Good day everyone, welcome to The Williams Companies first 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, Devin. Good morning, thank you for your interest in The Williams Companies. Yesterday afternoon, we released our earnings press release and the presentation that our President and CEO, Alan Armstrong, will speak to momentarily. Joining us today is our Chief Operating Officer, Micheal Dunn, our CFO, John Chandler, and our Senior Vice President of Corporate Strategic Development, Chad Zamarin. I will also mention that we've refined our quarterly earnings materials and our format for this call. We've adopted a clearer earnings press release format, we've integrated the previous standalone analyst package into the earnings release document. We now basically have one document there rather than two. In our presentation materials, you will find an important disclaimer related to forward-looking statements. This disclaimer is important and integral to all of our remarks, you should review it.
Also included in our presentation materials are non-GAAP measures that we've reconciled to generally accepted accounting principles. These reconciliation schedules appear at the back of today's presentation materials. With that, I'll turn it over to Alan Armstrong.
Great. Thanks, John, good morning, thank you for joining us this morning as we discuss our first quarter financial performance and the key investor focus areas of the day. As John said, we took a fresh look at the format, we're going to stay pretty brief and focused in our prepared remarks to allow time for Q&A. Let's move right into the presentation to take a look at our first quarter 2019 results. Here on slide two, we've provided a clear view of our year-over-year financial performance. The results you see reflect continued steady and predictable operational performance and strong project execution from our E&C teams. The results reflect very little direct commodity exposure. In fact, our first quarter 2019 gross margin reflects 98% fee-based versus only 2% of direct commodity margin.
These contracted fee-based revenues are not dependent on basis differentials or commodity buy-sell transactions, allowing for continued predictability and durability in our cash flow streams. Taking it from the top here, cash flow from operations increased 12%, demonstrating significant free cash flow in the quarter when compared with the 46% reduction in the capital expenditures you see at the bottom of the slide. I'll have much more to say about the adjusted EBITDA performance on the next couple of slides, but you can see here that it increased 7% year-over-year without adjusting for asset sales. You can see really nice improvement of 16% for our adjusted EPS. On DCF, we were up about 8%, and we've also introduced DCF per share on this summary, which grew about 7% versus last year.
Lastly, our very strong 1.7 times dividend coverage also increased versus the prior year. Really nice improvement on our various earnings and cash flow metrics despite the impact of some significant asset sales. Let's turn to slide three and review where we finished the quarter on our leverage metrics. The leverage story at the quarter end requires some unpacking since we have significant asset sale proceeds coming in post the quarter's end. Starting on the left-hand side of the table, if you start with the debt to adjusted EBITDA directly from the March 31, 2019 financial statements, you get to a value of 4.92 times.
However, that metric includes about $727 million for the purchase of the remaining 38% interest in UEOM, which we funded partially with our revolver right at the end of Q1, but will be refunded with proceeds reserved at the closing of the UEO-M OVM JV that we've done with CPPIB. A lot of letters there. If you adjust out that $727 million in cash we plan to receive at the closing of the JV, the leverage metric falls to 4.77. Furthermore, if you account for the approximately $600 million in additional proceeds we will receive from CPPIB at the closing of the JV, along with the $485 million we have now received from Crestwood for the Jackalope gas gathering transaction, the leverage metric falls to just over 4.5. I'll discuss the strategic transactions and leverage goals in more detail later.
Let's move on to slide four to discuss the main business drivers for our year-over-year adjusted EBITDA growth. On a year-over-year basis, adjusted EBITDA increased just over 7%, or 11% if you adjust for asset sales. On this slide, you can see a $37 million comparability adjustment driven by asset sales, including the adjusted EBITDA from the sale of Four Corners assets, the Gulf Coast Purity pipeline, and the Brazos JV accounting changes. Moving over to look at the financial performance of the continuing business. Atlantic Gulf led the increase with an over 20% increase in adjusted EBITDA, driven by top-line revenue growth from new expansion projects, including Atlantic Sunrise and Gulf Connector. Really very impressive growth from Atlantic Gulf, driven primarily by continued projects that have been going into service on a regular basis on Transco.
Next up, looking at the Northeast G&P area, we also see just over a 20% increase in year-over-year adjusted EBITDA. This was driven by 15% higher gathering volumes and higher gathering fees associated with expansion projects. Volume increases were led by the Susquehanna supply hub area, which grew about 25%, but we also saw double-digit growth rates in the Marcellus South and Utica, and high single-digit growth in the Bradford and OBM areas. Overall, a very nice start to the year for the Northeast G&P. Finally, we have the West, which is showing about a 7% decrease in year-over-year adjusted EBITDA after adjusting for its share of the asset sales described earlier.
That decline is primarily driven by lower NGL margins due to a temporary surge in natural gas prices at Opal and the effects of severe winter weather affecting one of our key customers' production in the Wamsutter, Wyoming field. Importantly, our operations team in the area was able to keep our facilities ready and available, but upstream production freezing off was the culprit in the area. Next, let's look at the sequential adjusted EBITDA growth, where we saw about a 2% increase since last quarter. A modest increase in EBITDA for the first quarter of 2019 versus the fourth quarter of 2018. You can see here on slide five. Of course, important to note that there were two fewer days in the quarter, which by itself is about $26 million or 2% of an impact.
Atlantic-Gulf was up about $30 million over fourth quarter, driven by lower O&M costs, and Transco revenues were higher related to Gulf Connector, but lower due to Gulfstar One volumes caused by well maintenance. Northeast G&P was pretty flat to fourth quarter, where increased revenue and lower O&M expenses were offset by lower wet Utica gathering and JV EBITDA from Aux Sable for our interest in Aux Sable and Blue Racer Midstream. Recall that Aux Sable was a non-op interest in a processing complex in Illinois. As we've discussed in the past, the Northeast EBITDA growth in 2019 is more weighted toward the second half of 2019, and we'll be covering the outlook for the Northeast in more detail in a moment. Finally, the West was pretty stable compared to 4Q of 2018.
