Williams Companies Inc

NYSE:WMB

Earnings Call Transcript 2019-Q4

[Operator]

Good day, everyone, and welcome to The Williams Companies Fourth Quarter and Full-Year 2019 Earnings Call. Today’s conference is being recorded.

At this time for opening remarks and introductions, I would like to turn today’s call over to Mr. Brett Krieg, Director of Investor Relations. Please go ahead, sir.

[Brett Krieg, Director of Investor Relations]

Thanks, Carey. Good morning, and 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 on the call today are our Chief Operating Officer, Micheal Dunn; our CFO, John Chandler, our General Counsel, Lane Wilson; and our Senior Vice President of Corporate Strategic Development, Chad Zamarin.

In our presentation materials, you will find the disclaimer related to forward-looking statements. This disclaimer is important and integral to all remarks and you should review it. Also included in our presentation materials are non-GAAP measures that we reconcile 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.

[Alan Armstrong, President and Chief Executive Officer]

Okay, great. Thanks, Brett. Good morning, and thank you for joining us as we discuss our fourth quarter and the full-year 2019 financial performance and our key investor focus areas. So let’s move right into the presentation and take a look at our strong year-end performance.

Here on Slide 2. 2019 was another year of strong predictable growth and solid execution. This is now the third year in a row we have exceeded the midpoint of our guidance range on key financial metrics. This highly reliable and predictable performance is the result of continuously improving execution by our operating teams on many fronts: capital project execution, reliable on-time services for our customers, safety performance, environmental stewardship, capital discipline and operating efficiency, all of these efforts circle around a deliberate strategy to deliver long-term shareholder value by accomplishing the following.

First is our focus on being the very best at providing infrastructure services for natural gas as an economically and environmentally superior energy source. Second is to reduce direct commodity margin exposure and basis risk to focus on highly predictable fee-based revenues. And certainly, the reason that our business has become so predictable is largely focused on that one. And we’ve very much achieved what we’d hoped to accomplish in terms of that reduction. And third is to deliver the balance sheet to provide flexibility and unquestioned financial stability.

These efforts grow predictable record results in 2019 across key performance metrics. The company produced record annual adjusted EBITDA of $5.02 billion and growth of 8% over the record 2018 performance of $4.64 billion.

Distributable cash flow, also record grew by an impressive 15% to an amount of $3.3 billion and this financial performance was driven by continued growth in the very large volume of natural gas the company gathers from a diversified array of both supply basins and a variety of producing customers.

While our record average daily gathering volume of 12.9 Bcf a day for the full-year of 2019 was a 5% growth overall, and it was 15% in the Northeast. In fact, in the fourth quarter, that – on that comparison, we saw volume growth of over 10%, up to 13.3 Bcf per day and for the whole gas – against the whole gas gathering portfolio and a 12% growth in the Northeast G&P segment.

So the company also continued to realize growth in the interstate gas transmission, driven by a 11% growth in the long-term firm contract capacity on Transco, the nation’s largest and fastest-growing pipeline system.

Turning now to Slide 3. I want to take a brief moment to acknowledge some of the key performance metrics we are using to manage the business and to measure our continuous improvement efforts.

First of all, our financial performance, along with the company’s disciplined approach to capital investment and successful efforts to monetize assets, brought our leverage ratio under 4.4 times, which was – is significantly inside our originally guided leverage ratio of under 4.75 times. So we are certainly well on our way to reaching our target of 4.2 times in 2021.

Also, as an enterprise, we are focused on improving our return on capital employed, or ROCE, while it is only a snapshot and it’s certainly not a perfect measure of long-term returns, measuring the year-to-year improvement keeps us very focused on preserving our precious capital and a 13% compounded annual growth rate on the very large capital base the company has employed is great improvement. But we look to continue bringing our ROCE up with our continued strong discipline around capital investment.

Our operating margin ratio shows how much of our gross margin gets to the bottom line after operating and administrative costs. And to improve on that, we have to utilize our scale to grow gross margin faster than our unit cost. We have improved this metric even in a slowing growth environment and dwindling commodity margins and target continued improvement here through both cost management and growth.

And finally, our total recordable incident rate is a measure of our safety performance among several safety metrics we monitor. There has been a great improvement in our total recordable incident rate over the last several years, as our safety culture continues to improve and our employees find and eliminate hazards from the workplace and protect the public, while operating our assets.

Every employee has full Stop Work Authority and they – and when they recognize the safety issue and are empowered to make it right. Our employees own this metric and are responsible for this great improvement, and I’m pleased to report on that group’s improvement here. And, in fact, in 2019, our TRIR came in at 0.55, which is well below the toughest of industry benchmarks.

And finally, all this discipline and focus has culminated to drive an impressive 25% CAGR on our EPS from 2017 through 2019.

Now, we’re going to move on to Slide 4. And here on Slide 4, we provided a clear view of our full-year and fourth quarter 2019 financial performance relative to 2018 period. And as you can see, we continue to enjoy steady growth across our key measures, despite the impact of asset sales and much lower commodity margins on a full-year basis.

We covered some key annual performance metrics on the previous slide. But on this slide, from an annual perspective, I’ll just point out that growth in our GAAP cash flow from operations of 12% is right in line with the adjusted EBITDA in DCF performance we’ve already discussed and the per share metrics, both DCF per share and adjusted EPS, showed equal or stronger growth with DCF per share up 14% and adjusted EPS up with that 25% again this year.

Another key piece of 2019 performance is the improvement in an already strong coverage ratio. Our DCF exceeded our dividends by 1.79 times, or nearly $1.5 billion. This healthy and growing coverage is one of the key items the management team and Board evaluated, as we raised our dividend here in 2020 by 5%.

