with higher volume will continue to benefit that relationship.
Thanks for that, Alan. Second one for me. The long-term 5% to 7% target growth rate, to the extent that there may be ongoing issues with NESE I mean, how – and 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. Are you talking about 5% to 7%?
Correct, the 5% to 7%. If there are any additional delays with NESE for instance, from a timing standpoint, is that something that’s still kind of is intact going forward?
Yes. We’ve got – I would just say, a lot of other variables to consider other than just NESE. NESE is a very attractive project for us. But there are a number of other things, but I would certainly say that we are confident right now and that’s the occurring and that is included as we think about that 5% to 7% growth rate out there right now that is included in that. But as we 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 if some time. But 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, can you – 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?
Yes, we’re not counting on any new customers out there in that number. So that 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. So it’s not perfectly rate-able across the space obviously. So I don’t really know what the broad base estimation is, but 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. And then just as a quick follow-up, I think in 2020 there are some Gulf of Mexico MBC rollout related to Gunflint. Can you just give any range that you have of the EBITDA decline that might be associated with that?
We don’t have any MBCs out there.
We do have some deferred revenue step downs that occur and we had some fixed payments that actually declined. So call that in the tune of $75 million roughly in that range of step down between 2019 and 2020.
Okay, perfect. 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. So if I’m looking at Page 10 with your growth projects, is it fair to say that when you referenced the MBC 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 MBCs associated with them?
Well, just to be clear, the most of the Susquehanna Gathering doesn’t have MBCs, it has higher gathering rates. So the gathering rates are applied across all of the volumes, not across – there’s not in MBCs 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 calculations. So I’d say another way, it’s not volume sensitive once the capital has been put in place.
So would the payback reduce your activity, these projects are still going forward?
Yes.
Okay. No change at this point. And then 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 tie backs. 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 five to six multiple project for us. So you can do the math on that $200 million. And that is just against the base field out there. So there are some other nice discoveries in the area that we are very well served – very well positioned to serve, but that isn’t going to come on for the next – in the next couple of years. That’ll be beyond that period.
And then finally you talked about we’ll possibly be in FID at the end of this year. But on the Page 10, it shows that as a 2022 plus. So is that – is it’s fid this years, is it still 2022 plus.
Yes. Just to be clear, my comment was our infrastructure. So our system, 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. And so we would be taking action on our part based on the dedication, so just to be clear on that. So we’re not going to get ahead of Shell and Chevron on their timing on the project out there. But I would tell you it is on a very fast track within both shops.
So it would still be 2022 plus per Page 10.
Yes.
That page is intended to represent when we believe the project really will come into full service.
Okay. Got you.
So 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.
Got you. 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 breadth – overall breadth of our business and the growth going on really in all areas across Transco, across the Northeast, the deepwater. And we’re excited to see the DJ started 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