Revenues and O&M were relatively flat sequentially, and per-unit NGL margins were quite a bit weaker. However, on a sequential basis, those lower per-unit NGL margins were more than offset by the favorable change we had in our NGL line fill valuation margins. As you may recall, our fourth quarter 2018 marketing margins were unfavorably impacted by these same losses in marketing inventory. As prices move up and down, the line fill valuation is something that swings up and down. Lastly, in the West, although we did see some nice sequential double-digit growth in Haynesville, overall volumes were flat due to the severe weather in the first quarter of 2019, again from the Wamsutter volumes, which were down in 1Q from weather, as mentioned earlier.
Generally, we had some nice growth in the Haynesville, but it was pretty well offset by the Wamsutter volume decline from the freeze-offs there. In summary, 1Q adjusted EBITDA was within 1% of our business plan overall. As we've said before, we see the overall 2019 growth to be weighted more towards the second half of the year, due primarily to the shape of the Northeast EBITDA growth. Let's move to slide six, where we'll spend the remainder of the prepared remarks focused on our views around some of the topics we most frequently discuss with our investors. The first item we'll be discussing is our financial guidance update. A lot has changed since we originally issued our 2019 guidance about a year ago.
From a macro perspective, we've seen our producer customers pressured to pull back on capital investment, and we've seen a significant downward shift in NGL margins. We've also had five important portfolio optimization transactions, including the Four Corners and DJ Basin transaction, the Brazos JV transaction, the sale of our Gulf Coast Olefins business, our Northeast JV that we've mentioned, and most recently, the sale of our Niobrara business. Lots of moving parts since we had laid out our guidance this time last year. I'm pleased to confirm that despite these unforecasted changes, we are maintaining our guidance ranges for adjusted EBITDA, DCF, and dividend coverage ratio. We're actually raising our guidance for adjusted EPS to $0.95 at the midpoint, due primarily to some lower depreciation expenses caused by last year's Barnett impairment and lower expected interest expense thanks to deleveraging efforts.
If you look in the appendix at slide 13, you can also see that we've added a DCF per share metric and provided a bridge between DCF per share and EPS. We've had lots of discussions with investors about the very significant non-cash charges that impact our EPS, so we've given more visibility into those elements. On the growth capital expenditures front, we've seen quite a bit of changes since last year associated with deleveraging efforts and new projects like the Bluestem Pipeline. As we'll discuss further in a moment, we are targeting a lowering of our CapEx in the Northeast G&P business to respond to the producer activity in the region. Our teams are doing a really nice job of making sure that we bring that capital in just in time and don't get anything out in front of the drilling operations.
Really nice work by our teams there that are constantly operating a very agile mode up there. When you net all of these changes, we're revising our consolidated growth CapEx guidance to a new midpoint of $2.4 billion, down from the $2.8 billion midpoint that was provided with our fourth quarter earnings release. When you factor in the new Northeast JV, our total contributions from JV partners this year take off another $120 million in addition to that $400 million reduction in the stated growth capital. When you consider the proceeds we received from the Northeast JV and Niobrara transactions, along with our excess cash after dividend, we expect to fund our 2019 capital expenditure needs with operating cash flows and proceeds from these transactions.
The effects of our portfolio optimization transactions, along with our lower capital expenditure forecast, has had a favorable effect on our 2019 year-end book debt to adjusted EBITDA, which we now expect to be under 4.6 times. Looking beyond 2019, we are still expecting 5%-7% annual adjusted EBITDA growth over the long term. Let's move on to the next topic, which is an update on the Northeast growth. As you'll probably recall at our third quarter earnings call, we introduced forecasted 15% CAGR for the Northeast area gathering volumes growth for 2018 through 2021. Since then, we've continued to work with our producer customers through two more forecasting cycles. Since last fall, delays in outages on Mariner East and delays on major gas takeaway pipelines like MVP have dampened the realized price expectations for producers in the area on a forecasted basis.
Despite this price decline, I am pleased to say that we are still expecting to see a 15% growth rate again this year on gathered volumes and a slightly higher EBITDA growth rate for the Northeast in 2019. Most of this is on the backs of great performers like Cabot and Southwestern, but increasingly we will see the impact of additional investments by Encino on their new Utica acreage. With the recent weakening of forecasted commodity prices, a few of our producer customers have focused on tuning their drilling CapEx directly to their free cash flows. Therefore producer forecasts at this point for 2020 and 2021 are very sensitive to forecasted pricing. I think very important to note there, that a lot of the planning is done around forecasted pricing. As prices change, we see producers shifting that, obviously.
Right now, I would say with the depression we've seen in local NGL prices in the area, that has pulled some of the capital out of some of the wet Marcellus areas. That is embedded in the forecast. We think it is wise and good for long-term sustainability for our producer customers to take this agile and measured approach, and we applaud the capital discipline. Over the long term, we believe that demand growth ultimately will drive producer volumes. Demand from converted power generation, LNG exports, and new industrial loads is continuing to grow after several years of heavy capital investment and construction. Now we are seeing a second wave as the Permian gas supplies have further convinced the world that the U.S. has sustainable low gas supplies for decades to come.
As a result, we don't believe that the current downturn in pricing is sustainable given the continuous growth in natural gas demand, coupled with the discipline we have seen from the producer community. While Permian supplies are a needed resource to help fill the demand, we still have two-thirds of our gas supplies here in the U.S. being generated by gas-only directed drilling that will have to have a price signal and has become evident that we simply can't get the infrastructure built fast enough out of the Permian to keep up with the demand that continues to grow. While those fundamentals continue to support our steady and sustainable long-term growth, we do want to be transparent about the producers' forecasts as they relate to our near-term gathering volumes and growth rates.