Our impressive performance on leverage was a result of strong operating performance that we’ve already discussed, but also importantly, a disciplined approach to capital investment. In fact, I think, this is one of the great highlights here for the year and for the quarter that our total capital, both growth and maintenance came in under $2.5 billion for 2019, and that was a $1.7 billion, or 40% reduction from 2018 and well below our original guidance on both growth and maintenance.

So during 2019, we saw an environmental – sorry, we saw an environment shaping up that would challenge the growth plans some of our producer customers have laid out. We quickly responded to the realities we were seeing in the market by moderating our capital spin versus the budget we had created in late 2019. And, in fact, in the Northeast alone, our total capital spin came in approximately $400 million under that original budget.

So against the backdrop of a much lower commodity price environment that we had in 2018, the company produced strong growth in our various earnings and operating metrics and grew dividend coverage, while also realizing over $1 billion in net proceeds from our portfolio optimization efforts and lowering leverage. We are certainly very pleased with the performance that we saw across many of these facets for the full-year.

So let’s move on to Slide 5 and discuss the main business drivers of our 4Q 2019 over 4Q 2018 on an EBITDA basis. And so here on Slide 5 now, we compare fourth quarter 2019 to fourth quarter 2018. Adjusted EBITDA increased about 7%, or 8% if you adjust for the bigger transactions that affect the year-over-year comparison.

This 4Q growth came at a point in the year when G&P customers had already begun to talk about moderated growth plans and commodity price concerns. Our business showed growth against a tough comp, where the prior year period already included contribution from the Atlantic Sunrise project and the associated gathering volumes that grew dramatically in the fourth quarter of 2018.

On the left side of the slide, you can see a net unfavorable $7 million comparability adjustment in the gray bars, which includes removing the adjusted EBITDA from the various asset transactions netted against the favorable addition of 38% UEOM interest. Normalizing for those items, you see adjusted EBITDA growing 8%.

Now moving over to the right side of the chart to focus on the financial performance of our continuing business, the Atlantic Gulf increased by $43 million, or 8% from the fourth quarter of 2018, driven by Transco revenue growth from the Gulf Connector and Rivervale South to Market expansion projects.

Additionally, for fourth quarter of 2019, results include the increased EBITDA from the Transco rate case settlement. And lastly, while total deepwater gas volumes were up 17%, we saw a decrease in revenues due to temporary producer operational issues on our Gulfstar deepwater platform. And this issue appears to be corrected now, as we’ve seen volumes come back very strong here in first quarter.

Also in the Norphlet pipeline, which serves Shell’s deepwater Appomattox field in the Gulf East, continues to see volume increases after flowing first gas on the pipeline in the third quarter of 2019. The next, the Northeast G&P area led the fourth quarter performance with a 19% increase, driven by an increase of about 970 million cubic feet per day, or 12% on higher gathering volumes and higher gathering fees that were associated with expansion projects and escalators that are built into those contracts.

Volume increases were led by Susquehanna Supply Hub and Bradford areas, which grew about 600 million cubic feet per day, but all our operated Northeast franchises saw volume growth over this time period So overall, our operated assets in the Northeast continue to see very strong growth across the Board.

Finally, even though we enjoyed an impressive 10% increase in total gathering volumes on our remaining assets during the fourth quarter comparison, the West EBITDA was relatively flat, due primarily to $31 million decrease in revenues for our Barnett gathering business. As a reminder from our third quarter results, this decrease was associated with the end of a Barnett MVC or minimum volume commitment and a related step down in deferred revenue amortization.

The Barnett MVCs expired at the end of June 2019. And once that happened, the revenue recognition rate of fixed payments that we previously received, began to reflect actual volumes rather than the MVC levels. We also overcame about $13 million of lower NGL margins in the West, which was a 45% decrease from the prior year fourth quarter.

Now moving on to Slide 6. We’ll look at the full-year drivers of adjusted EBITDA, which increased about 8%, or over 11% if you adjust for the bigger transactions that affect this full-year comparison. Once again, on the left side, in the gray bars, if you net these out, you’ll see an unfavorable $110 million comparability adjustment from the various asset transactions that occurred during this time period. In 2019, Atlantic Gulf increased 20% and the Northeast was up 19%, driven by the same factors discussed on the previous slide.

With the addition of a full-year revenue impact of the Atlantic Sunrise project that came online in early October of 2018, the West is down about 6%, reflecting much lower NGL prices, again, to step down to the Barnett revenue we talked about, offset by growth in the Haynesville, Eagle Ford and DJ basin. Also, our Conway frac and storage business, so that’s our NGL services business, continues to see strong fee revenue growth on the back of NGL production that’s been coming out of both the DJ and the Bakken areas.

Our team’s crisp execution drove the growth we continue to show in the Atlantic Gulf in Northeast this year, leading to an overall 8% growth in adjusted EBITDA, despite the significant asset sales, the much lower NGL margins and the one-time step down in the Barnett revenue recognition.

So now let’s move on to Slide 7 to address the key investor focus areas. So first, let’s set the scene a bit for 2020. As of January 1, 2020, our Northwest Pipeline business will be managed and reported with our other regulated interstate gas transmission systems in a segment we will call Transmission & Gulf of Mexico.

This move will streamline the management and operations of the regulated gas transmission business, combine these businesses into a single reportable segment and providing a clear picture of the very solid performance and predictable cash flow generation of these competitively advantaged assets. The deepwater business will remain in this segment as well and become more important to our EBITDA and ROCE improvement, as growth in this basin is coming back strong.

Moving Northwest Pipeline out of the West segment will position the West as a gathering, processing and NGL services business, providing a full suite of midstream services to producers from wellhead gathering all the way through NGL fractionation storage and NGL logistics, especially after the Bluestem NGL project is placed in service later this year.

And the Northeast G&P segment will continue to provide all midstream services to the prolific Marcellus and Utica Shale, the largest source of gas production in North America. We will continue to separately report the West and Northeast G&P segments, but combined management will allow us to take better advantage of our tremendous scale and continue to grow our operating margin in this producer-facing business.