Using the current detailed forecast from our producers, our gathering volume CAGR is expected to be a very impressive 10%-15% growth through 2021, and while our EBITDA CAGR would still come out at or above 15% through the same period. Also on this front, I'm pleased to say that our capital programs are closely aligned with our producers, allowing us to reduce growth CapEx to more efficiently place capital against the same amount of producible reserves. We're encouraged to see the level of EBITDA growth of our Northeast G&P business can continue to generate even with reduced capital being applied, and this combined with synergies from our new JV will allow us to place capital more efficiently than ever in this important basin. Next up, let's get an update on our deleveraging efforts.
We've had excellent execution this year on our portfolio optimization efforts with Northeast JV transaction with CPPIB accomplished multiple benefits for the company. Consolidating the UEO M and the OBM systems while freeing up immediate cash for deleveraging and aligning us with a long-term strategic partner who also owns and controls one of the most important customers in the area, Encino. Encino has attracted some very experienced and capable personnel, and we are excited to be forming another key mutually beneficial relationship in the region, much like we have with Cabot and Southwestern today.
The Niobrara transaction allowed us to accelerate deleveraging by exiting an area that wasn't strategically connected to the rest of our business network, and this transaction was priced at the same strong mid-teens multiples we've realized in other portfolio optimization transactions. No changes to our long-term leverage target of 4.2, which we target to hit by the end of 2021, while maintaining the 5%-7% annual growth targets over this period. Let's move on to slide seven and start with an update on the Transco rate case. As we previously discussed, we filed for an annual rate increase in our August 2018 filing, and those new higher rates went into effect on March 1. We're currently receiving the higher cash payments from our customers subject to refund, but you won't see that reflected in our results as we're reserving the increase pending ongoing settlement negotiations.
On the settlement progress front, we've had two conferences recently, and we'll have another in May. The negotiations are confidential as long as we remain in the settlement process, so I can't share where we stand with the counterparties at this time. I can tell you that the settlement negotiations are likely to continue for many months and could extend into next year. We are hopeful that a settlement can ultimately be reached without the need for litigation, and that the settlement would include the $1.2 billion emissions reduction investment opportunity. We continue to present any upside from the rate case-- sorry, continue to not have any of that upside built from the rate case reflected in our financial guidance. Let's also touch on the status of Transco's major growth projects here.
Lots of news out there these days and questions regarding the effect that the recent presidential executive order might have for our projects. Williams supports efforts to foster coordination, predictability, and transparency in the federal environmental reviews and the permitting process for energy infrastructure projects. Along those lines, we were actually very impressed with the level of detail that appeared in the executive order on complex issues like the EPA's water quality certification requirements, and we are appreciative of the administration's efforts and in strong support of a sustainable approach to ensuring consistent application of EPA's regulations. We know that any major shifts in policies coming out of the executive order will likely be challenged by opponents of infrastructure and fossil fuels, no matter how clean.
We deal with these permitting challenges on a daily basis, our project development teams consistently do a great job of navigating those. Beyond presidential orders, we continue to advance our key New York and New Jersey projects, like the Northeast Supply Enhancement project, the Rivervale South to Market expansion, and our Gateway expansion by demonstrating their critical importance to the markets they serve and the quality of our execution track record, as was most recently demonstrated by our teams on Atlantic Sunrise. Transco's large-scale existing right-of-way and vast interconnection network are really the best way to bring clean, safe, affordable, and reliable natural gas to these Northeast population centers that allow these regions to continue to lower their greenhouse gas emissions. To that end, we continue to progress on the 20-plus Transco projects we currently have in development, including the most recently announced Regional Energy Access project.
The binding open season for Regional Energy Access was extended from April eighth to May eighth to give shippers additional time to get the approvals they needed, not for just indication of interest, but for binding commitments. We have been impressed with the interest the project has garnered. We are targeting a Final Investment Decision in the third quarter of this year, with pre-filing to follow. Next up, I'll touch on our growth in the DJ Basin area. Since February, there have been ongoing developments in Colorado as the new executive and legislative leadership of the state took action to address oil and gas development laws. Ultimately, the new legislation seems to be a much more balanced approach than what we saw last fall with the failed Proposition 112.
With the vast majority of oil and gas activity occurring in the industry-friendly Weld County area, we welcome the shift in authority to local counties and municipalities, we will continue to monitor as regulations are developed. In fact, our teams are working hard right now to keep up with the growth supported by a long backlog of currently permitted wells. Here in early April, we started up our new 200 million cubic feet a day Fort Lupton 3 cryo. The train is running very reliably, great job by the teams getting that started up safely. Construction is progressing very nicely on our Keenesburg number 1 cryo that should be online in the third quarter of this year. In February, we signed another new package of gas along with NGL marketing rights right in that same area where we're continuing to develop infrastructure.
Really very pleased right now with the strong demand for reliable and gathering processing services in the area, and we look forward to continued growth and support for our NGL marketing businesses, including the Bluestem Pipeline project and associated upgrades at Conway. Next on to deepwater. Last but not least, we have seen a steady increase in activity in the deepwater Gulf of Mexico, where substantial new discoveries are being made in close proximity to our assets. This is an area where our existing assets and acreage dedications give us tremendous competitive advantages, and we are thrilled to see the dramatic rebound of activity that is focused on keeping costs and cycle times low by utilizing existing infrastructure like ours.
This year, we'll see EBITDA contributions from our Norphlet project, including those from the purchase of the Norphlet pipeline and additions to our Mobile Bay processing complex that we did last year, and that is going to get paid for. Actually, our Norphlet pipeline purchase gets paid for once first oil begins later this year, and we have line of sight to existing new potential business with likely FIDs in 2020 on several major projects that would lead to large incremental free cash flows on our existing asset base in 2022 and beyond. As I promised on the introductory side, we try to keep things brief today, but we're pleased to be able to update you on the solid first quarter performance and great transactional progress that is accelerating our natural rate of de-leveraging. With that, let's continue the discussion in our Q&A session.