So I’d like to talk for a moment about how we see the G&P business, both in the near-term and the longer-term and how we have positioned this business. We saw record gathering volumes in 2019 because of continued production successes by our upstream customers, continued growth in natural gas demand and great execution by our teams.

But over the last year, robust production growth has outpaced very healthy demand growth and, in fact, demand has grown significantly 21% over the last three years, but domestic production has grown even faster. This imbalance will be a near-term headwind to volumes and EBITDA in the G&P business, as current prices don’t support investment in gas drilling in most cases.

So producers, of course, are acting rationally, slowing their capital investment and reducing production growth. While some producers are still forecasting growth, others are focused on keeping production flat, and while lack of recent investment from the upstream will cause declines in other production areas.

Some producer balance sheets are stressed. We have already seen some bankruptcy filings. While a customer bankruptcy filing is often disrupted to the normal course of business, it affects various midstream services and contracts very differently.

After a very long time in this midstream business, I have seen and experienced many instance of producers’ stress and even bankruptcy, and it’s very clear to me that the most protected service by far is that a wellhead gathering. Wellhead gathering is absolutely essential to any reserves that are going to be produced. Gas could not get to market and cash flow cannot be realized, if wellhead gas gathering is not available.

While counterparty credit is important, the physical nature of the service is even better security. We believe this supply demand imbalance is only a near-term concern, as last week’s storage was only a 215 Bcf above the five-year average.

We see continued demand growth bringing supply and demand – sorry, supply and demand back in balance. And our long-term strategy is, as we’ve told you many times before, is predicated on the belief that the economic and environmental benefits of natural gas will support continued long-term demand growth, both domestically and internationally and that U.S. domestic supply is well-positioned to grow its share of global demand as well.

In the long-term, whatever demand is, supply will grow or decline to meet that demand. And importantly, we expect low-cost gas basins to continue to be the majority of supply that will meet this demand. Associated gas will be important, no doubt. But gas-directed drilling, the source of approximately 65% of today’s gas supply will remain the bedrock of domestic gas production.

So we feel confident in the long-term position of our assets and strength of our strategy. But the current price environment is a reality that the market will navigate through here in the near-term, and we have built a very resilient G&P business that can succeed in a wide range of market environments, the dramatic growth we’ve seen over the last three years and the currently challenging price environment for our producing customers.

We built this business very intentionally, not by accident. We’ve been at this a long time. And we have moved away from direct commodity exposure and from reliance on marketing and basis spread for profit. We have taken strategic action to broadly diversify our sources of EBITDA, both in the 15 different supply areas, our G&P businesses served and the very wide variety of customers we contract with to provide those services.

Another thing I want to point out is that continues to demonstrate our ability to work with a wide range of stakeholders – excuse me, is that the free cash flow produced by our onshore G&P businesses grows dramatically when drilling activity pulls back. Capital spend declined significantly, driving near-term ROCE improvement and tremendous free cash flow growth.

So, as we’ve said before, when we do see investment pullback on the drilling side, we see tremendous continued increase in free cash flow growth in the G&P business. Our West is a great example of that.

And with regard to our 2020 guidance, we are reaffirming the guidance we provided at Analyst Day in December. While the largest near-term uncertainty is producer activity, we feel comfortable with our 2020 guidance. We will keep a keen focus on capital spending in cost management as the year evolves. And importantly, we are expecting to fund dividends and CapEx with internally generated cash flow, which benefits the company as we look toward our long-term goal of reaching a net debt-to-adjusted EBITDA leverage ratio of 4.2 or lower.

And so I just want to comment a little bit more here on the guidance for 2020. First of all, the volumes that we saw in the last-half of the year, certainly in the Northeast and the rates that we enjoyed there, along with what we’re seeing here in January and February in terms of volume, as well as some pretty significant cost cuts that we made late in the fourth quarter of 2019, all compiled to continue to give us confidence on our guidance for 2020, despite the challenging price environment that’s out there today.

So now, let’s move on to discuss some of the key issues around our Transmission & Gulf of Mexico business. First, we’re pleased that we have filed our Transco rate case settlement with FERC on December 31. We had only supporting comments from shippers to FERC. Since the rate settlement was filed with FERC, we are pleased to have reached this settlement that we expect to provide $76 million benefit to adjusted EBITDA in 2020 versus our – the last full-year of 2018, which was the last time we had a period with no rate case impact.

I also want to point out the successes we’re having on our portfolio of transmission expansion projects. Since September, we placed the Rivervale South and Gateway project in service, both of these were in New Jersey and our Northwest Pipeline commenced service on the North Seattle Lateral expansion. These are two areas with extremely rigorous permitting processes and a politically active vocal minority opposing natural gas infrastructure in short, challenging places to build gas pipelines.

Williams continues to demonstrate our ability to work with a wide range of stakeholders in a constructive manner to address these regulatory, political and community concerns, while still getting important infrastructure expansions permitted and built. We plan to continue that track record on the over $3 billion of pipeline expansion projects that are currently in execution mode, and we are achieving key milestones on each of these projects.

First of all, Hillabee Phase II is mechanically complete and ready for in-service. The Southeastern Trail project has all of its federal permits and began construction in January of this year, with an in-service targeted by year-end. The Leidy South and Gulfstream, Gulfstream’s sixth expansion now, both received favorable environmental assessments, which is a key step in the FERC certificate process, and each project remained on track for scheduled in-service, Leidy South by the end of 2021 and the Gulf Stream Phase VI expansion by the end of 2022.

Our Regional Energy Access project is looking more attractive as time goes on. We have a project that will be between 800 million to 1 billion cubic feet per day. And once we’ve settled on the appropriate size of the project, we’ll move to complete the work to apply for FERC certificate. So we’re in the final stages of tidying up contracts there with our customers. But we do have a project at this point, it’s a matter of the size of that project.