Thank you. Ladies and gentlemen, if you wish to ask a question at this time, please signal by pressing star 1 on your telephone keypad. Please ensure the mute function on your telephone is switched off to allow your signal to reach our equipment. Again, please press star 1 to ask a question. We will now take our first question from Jeremy Tonet of J.P. Morgan. Please go ahead.
Hi, good morning. I wanted to start off with the Northeast G&P and was wondering if maybe you could provide a little bit more detail with the volume growth that you're talking about. Maybe some thoughts on the cadence there, how you see that kind of progressing over the next several years based on producer conversations and also kind of CapEx specific to this area. Has that lightened up at all?
Jeremy, thank you. Good morning. In terms of cadence, I would just say right now we've got a lot of activity, a lot of wells being, and pads being turned into line right now as we speak, actually here in the last month. A lot happening out there right now all over the place, both in the Northeast and the Southwest. A lot going on on that. I would say in the Utica area, the Encino team there has just now taken over operations of that area in transition from Chesapeake, and we are really working closely with them to have kind of the same kind of integrated approach to development and growth development that we have with both Cabot and Southwestern. Really excited about the team they've pulled together there at Encino and our ability to work with them.
In terms of kind of the cadence there, I would just say, certainly, Cabot continuing to lead the way with development with 20% kind of growth. I would say the Northeast PA continues. They've continued to invest with or support our expansions of further expansion on our gathering systems out there. Of course, we're very interested in additional takeaway capacity out of the area given the big reserves and the low-cost reserves they have in the area. I would say in the Northeast, there really hasn't been anything other than just continued steady performance by Cabot, and we're starting to see that kind of spread into some of the other areas as well, like in the Bradford area. Northeast, though, I think is very predictable and steady.
The areas that have more, I would say, volatility in terms of ups and downs and perhaps being a little more reactive to prices is in the wet gas areas, like I mentioned earlier, both the Marcellus wet and the Utica wet. A lot of that, I would tell you, is driven by pretty sharp realized price decline on NGLs that were associated with the Mariner East up and downs. Of course, now hoping for expanded capacity out of there on Mariner East 2. I would say that the pricing forecast on NGL has been difficult to predict. Of course, the gas takeaway situation, particularly with MVP, has been pushed back a little bit as well. I think those things will resolve themselves as we get in. Obviously, as we get into 2020, I think those things will resolve themselves.
We are seeing those producers be very responsive. I would say very strict about living within their cash flows and their forecasted cash flows. Of course, that requires them to forecast prices. I think that's what we can look to in terms of signals there. Our build-out, though, continues to be pretty robust for both the Southwest PA and the Utica area. A lot of new capital, but we're finding ways to really trim that back and have that capital come on just in time as the production comes on. That's what you see reflected in some of our capital pull back and reduction in capital that you see here in our guidance.
That's helpful. Thanks for that. Turning to UEO, OVM, the combination there. I was wondering if you might be able to provide a little bit more detail as far as some of the synergies you see bringing those two assets together as far as capital efficiency improvements.
Great question. Really on two fronts. First of all, very simple front there is on the liquids front. We have the Moundsville fractionator sitting there that has been running right up against its maximum capacity, and we had some investment that was going to be required there to continue to operate that facility and to expand it. Now we're going to enjoy being able to put those liquids through our new pipeline that we're building over to the Harrison fractionator. We'll be taking those liquids over to the excess capacity, big excess capacity that exists at the Kensington fractionator. They were sitting there, a lot of latent capacity on the fractionation side and better markets there at the Kensington area.
Effectively allows us to shift our focus of growth for fractionation and reduce any investment required at Moundsville, and completely take that capital out of our capital plans. That's the simple side. On the more complex side, we also are looking at ways to take advantage of the excess processing capacity that UEOM enjoys. We're starting to run up on capacity constraints there at OVM, and if growth continues there, we'll be looking for ways to move volumes over to UEO as well. Those are kind of some of the obvious issues. Obviously, there's management consolidation and overhead consolidation that's beneficial to us. A lot of it really just relates to being able to take capital out of our plan that would've otherwise been in there.
That's really helpful. Thanks. Last one, if I could. It seems like NESI could really lower CO2 emissions by displacing dirtier fuels. Just wondering how that messaging is resonating in the communities that you're looking to operate in there. When do you see kind of the path forward at this point as far as permits and when construction could start there?
Good morning, this is Micheal Dunn. I'll take that. We absolutely think that NESI is a key piece of the puzzle in the New York City and New Jersey metroplex to reduce emissions, especially CO2 emissions. It's very dramatic in regard to the emissions profile of the fuel oil that's currently being used and converted to natural gas up there. We're going to be a key part of that continuing opportunity to convert if NESI gets approved, and we think it will and gets built. The permitting process is currently in the late stages here. We expect to receive a FERC certificate for that project any day now. The 401 certification deadline in New York is mid-May, then the 401 certification deadline in New Jersey is mid-June. We would expect several of those permits to come to the forefront here in rapid fashion.
That's very helpful. Thanks for taking my question.
Thanks, Jeremy.
We will now take our next question from Shneur Gershuni of UBS. Please go ahead.
Hi. Good morning, guys. Just sort of to follow up on the Northeast questions a little bit. First and foremost, does the consolidation of UEO into Williams, or the UEO transaction rather, does that sort of change your weighted average growth rate kind of beyond 2019? When you talked about being able to take down CapEx, which you've done materially for this year, does this CapEx efficiency benefit roll into 2020 and beyond?
Yeah. Great question, Shneur. First of all, on the gathering volume piece, it really doesn't change that because remember, we're already operating the gathering systems that feed in to UEO, so those gathering volumes would've already been in there, so there's really not any change on that. UEO is primarily just the fractionation and processing facilities downstream of that. That's really no change from that. On the question about capital savings going forward, I would say a big chunk of the capital savings and the synergies are actually now forward-looking, as we take advantage of being able to balance between the two processing complexes, and the liquid. Actually, a lot of the capital is even more looking forward. A lot of the gathering capital really won't change that much.
If you think about that, it's really on the processing and fractionation capital that we'll be able to shift volumes into areas that we could not have to put expansions into like we would have to otherwise.
Hey, Garrett. No, great color. Just another follow-up, kind of a bigger picture question. You sort of talked about in your prepared remarks about a longer-term growth rate of 5% to 7% for EBITDA. Can you talk about what kind of capital program would be needed to support that type of long-term growth rate, and could we assume it would be funded at least 50% from internally generated cash flows?
Yes, I'll maybe have John Chandler take that in terms of where we would go with that. Yeah, as we've said, the $2.5 billion to $3 billion, assuming a little more moderated returns than we've been enjoying, generates that 5%-7% growth rate. So obviously, as we can high grade our investments, that improves, and bring in synergies like we're doing on these JVs. Generally, that $2.5 billion to $3 billion is what we think it takes to grow that 5%-7%. I'll let John talk about the funding there.
I think that's fair. As we look forward in our projections today, using this $2.5 billion, let's use that as the number, type expansion capital. As we look to our forecast, we're able to fund that completely and entirely through excess cash flow and obviously some new leverage in the future. With the growth of our EBITDA, we're able to maintain and continue to lower our leverage ratio going forward and fund that capital that supports that kind of EBITDA growth.
If effectively, once you hit your leverage targets, would there then be room to consider share repurchases as well also?
We'd have to talk about that once we get there. There's still work to do. Obviously, Eric, under 4.6-4.2, there's still quite a bit of work for us to do. I think we've got time to talk about that. Certainly when we get to the point where our leverage targets are where they need to be, we will be generating a significant amount of excess cash flow.
Yes, Shneur, I would just say on that front, we'll see what the markets look like when we get to that point. It's kind of hard to answer that because we're speculating on what the returns would be on that investment versus our other investments. I can tell you we're constantly allocating our capital return projects that a lot of the industry would accept. So I think there'll be a balance there between increased capital investment opportunity is another thing we can do with that capital. As I said, we're constantly allocating away projects today as we continue to press on de-leveraging the business.
Okay. One last question, if I may. Your excitement level about the Gulf of Mexico seems to be increasing. You sort of touched on it in your prepared remarks. I was wondering if you can sort of expand on the opportunities that you see there and how we should be thinking about it on a go-forward basis.
Yeah, I would just say, the opportunities are getting to be so plentiful that it's kind of getting hard to keep track of, honestly. Some of the very certain opportunities exist around the Western Gulf or operations around the Perdido area. Obviously, the Whale prospect out there is going to be a big mover for us. Shell just announced a little bit earlier this month, or sorry, in April, the Blacktip discovery, which is also another very large discovery in that Perdido belt area. To the south of that, of course, the Mexico Perdido is even a much larger kind of order of magnitude opportunity that we're extremely well-positioned for. On the Western Gulf, it's going to be a matter of maximizing our return on the investment. There is plenty of production to fill up our existing capacity and then some more.
Really important opportunity for us out there, and we're just extremely well-positioned, both contractually and with the infrastructure that we have in place out there today. If you move over to the Eastern Gulf, of course, really excited about the Ballymore prospect that will likely get produced across the Chevron Blind Faith platform. That's also a very large find there. Again, just big, free incremental cash flows coming our way with very little to no capital on our part. We're excited about that. The Norphlet prospect, while we kind of thought that was almost singular as an investment originally, and we like the returns just singularly across that one field, we've seen a lot of new development out there around not just by Shell, but also by Chevron now in that area. Lots going on in the Central Gulf.
Lots of new opportunities. The LLOG Repsol JV will bring some promise to us in the area, and a lot of new development going on there as well. I'm not even getting into the multitude of smaller projects that are coming our way. A lot of the reason that I think we're so fortunate is that in the past, what we saw was producers really looking to add big reserves. When oil was $80-$90, or as they were enjoying prior to 2014, there wasn't so much focus on the use of existing infrastructure to keep costs down. Now with these lower prices, we're seeing a huge focus on utilizing existing infrastructure, and therefore that means we're not having to build a bunch of new capital. It's just development in and around our existing assets.
That is really good for us and really good for the industry as a whole. I would say if I was going to describe one big change from the last time we saw the deepwater take off, that is really it, that there's this intense focus on the utilization of existing infrastructure. Of course that when you already have a lot of the big gas infrastructure in the deepwater, that bodes very well for you.
Hey, Alan, if I could add to that on the Norphlet opportunity. That was a great negotiation for us to have with Shell there, where we acquired the pipeline that they built. It was pre-negotiated with a return, and we're obligated, obviously, to move their gas to shore to our Mobile Bay facilities, where we have a % of liquids contract with them to process that gas. The strategic value there, additionally to us, is the fact that that pipeline won't be full, and from day one, we can go out and acquire other business to bring through to have a 50 tieback into that Norphlet pipeline that we'll purchase upon first gas movement there. A great opportunity for us to take advantage of that facility that has already been built.
The construction risk is taken away as well as the timing risk has been taken away because we don't pay for it until the gas flows.
All right, perfect. Really appreciate the color, guys.
Thank you.
We will now take our next question from Christine Cho of Barclays. Please go ahead.
Good morning, everyone. You guys have talked about wanting to consolidate Northeast for some time, obviously the UEO transaction took you in that direction. How should we think about the potential for Blue Racer to be included under that umbrella?
Great question, Christine, as always. I would just say, a lot of value in that combination. We're working through some various transactions to try to extract some of that other than through direct control of the asset. Certainly a lot of opportunity there, I would just say we haven't been able to get there from a price standpoint. We haven't been able to get to what we thought made sense for us on that. I would say lots of opportunity, but we remain patient, and will remain patient with making those combinations. I do see some opportunity just contractually to continue to find ways to utilize common facilities out there. I think that's a step in the middle if we can't reach agreement on a broader transaction.