We also continue to feel very confident about the prospects for Northeast Supply Enhancements completion, and we look forward to the conclusion of National Grid’s process to assess alternatives for serving Brooklyn and Long Island’s growing energy needs.

We continue to see this project as the most reliable, most environmentally beneficial, and most economically friendly alternative. At full load, the fuel oil to natural gas substitution for this project would enable an emissions reduction up – that’s equivalent to taking 500,000 cars off the road.

So that, along with the savings to the customers and the residents in those areas, we think are powerful motors for getting that project approved, despite the very noisy minority around that. And we certainly know that this is by far the best solution for the area.

Beyond these projects and execution, we continue to make good progress on our backlog of projects in development and we expect several of these to move into execution mode this year. Transco is well-positioned to continue growing our contracted volumes and a well-established corridor serving a large portion of the U.S. population.

The forces you see working in the market today are only increasing the competitive advantages of Transco. Low prices continue to incent demand in all sectors, and our access to many geographies and types of demand is unmatched. LNG, industrial, power, residential, commercial are all growing along Transco.

Difficulties seen by Greenfield pipeline projects will also benefit Transco in the long run, as Transco has uniquely positioned to meet new capacity demand by expanding along its existing rights of way, which are irreplaceable and unmatched in terms of their proximity to demand.

Our Gulf of Mexico assets are similarly positioned against the growing market opportunity. Chevron made a positive final investment decision on their Anchor project in December of 2019. Anchor is near our Discovery’s Keathley Canyon Connector, and we are excited to be finalizing the definitive agreements to provide a full range of services for this very rich gas to be produced by the Anchor project.

Anchor represents continued realization of the strategy that supported the original Keathley Canyon Connector investment, capturing new volumes from significant nearby deepwater prospects. Given its proximity and our pre-planning, we will not have to invest any significant capital for this new business.

Williams will continue to pursue similar connections as other nearby prospects moved towards FID and first production, including the LLOG-operated Shenandoah, Yucatan, Leon and Moccasin; the Equinor-operated Monument; and the Total-operated North Platte. The Shell-operated Whale project is an even larger opportunity for us. And the services we expect to provide to this dedicated field include gas transportation, gas processing, and importantly, the crude oil transportation as well.

Shell continues to make progress on this very large-scale project and expects to make their FID decision this year. And, in fact, in November of 2019, Shell awarded Singapore’s Sembcorp Marine the contract to build the well floater. In addition, Williams has executed a reimbursement agreement with the well owners to cover commitments in 2020 to keep the project on schedule for first production. Williams will secure several long lead items, including the line pipe valves and fittings and the installation contract and ongoing engineering costs.

Whale and Anchor would represent a significant increase in the volumes we are currently handling on our consolidated assets. But these are just two of the many opportunities our deepwater assets are competitively positioned to win, as producers in the area are looking to align new development with existing infrastructure to lower cost and decrease time to market.

We believe our business is very well-positioned to benefit from continued demand growth in natural gas over the long-term. And that our strong competitive position and conservative financial model makes us a resilient business that can deal with the near-term challenges in the market, while positioning ourselves for the strong growth that’s ahead.

So with that, let’s go ahead and transition to our Q&A session. And thank you, again, for your time today.

[Operator]

Thank you. [Operator Instructions] Our first question will be from Jeremy Tonet with JPMorgan.

[Jeremy Tonet, JPMorgan]

Hi, good morning.

[Alan Armstrong, President and Chief Executive Officer]

Good morning.

[Jeremy Tonet, JPMorgan]

Just want to start off with, I guess, some of the strategic transactions that you guys had done in recent years and kind of some sales and JVs. And I was wondering if you could comment, I guess, on the ability to kind of capture those type of opportunities going forward here and what that could mean for hitting kind of the 4.2 leverage ratio that you guys are targeting there? If you’re able to do that, I guess, it’s quicker, or if that doesn’t come together, how long do you think it would take you to hit kind of a target 4.2?

[Alan Armstrong, President and Chief Executive Officer]

Yes. Jeremy, good morning, and thank you for the question. I would just say, first of all, we’re encouraged by the attraction to the kind of assets that we have, which have long histories of cash flow. And so that’s very different than some of the other assets out there that aren’t as well-positioned or more speculative in nature of cash flow.

So we think, assets that are stable and have a long history of cash flow are pretty important in this market today. And so we’re very encouraged by that. I would just say, the growth that we have and the continued cash retention that we have in the business, right now, we certainly have our eyes on that 4.2 even without that. But we look at the further transaction as a way to accelerate ourselves towards that, and likely well under that with some – with any significance to the size of those transactions.

[Jeremy Tonet, JPMorgan]

Got it, thanks. And just want to see, I guess, with regards to producer activity and kind of conversations with producers today versus where they stood at the Analyst Day, just wondering if you could help us think through a little bit more on how that has changed? Has it been notable, or not as notable? I guess, I’m trying to think how that translates into guidance. Should we be thinking about the midpoint, or does this kind of bring more towards the lower-end of guidance, or any color you could provide there would be helpful?

[Alan Armstrong, President and Chief Executive Officer]

Yes. Great question, Jeremy, and thanks for asking that. I know that’s an issue on lot of people’s mind. First of all, I would just say, obviously, we have a very diverse business and some things go South on us and some things go positive. If you think back to last year and you think about the commodity price assumptions that we had versus how the year actually wound up, we outperformed as, again, good evidence of how things can go our way to offset other negatives that occurred during the year.

So I would just say, we do have a large portfolio. I also, though, as I mentioned in my comments, and I think this is really important for people to understand. If you look, for instance, a lot of concern around the Northeast volumes and if you look and took the combined – took the average of the third quarter and the fourth quarter, you would see that if we – if all we did was repeat that, we would come in above our guidance level for the Northeast for next year, and I know there has been a lot of concern about that.