Okay. You guys are tracking to get to your targeted leverage faster than planned. Should we think that there are any other non-core assets that you are contemplating selling, or is this sort of it?
Well, I would just say, we continue to see this big spread between what our stock is trading for versus what these assets are selling for. If we can do those kind of transactions in a way that don't dilute our future and stand in the way of us accomplishing our strategies, then we'll continue to look for those. We don't have anything specific on the drawing boards, and I think as we've said before, I think looking to our strategy and looking to how things link in our asset base is not because we have some written rule that says we have to have the downstream business for it to be a core asset.
When it comes to placing capital, new capital, and it's competing in this capital allocation process that we're constantly running, if it doesn't enjoy the downstream benefit and the coupons that flow from the downstream benefit, the incremental returns just don't stand up. Niobrara is actually a perfect example of that. The returns just on the standalone G&P basis there just didn't stand up well within our capital allocation program. We had both partners and customers frustrated with our lack of interest in investing at those return levels. It wasn't for any reason other than it just didn't stack up within our capital allocation process. That's why we're fixated on that, is just because those areas that are in growth tend to drive those higher returns, and therefore make it through our capital allocation process.
I think that's about as much as I can tell you. Do we have our sights on anything particular at this time? The answer is no.
Okay. Great. Thank you.
I would also say, though, there's obviously cheap money looking for opportunity out in the marketplace. Very similar to our Four Corners assets, we get approached by the market all the time on assets. Again, to Alan's point, while we don't have any specific thing targeted, we're constantly being approached.
Great. Thank you.
We will now take our next question from Gabe Moreen of Mizuho.
Hey, good morning, everyone. I just had a quick question on the Transco rate case and some of the associated details around that. It seems like the timeline there has been extended around settlement discussions. Can you just talk a little about the decision to kind of keep going with settlement discussions and I think extend the timeline here fairly considerably? I assume you're pretty confident in terms of your own position there, so why not a move to maybe litigate a little bit earlier than end of 2020? Related to that, the emissions reduction spend at Transco, is that going to be part of the rate case or separated out, and is that something you would spend before the rate case was concluded?
Yeah, I'll take that. This is Micheal. I wouldn't say it's necessarily extended out, per se. It's just a process we have to go through in front of an administrative law judge there in regards to trying to reach settlement. We think it's prudent to continue that process until we reach impasse with our customers, but we're certainly not there yet. We're rapidly working with them to try to come to a settlement that both sides appreciate and like. It certainly doesn't mean we won't be willing to litigate that if we feel like we've reached impasse. Certainly the administrative law judge will assist us in getting there, hopefully quickly, so that we can move on to the litigating path if settlement's not where we ultimately end up. We would love to have a settlement with our customers there.
We think it's the proper way to hopefully achieve a good outcome for both sides. I'm not afraid of the litigation path as well. Specifically on the emissions reduction, so the way we've contemplated that, it would be a separate tracker. As we spend the capital, we would basically change the rate upward to accommodate the compression that's been replaced there. It really just allows us to do that as if we were going through a rate case, so to speak.
Without having to go through a rate case to be able to increase those rates as we deploy that capital to reduce those emissions along the Transco pipeline system. If ultimately we don't get the emissions tracker, that would make it more likely that we would have more rate cases coming to be able to accommodate those emissions reductions projects within our rate.
Great, thank you. Maybe if I could just get more of an update on Bluestem and how discussions are going on that, whether recent Waha prices have been motivating customers a little bit more, and to what extent you're looking at partners there where it may stack up on the returns profile within your capital backlog.
Yeah, this is Chad Zamarin. Thanks for the question. I would just say that we continue to work on projects from the Permian to Transco markets. You've seen recent dislocation in basis from the basin, obviously to the coast. If you look at the forward curves, I think the market has been a little slow to recognize that that might be long-term sustainable. We're going to be really cautious in ensuring that any project that we would proceed with is one that has really solid fundamentals and economics. I think if we were to move forward, it would be with partners. We're not looking to make an investment of that scale out of the basin on our own. Ultimately, I think what's important to us is to continue to build Transco's market connectivity, both on the supply and on the demand side.
We believe those volumes ultimately want to get to the best markets, we think Transco offers those very best markets. Again, we continue to explore participating in a project from the Permian to the Gulf Coast. We have volumes with our partnership with Brazos Midstream that we can leverage for the purpose of benefiting and improving a project. Again, I think the economics that we've looked at least to date on the projects that have gone forward and that are being contemplated, haven't yet met our expectations alongside the inventory of opportunities that we have. We'll continue to work it. Again, I think the most important thing for us will be that we make sure that Permian Gas has a good home to come to along our Transco markets.
Thank you.
We will now take our next question from Colton Bean of Tudor, Pickering, Holt & Co.. Please go ahead.
Morning. It's actually just to follow up on the Bluestem discussion there. Have you seen any shift in producer willingness to flare, given the extreme focus on ESG for the upstream community over the last couple of months?
Yeah. I think we continue to see quite a bit of flaring, but I do think the producers are interested in getting gas to market. I think they're looking forward to relief coming later in the year when the first long-haul pipe project comes online. We've seen significant volumes shut in the Alpine High area, and we have seen, I think, restrictions associated with gas prices in Waha. I think we get a lot of questions around with as large as the basis is why we haven't seen a stronger move towards an additional project. I think what we're seeing is it takes, as Alan mentioned in his comments, it takes a lot of time and effort to create infrastructure that can move all the way from West Texas to the markets.
I think we'll continue to see a desire to reduce flaring, but the options today are either shutting in or waiting for infrastructure to be built, which takes some time. We think another project needs to get built. Again, if you look at the forward curves for basis, Waha to Henry Hub right now, those prices don't support an investment in a long-haul pipeline. Until we see producers and end market users willing to step up for longer terms and better economics, I think we'll continue to see challenges in the basin.