If you took and just took four times the fourth quarter, assuming the fourth quarter held where it was and didn’t see growth – any growth at all, you’d see a – we would beat pretty significantly that guidance that we had laid out for the Northeast.

And so that, I would say, combined with a couple of things, one is the fact that our fourth quarter did come in stronger than we were expecting for the Northeast. When we were laying guidance out in – at Analyst Day, we were working off a forecast that was actually exceeded for the fourth quarter. So we’re starting off better than we start than we expected to.

Secondly, we’ve seen January and February volumes now. And so we’ve got pretty good confidence about where actual volumes are.

And then finally, I would say, we took the cost that we took out that we’ve worked on and planned around during 2019, most of those costs and the impact of those costs actually started rolling out very late in the fourth quarter of 2019. So we will have the benefit of that working with us going into 2020.

So I would just say a lot of positive things that are occurring as well with some deepwater production that’s coming on a little faster than we would have expected as well. And volumes actually, again, exceeding where we thought they would be at this point in time when we laid out at Analyst Day. So those are the things that have given us the confidence on our guidance being maintained as we sit here today.

[Jeremy Tonet, JPMorgan]

Got it, great. That’s it for me. Thanks.

[Operator]

Thank you. Our next question will be from Spiro Dounis with Credit Suisse.

[Spiro Dounis, Credit Suisse]

Good morning, everyone. Alan, I appreciate your comments around G&P being one of the more protective components of the value chain. But I guess, when we think about quantifying a potential impact, is there a way for you to help us quantify how much of your volumes or margin could be considered maybe above market or maybe subject to renegotiation?

You’ve been pretty proactive on this front so far. So not sure how much your portfolio is, in theory, still at risk? And if you’re receiving any sort of inbound inquiry from customers to do a blend and extend?

[Alan Armstrong, President and Chief Executive Officer]

No, we are not – I think we have – we’ve completed all negotiations that anybody has entertained with us on issues right now, particularly with Chesapeake. We settled that in the Eagle Ford, and I think you’ll see this year, I think you’ll see that some of the assumptions that were made by some of the analysts about where that was going are going to be proven very wrong about their assumptions on that for the Eagle Ford.

And I would say this in terms of incenting further drilling, we’ve been working pretty actively. Our commercial teams have been working very actively in places like the Haynesville to incent drilling on acreage that’s dedicated to us, but not otherwise being drilled. And that does require us putting an incentive rate out for new drilling, but it doesn’t affect the rates of the existing business.

So it’s just a way to attract new drilling dollars against acreage that Chesapeake, for instance, likely wouldn’t get to, if we weren’t out working transactions to help make that happen.

[Spiro Dounis, Credit Suisse]

Understood. And then some of the common pushback we received from time to time just around the growth backlog and your ability to spend, I guess, enough to really on those demand pull projects to drive that 5% to 7% growth. And so in other words, I think people are struggling with maybe the scope of these projects and their ability to grow that $5 billion EBITDA base. And so are there opportunities beyond the ones you list that maybe we’re not appreciating, or is G&P actually still an ongoing major contributor to growth even at the lower CapEx levels?

[Alan Armstrong, President and Chief Executive Officer]

Yes. I think, certainly, we had a great year of growth this last year and on an adjustment for both asset sales and margins, where our growth was a lot better than we would have just built into the plan in terms of volumes and fee-based rates last year, a lot of that came from good cost control and really good execution on our projects, bringing them on a little earlier than expected.

But I would say, the things that I think the market tends to miss is the things like the DJ basin growth that continues to come on very nicely for us, the Bluestem project coming on for us, the deepwater, which is really coming back, I think, 95% of the rigs now available – floating rigs available are in under contract now in the deepwater.

And so we are seeing a lot and expecting a lot coming from that area as well. So, these projects coming on in Transco are pretty powerful, but that’s not what we’re totally dependent on for our growth by any stretch of imagination.

[Spiro Dounis, Credit Suisse]

Very helpful. Thanks, Alan.

[Operator]

Thank you. Our next question will be from Shneur Gershuni with UBS.

[Shneur Gershuni, UBS]

Hi, good morning, everyone. I’m just wondering if we can revisit the guidance commentary. It sounds to me that you’re fairly confident with the midpoint of your guidance, despite producers being shifting over to maintenance mode at this stage right now. You’ve talked about some of the pushes and pulls, including some of the cost reductions that you’ve put through that that gives you some confidence in that. If this were to – maintenance mode were to maintain itself into next year, are there any more levers that you can pull on the cost side and on the CapEx side to sort of maintain cash flow generation, where you expected to be this year or even potentially driving higher next year?

[Alan Armstrong, President and Chief Executive Officer]

Yes. We certainly have quite a bit of capital still in plan. And despite the narrative that’s out there, we still have producers that are still pushing ahead with the growing plan, some of those based on hedges that they have and some based on contracts that they have. But we still have some pretty big obligations to keep up with that.

I know, the market is – the narrative is very different than what you’re seeing. But in reality, right now, we do have that capital built in, because those producers are moving ahead right now with their activities, as they told us they would. And so – and those come with obligation on their part, so we have to be ready with that capital that’s in there.

If that were to change for whatever reason, then that might shift that back. But I think we should be clear that we do have customers continuing to have growth and plan growth in the Northeast. And so, we’ll wait and see, obviously. But right now, it’s getting pretty late in the process for them to be pulling back from those plans that they’ve laid out for the year. And, again, I think a lot of that is based on hedges that they have in place that continue to support those activities.

So I don’t want to get into each individual customers, because that’s up to them to lay out their plans and communicate that. But we are responding to the very detailed planning processes that we work within the customers, and we do have capital in the plan to help drive that. And so we – like we had last year, if we need to turn that back quickly, we certainly would. But there is quite a bit of activity that’s going on out there, despite what the narrative is.

[Shneur Gershuni, UBS]

And would you feel that you would have more flexibility on 2021, if this were to maintain itself?

[Alan Armstrong, President and Chief Executive Officer]

Shneur, you’re breaking up just a little bit. Could you repeat that?

[Shneur Gershuni, UBS]

Sure. Yes, would you have more flexibility on capital and cost structure for 2021, if this trend sort of maintained itself? Obviously, it’s late in the year to be adjusting things for 2020, but I was more thinking about 2021? Do you have a lot of levers that you can still pull there if this environment maintained itself?

[Alan Armstrong, President and Chief Executive Officer]

Yes, we certainly do. And I think part of our effort to combine the West and the Northeast G&P area is, because we do expect to move. I mean, that area has been growing grammatically. It sounds really easy for us to sit here in our offices and think about the kinds and talk about the growth off of spreadsheet. But the reality is the very, very hard work of our employees and the teams out there trying to keep up with all that growth. They’ve done a remarkable job on that.

But it does take a lot of people and it takes – when you’re investing in the capital, it puts a lot of costs onto the operating teams as well, because there’s a lot of change going on that they’re having to manage. So the more mature in a slower growth environment absolutely allows us to go after and increase our operating margin in an area. And us combining our West and our Northeast from a management perspective is allowing us to get after some of that.

[Shneur Gershuni, UBS]

That makes great sense. And as a follow-up question, there’s some new PHMSA rules out. Just wondering if you’ve looked at it and whether this could kick off potentially a rate-based investment cycle, or do you constantly replace pipe and it’s really irrelevant to all these new rules?

[Micheal Dunn]

Good morning. This is Micheal. I’ll take that one. So on our transmission systems, we’ve been ahead of the curve there for a long time and maintaining our commitment to keeping our assets safe and reliable. And I would say, with the timelines that have been laid out in the new rules, there’s a long runway to compliance there.

So I think that’s going to allow not only ourselves, but the industry to manage that pretty well within our maintenance CapEx and our normal OpEx. And so I’m not too concerned about having that drive any additional rate cases.

[Shneur Gershuni, UBS]

Okay. And then one final question, Alan, in your comments about the NESE project, if that were to come to fruition, would that be considered a positive ESG benefit to Williams, given your comments about how many cars you take off the road?

[Alan Armstrong, President and Chief Executive Officer]

Shneur, I’m sorry, you broke up, again. On which project were you asking that question?

[Shneur Gershuni, UBS]

With respect to NESE, you’d given a whole argument about how many cars who takes off the road and so forth. Just wondering like as we sort of think about ESG, is that something that would be viewed as a positive benefit?

[Alan Armstrong, President and Chief Executive Officer]

I would certainly hope so. But it’s – I think there’s a lot of uncertainty right now within the rating systems within ESG as to where we get that. We would certainly pronounce that as a win, because it certainly is going to impact the environment, and we certainly would be taking a big part in making that possible. So we certainly would want to talk about that.

I would say even – perhaps even larger than that and more directly related to that would be the emissions reduction projects on Transco that we still intend to follow through with some negotiations lingering post the rate case on that. But that would be very dramatic conditions – reductions.

And it’s exactly the kind of thing that I think the whole industry certainly, Williams and the whole industry is really capable of reducing emissions dramatically. And if the focus got to be on actually reducing emissions, and not just trying to stop fossil fuels, there’s a lot to be accomplished by the energy industry in terms of emissions reductions, and we expect to play a big part of that.

[Shneur Gershuni, UBS]

All right, perfect. Well, thank you very much. I appreciate the color today, guys.

[Operator]

Thank you. Our next question will be from Tristan Richardson from SunTrust. Richardson, your line is live. Please be sure you’re not on mute. Al right. Next question will be from T.J. Schultz from RBC Capital Markets.

[T.J. Schultz, RBC Capital Markets]

Great, thanks. Just first in the Gulf, you’ve got some big projects in 2023, 2024 timeframe. But you also listed off in the prepared remarks a number of projects that may be more near-term potentially. So just any tiebacks assumed in the next year or two, that may be additive to EBITDA, or could offset some slowing G&P growth?

[Alan Armstrong, President and Chief Executive Officer]

Yes. T.J., great question. First of all, one of the impacts this year will be the growth in Appomattox. So remember, our Norphlet pipeline that we put online last year, that is finally starting to ramp up pretty dramatically as expected. Shell has got some big plans out there on Appomattox, so we’re really excited about that.

So even though the construction work is there’s nothing new on that, the actual volume growth on that we expect to be pretty nice this year. On top of that, we tied in two prospects on discovery last year, that were kind of midway through the year. Those will contribute to discovery this year.

And then finally, on Gulfstar, Hess’ Esox project was brought online well ahead of schedule. They did a great job of executing on that project, and really made for nice returns for both themselves. And, of course, we make nice fees on that business as well. So that was well ahead of our schedule, our plan as well.

There’s also work going on by Kosmos around some of our areas with their Kodiak 2 well that they’re working on right now. So a lot of activity out there, and we’re very fortunate to have a lot of that activity directly around our assets out there.

[T.J. Schultz, RBC Capital Markets]

Okay, great. Just for follow-up, maybe a question for John. You mentioned at the Analyst Day the ability to lower some interest costs. Just what are you seeing today as the ability to lower interest costs for maturities in 2020 and 2021 that get refinanced? And does your guidance assume that you pay down any of that maturing debt with cash, or is that more dependent on asset sales?

[Alan Armstrong, President and Chief Executive Officer]

That’s more dependent on asset sales. Our guidance assumes a refinancing. But I will tell you, we do have $1.5 billion of our debt maturing in March at a net rate of 5.2%. We could refinance that today, for example, 10-year – at a 10-year rate of 3.3%. So we like the rate environment right now.