Got it. Just circling back to the Q1 results here. On the downtick in Atlantic Gulf operating expense, is that a function of timing on the maintenance spend, or is there something more structural in nature to point to?
This is Micheal. It's not really. It's more of we had some one-off issues last year that, specifically in our unregulated business with turbine overhauls and things of that nature, that contributed to that higher expense in the comparable quarter in 2018. It's not really a structural issue, it's just a timing issue of activity.
Got it. 2018 was probably an elevated level, and this is maybe a better look at the go-forward rate.
I'm not going to be a predictor of go-forward rates with the exception of saying that it's lumpy because of timing and specifically turbine overhauls. They're pretty expensive. A couple million dollars to do one turbine overhaul, and those have to be done at certain intervals of runtime hours. We have to accomplish those when we hit those runtime hours. It's highly dependent upon the runtime of the equipment, for example, when we have to do those, and if we have emerging problems we have to go and take care of. I would also say in the 2018 quarter, we also did a lot of work on our reciprocating compression on the Transco system that had to be accomplished as well. It's just a timing of overhaul aspect, and it's highly dependent upon runtime.
Understood. Just a quick final clarification here. For the $400 million reduction of the capital program, I think you all had noted previously that around $90 million was associated with Jackalope. Is the balance of the entirety there solely attributable to the Northeast? As you think about the Northeast, Alan, I think you mentioned a just-in-time element for some of the reductions. Does that imply that any of this has shifted to 2020, or should we think about it more in terms of the processing discussion that you outlined?
Great question, Colton. First of all, it is a combination, on the last part of your question, it is a combination of stuff getting pushed out as well as ability to not have to, for instance, continue to expand at Oak Grove and Moundsville. Yeah, it's getting pushed into 2020, but you'll see some of the benefit of the synergies show up in 2020 that would offset that, if that makes sense to you. Finally, on your question of the 90, the Jackalope 400 elsewhere. I'd just say a lot of moving parts. Of course, we added a little bit of cost in there for getting on with the fractionation at Bellevue as well as Bluestem, who's going in there.
Some capital coming out of the Northeast and some lower capital for the year, just as these projects, we always have a lot of contingency built into these projects. As those push out and get closer, you saw we advanced one of our Transco projects into 2020. We're actually seeing really good performance on that front. For the most part, it is coming out of the Northeast, but not all.
Yeah. That's very helpful. Thank you.
We will now take our next question from T.J. Schultz of RBC Capital Markets. Please go ahead.
Hey, good morning. On the executive order you guys highlighted, what's your expectation from the DOE as it works to submit reports just on timing to get more clarity around that, and any input you all are having on that process?
Well, I would say on the presidential executive order, first of all, we were really impressed with the work that was done by the various attorneys, staff attorneys around the EPA. I think everybody recognized that some of the so-called guidelines, and I'll use quotes around that term, guidelines, had been put in place during the Obama administration that had become treated almost like rules by the state. In fact, there never really had been a regulatory process to establish that. I think that appropriately, the EPA administrators, regardless of which party affiliation you're interested in, I think they thought that that was not proper administration and regulation, and so they're trying to bring clarity to that. We haven't been asking for easier regulation.
We've been asking for clear and consistent regulation. That's exactly what we thought the order tried to address without overreaching towards any one particular project. It's something that needed to be cleaned up. If you really dig into that, it's actually a very astute and detailed approach to it that we really applaud. I think it's exactly a big step in the right direction. It's obvious to us there was great experts involved in that. While I don't see it being a miracle cure for any one of our particular projects that we have out there right now, I do see it as a big step in the right direction for bringing clarity and consistency between how the states and the feds deal with Clean Water Act regs within the EPA. Anyway, pretty impressed, frankly, with the sophistication of that order.
Okay. Makes sense. Just one more. You've mentioned Mountain Valley a couple times. Maybe ignoring timing on in-service. They've built a lot of that project. Assuming they get to Station 165, you've talked about synergies. Has that moved into commercializing anything at this point? Does it have to wait on firmer in-service? Just any color on the benefits there to you all. Thanks.
Sorry. Just to clarify, you were talking Mountain Valley Pipeline, is that correct?
Yep, sorry about that. Mountain Valley Pipeline.
Okay. Yeah. Thank you. This is Micheal. Just seeing what the Mountain Valley Pipeline backers have said about their project. Obviously, they feel certainty in regard to completing their project, we're obviously watching that very closely along with them. It ultimately will hit Station 165 area, there very likely should be takeaway opportunities for us from that point on the Transco system once that project gets closer to some certainty there. We're certainly looking at that and willing to take on any customer-related project that would like to move that gas away from Station 165, we certainly think there's opportunities to do that.
We will now take our next question from Jean Ann Salisbury of Bernstein. Please go ahead.
Hey, good morning. It looks like latest flows into Transco from the Northeast Marcellus are around four and a half BCFD, including Atlantic Sunrise. Is that effectively the max capacity for Transco there? Is there any way that you could take more gas and get paid for it with just compression or anything like that?
I would say, just to remind everybody on that, Transco's capacity is fully sold, it's consistently sold out. I think, Jean Ann, you have a full of that.
Yeah.
Really what we're talking about is just interrupt, just loads and how much we can physically flow during a period. That's very dependent on local loads, where the gas is needing to be delivered to. There's a lot of variables that go into play there. I would say generally, we are constantly maximizing the capacity out of that basin right now because the margins support that. A lot of that is managed by the shippers. In other words, they're the ones dictating where they want to move gas to and from. A lot of that is dictated by them. I would say every day, we're optimizing as much as we can move out of that area, so.
Okay, that's helpful.
Those assets are staying full. Like Atlantic Sunrise has virtually been full almost since day one. That does bode well for the future opportunities to move additional expansion volumes out of there.