I will tell you though, we’re holding tight and waiting you. I think it’s no secret that we’ve said we are looking at potential or opportunities for asset sales or selling interest in some of our assets. And I – we don’t want to get in front of that by paying down debt that otherwise could be paid down with cash received through one of those transactions. But I will tell you, our guidance and forecast didn’t include asset sales.

[T.J. Schultz, RBC Capital Markets]

Perfect.

[Alan Armstrong, President and Chief Executive Officer]

And so we could see interest savings just through the refinancing and obviously much more significant savings if we actually did pay that down through the – through an asset sale.

Operator, are you still there.

[Operator]

Our next question comes from Colton Bean of Tudor, Pickering Holt & Co.

[Colton Bean, Tudor, Pickering Holt & Co.]

Good morning.

[Alan Armstrong, President and Chief Executive Officer]

Good morning.

[Colton Bean, Tudor, Pickering Holt & Co.]

Alan, you had mentioned that the volume trends that you are seeing thus far in 2020, can you give us or just frame the activity levels that you’re seeing in some of those primary basins in the West? I know we spent a lot of time in the Northeast, but just how you’re seeing some of the West basins and maybe how that compares to your guidance that you laid out in December?

[Alan Armstrong, President and Chief Executive Officer]

Yes. Micheal, do you want to take that?

[Micheal Dunn]

Sure. We’re seeing really good results in the Eagle Ford right now coming in, starting the year as well as Haynesville are well ahead of where we thought they would be at this time of year. A little bit challenged in the Wyoming area with the weather. There has been some pretty severe weather in Wyoming this year that’s challenged the Wamsutter area as can typically happen at this time of year. But overall, I think, we’re going to see an increase of what we anticipated so far here in the first quarter from what our forecast should.

[Colton Bean, Tudor, Pickering Holt & Co.]

Yes. And so it sounds like the Rockies segment there hasn’t been impacted as much as you would have expected from the natural gas decline?

[Micheal Dunn]

No, we’re still seeing good production coming out of the Piceance. For example, as Alan talked about earlier, we have some incentive rates out there with our customer, where they are continuing to drill in the Piceance, for example, and getting good results. And our DJ Basin is really performing very well with our Rocky Mountain midstream asset, and so we’re very pleased with that and also capturing the NGLs coming off the processing there that’s going down OPPL pipeline system.

[Colton Bean, Tudor, Pickering Holt & Co.]

Got it. That’s helpful. And then just on Leidy South, given some of the moving pieces around producer plans, has there been any discussions with anchor shippers that would impact that Q4 2021 timing, or is that solely contingent on the permitting process at this point?

[Micheal Dunn]

No, it’s solely dependent upon the permitting process at this point, and we got our environmental assessment earlier than anticipated. So everything looks to be in good shape there, had no conversations at all about slowing that project down with our customers

[Colton Bean, Tudor, Pickering Holt & Co.]

Well said. I appreciate the time. Thank you.

[Operator]

Thank you. Our next question will be from Derek Walker from Bank of America.

[Derek Walker, Bank of America Merrill Lynch]

Hi, good morning.

[Alan Armstrong, President and Chief Executive Officer]

Good morning.

[Derek Walker, Bank of America Merrill Lynch]

Alan, at the Investor Day, you mentioned a return on invested capital around 12% for projects over the last several years. And as you look to sort of allocate capital to the highest returning projects, it seems like it’s a – for this year, it’s a mix of Northeast, regulated transmission, also some deepwater, where you have some operating leverage. So I guess, relative to that 12% number, do you see at least in 2020 or at least over the next couple of years getting above that 12% number, or is it just going to be a mix, or how should we think about that relative to the 12% number you guys been able to achieve over the last several years?

[Alan Armstrong, President and Chief Executive Officer]

Yes, great question. Well, first of all, I would remind you that our individual project returns are often – well, in fact, they are well above that number. But that’s working against things like deepwater declines, the declines in basins like the Barnett and certainly deferred revenue step down and things like that.

So there is a natural decline in some pieces of the business that those returns have to offset. And – but I would say that our current returns on projects are as good or better than what we’ve had in our previous mix of projects as we’ve tightened the capital budget. Obviously, as you tighten the capital, you’re allocating stuff out. And so I would expect that number to continue to be as good or better than we’ve had on it on an overall number across the whole portfolio.

[Derek Walker, Bank of America Merrill Lynch]

Thanks. That’s it for me.

[Operator]

Thank you. Our next question will be from Becca Followill with U.S. Capital Advisors.

[Becca Followill, U.S. Capital Advisors LLC]

Good morning. Alan, you’ve talked about that the Gulf of Mexico assets are well-positioned to win new business. Can you quantify what kind of EBITDA contribution you would expect over the next several years and what potential and the CapEx associated to get there?

[Alan Armstrong, President and Chief Executive Officer]

Yes, Becca, good question. A lot of the capital, what we’ll start spending some this year, as we mentioned, on things like Whale. And so in some – versus an Anchor prospect, so I’m just going to give you the kind of ends of the spectrum here. On one hand, pretty significant capital required on Whale now, because the volumes came in a lot larger than we expected to and the producers wanted plenty of flexibility in their capacity. And so that project is going to take more capital.

On the other hand, Anchor, we had laid a sled down, when we built that Keathley Canyon Connector, we had put sled down, so that we could make those connections fairly inexpensively and the producers generally are providing that capital. And so in that case – and – but we’re not going to make return on that investment capital. So we’re going to make an existing rate.

So in one case, I would tell you, Whale, very significant revenue contributions and EBITDA contributions, that will be in the 10% to 15% just by itself across the whole deepwater. And then things like Anchor would be inside of that, because it’s not – smaller.

You also, as we’ve also mentioned, we have Ballymore. It’s a very large prospect. That project that Chevron and their partners are trying to decide if it’s going to be so big, coupled with some other prospects that they have in the area, they have to put a new floater in. If they had to do that, then we would have to invest new capital. Best thing for us is that they find a way to fit that on to blind faith. And that would be pure incremental EBITDA without any new capital.

So it’s still in the mix. But I can tell you based on both volume and EBITDA, we think it’s very significant. In terms of the total percentage increase in the deepwater, it is going to be a very significant step up from our current EBITDA levels in the area.

[Becca Followill, U.S. Capital Advisors LLC]

Alan, I asked the question, because it’s hard for us to give credit for that and evaluation when I have no idea what significant means in terms of EBITDA. I mean – or what the CapEx is to get there?

[Alan Armstrong, President and Chief Executive Officer]

Agreed. And I think I would just be cautious on our part. What we have laid out, Becca – so I’ll be clear, what we have laid out is that our contracts allow us to get the existing rate on our current systems, plus a 12% after-tax return on any incremental capital that we spend. So that ought to give you a pretty good read, if you take the rate in the Gulf West areas, for instance, you ought to be able to see a pretty nice increase in that. Obviously, we don’t like to spell out exactly what our deals are with our customers.

So we’re not trying to be elusive as much as we are respectful of the relationships that we have with those customers. But if you look at the volume, for instance, on Whale and what’s been quoted out there, you’ll see it looks very much like Perdido, which is what we already gather in the Gulf West.

And so this would be effectively a doubling of what we get in the Gulf West there today. So it is very significant. But, again, we’re – we’ve got contracts in place that we’re not going to lay out exactly what those are. But if you look at total reserve additions versus our current reserves tied up that are out there, you would see that we’re – on both the Gulf East and the Gulf West that we’re coming close to doubling those connected reserves out there.

[Becca Followill, U.S. Capital Advisors LLC]

Thank you.

[Operator]

Thank you. Our next question will be from Danilo Juvane from BMO Capital.

[Danilo Juvane, BMO Capital Markets]

Hey, Alan, good morning. Given that we are in an environment of slower EBITDA growth, how are you thinking about managing leverage and dividend growth? And at what point do you see those two converging longer-term?

[Alan Armstrong, President and Chief Executive Officer]

Yes, great question. Certainly, as we mentioned this year, our coverage came up. And so we certainly – our DCF came in quite a bit stronger than we had planned. And certainly, those are the things that we’re looking at in terms of dividend growth. And certainly, our – as our debt comes down and our interest payments come down, we’ll see continued improvement in that as well.

So I would say, the capital allocation question remains out there for us, as we look at some of these larger transactions that we’re going to look to. But the dividend coverage that we have today is allowing us to have excess cash. And so we don’t see anything really changing on that front.

But as we get into some of these higher-growth areas as we get into 2022 and 2023 that are not requiring a lot of capital. That’s going to build some pretty nice coverage even further than what we have today. So I’m not going to give you a very direct answer on that, frankly, because that’s a Board level decision in terms of what our growth rate on the dividend is. And I would just say this year, the factors that were considered were how much our DCF had grown and the other uses of capital that were available to us.

[Danilo Juvane, BMO Capital Markets]

Gotcha. I guess, my next question is for John. To the extent that you did have some impairments during the fourth quarter, any details on how much that impacts DD&A going forward?

[John Chandler]

Yes. So the biggest impairment we had in the fourth quarter was on constitution. We weren’t appreciating that at this point since it’s in construction. So that won’t really have an impact on our depreciation calcs.

[Danilo Juvane, BMO Capital Markets]

Great. Thanks for that. Last one for me. To the extent that the Texas RRC came out with a report on flaring this week, do you guys have any thoughts on some of the commentary that they laid out?

[Alan Armstrong, President and Chief Executive Officer]

No, I’m sorry. We couldn’t quite hear that on this thing. Could you try that again

[Danilo Juvane, BMO Capital Markets]

Sorry, I was mentioning that the Texas RRC came out with a report on flaring earlier this week. It may have some implications for your systems in Texas. I wanted to see what your thoughts were on what they came out within the report?

[Alan Armstrong, President and Chief Executive Officer]

Yes, thank you. Yes, we’ve actually been pretty engaged with the Railroad Commission on this issue and have attended several conferences, trying to come up with the right solution. And so, as always, we think the Railroad Commission is going to be very constructive. And work to address the concerns that are out there, I would tell you, the producer community, I think, for the most part, is being very responsible on that issue as well.

And we were proud to see Chesapeake in there as one of the top producers in terms of limited flaring. And, of course, we provide those services to them. And so that indicates that our reliability is strong when they’re not having to flare, that tells you our reliability is strong on our service providing. And so we’re proud to see that when our customers are on that list.

And so I would just say, we think that there’s going to be an effort to both at the regulatory level and both by producers themselves to continue to reduce flaring. And we think that’s important for the industry. And we are very supportive of that and we’ll continue to push the industry to do the right thing on that front.

[Danilo Juvane, BMO Capital Markets]

Thank you. Those are all my questions.

[Operator]

Thank you. This is all the time we have for today’s questions. Thank you for your participation at this time. I’d like to turn the call back over to Alan Armstrong for closing remarks.

[Alan Armstrong, President and Chief Executive Officer]

Great. Thank you. And just would close with saying we’re really pleased with the way the year ended up. We had a lot of headwinds, asset sales commodity prices that we overcame and delivered a great year. And I think that’s really attributable to the wide variety of services and businesses that we operate. And we’re very excited about the growth that is reemerging in several areas and the opportunities that we are working hard to capture. And so we appreciate your continued interest in the company, and thank you for joining us today.

[Operator]

Thank you. Ladies and gentlemen, this concludes today’s teleconference. You may now disconnect.