Yeah
With new projects.
Yeah.
Jean Ann, Regional Energy Access, though, takes advantage of a lot of existing infrastructure, as does the Leidy South project that we're working on for National Fuel Gas and for Cabot. There is obviously some pretty easy expansions out of the area, relatively, to the project teams that are working on.
Sure.
Relatively, we've got a lot of compression we can do and a little bit of looping to do to add capacity out of that area.
That's really helpful. Thank you. Do you still have any spare capacity in gathering in the Haynesville and perhaps in the Eagle Ford, or is your system pretty much maxed out there?
I'd say in the Haynesville, we bump up against the top end there quite often as the well pads come on. We get to max capacity there last year and continue to define new volumes coming in there that put us right at max capacity. We're pretty maxed out at Haynesville from time to time, and it's highly dependent upon when the pads come on and then the steep decline on those wells. The Eagle Ford, we continue to have new well connect opportunities there as well. We continue to expand our systems there as needed for the producer customers out there. Most of that requires additional compression when we bring that online and some new well connect capital as well, and possibly some looping. It's highly dependent upon where the producers are drilling their pads.
Yeah. A system like the Haynesville, that system actually has a south and a north component to it. While you might see one part of the system get loaded up, the southern part maybe more than the north sometimes, or vice versa. That really dictates. It's not like it's a processing plant where you just have a fixed amount of capacity through the plant. The system capacity is very dependent on where the gas shows up. Our teams have done a really nice job out there working with other midstream operators in the area to use up the capacity to be able to cross haul between the systems and to continue to do that.
On the Eagle Ford, we would remind you that that is a cost of service agreement, as we add capital there, that gets covered in our rates, where the Haynesville is not that set up.
Perfect. That's all for me. Thank you.
We will now take our next question from Michael Lapides of Goldman Sachs. Please go ahead.
Hey, guys. Thanks for taking my question. I'll be quick. I know there've been a bunch on both MVP and ACP. Hypothetically, if ACP, and let's say even if MVP didn't go through, meaning got stuck in the court system, bogged down for a lot longer, or cost creep inflated to a point making it untenable, how do you think about the solutions that Williams could offer into Virginia, North and maybe in the South Carolina, and the ability, the timeline to realize some of those solutions?
Yeah. Michael, obviously, the topic that's been getting a lot of discussion. We have a lot to offer in terms of distributing the product of gas to market, whether it's helping what would be the ACP eastern system or moving supplies to them. We do have a tremendous amount to offer with our existing right of ways. MVP is more just kind of a downstream issue, so to speak, because obviously they got to cross the trail with those supplies. That's really the struggle there. I would say we have a lot more to offer ACP in terms of meeting their market distribution goals. As for MVP, they're going to need some market distribution if they do get across the trail, and we're well-positioned to help out with that.
That's how I would describe that. Obviously, in this environment, I think it's important for all of the industry participants to try to utilize as much existing facilities as possible, keep the cost down, and that's what we're very focused on in both those cases.
If ACP, for some reason or another, didn't get completed, how much new infrastructure or new steel in the ground, how much significant new pipe would you have to build, especially to get the gas into North Carolina? I'm just trying to think about the infrastructure requirements and the timeline to deliver them.
I would just say we have a lot of routes already into some of those markets, but it is significant in terms of the investment. It's obviously quite a bit lower cost by using the existing facilities. It would be pretty significant investment required, and it's very dependent on where the supply comes from. A lot of variables here depending on where the supply comes from. If you just showed up with the supplies along that 165, the 190 corridor, we have a lot of ability to help distribute that gas into those markets.
Got it. Thank you. Much appreciated.
We will now take our next question from Justin Jenkins of Raymond James. Please go ahead.
Great. Thanks. Just one follow-up from me. Just if you take the 1Q run rate for CapEx, we're a bit below the full-year guide. Is it more balanced throughout the rest of the year here, or is it back-end loaded? Maybe just some help on the cadence of CapEx, if you could.
Yeah, this is Micheal. I would say, Q1, you can't take that really as a run rate because our construction projects really ramp up in second and third quarter of the year with our growth projects that we're working on. I'd say we're still within the ballpark of our guidance suggestions that we put out there with the information that came out this week, and it will ramp up as the summer construction season heats up.
Got it. Thanks, guys.
We will now take our next question from Chris Sighinolfi of Jefferies. Please go ahead, sir.
Hey, everyone. Thanks for the added color this morning. Alan, you guys have been very active since analyst day a year ago with asset sales, JV rationalizations, and clearly a focus on deleveraging. I guess I have two questions that stem from all of that. The first is to follow up on Shneur's earlier question about your longer-term, 5%-7% annual EBITDA growth guidance. Just curious how to interpret your longer-term phrasing. For periods beyond 2019, just wondering maybe how you or John would think about the outlook versus the forecast contained in the WPZ S-4 last summer.
The Williams Partners L.P. Form S-4 last summer, I wouldn't pay much attention to the financial information. We had to do a fair amount of talking through that. That wasn't obviously meant for marketing purposes. As we look at our forecast today, again, back to our earlier point, as we look at our forecast today over the next two or three years, and we look at a capital spend of around $2.5 billion on expansion capital. Again, we continue to see a deleveraging, and at the same time, we see this level of EBITDA growth that runs in the 5%-7% range. I really wouldn't put much weight in the Williams Partners L.P. document.
I would just say, Chris, on that, we are focused on delivering on both of those ends, both on the 5%-7% growth as well as the deleveraging. We're constantly balancing that. Obviously, being able to sell assets that are well at these high multiples is pretty attractive way to get there. We also are very focused on making sure we have plenty of reinvestment opportunity to drive that growth, that 5%-7% growth. So far, I would say, feel very comfortable about our ability to continue to place that capital, projects just continue to develop that are moving along pretty nicely. Within this period, I would tell you that the one sizable project that's developed is the Regional Energy Access project that's come along very nicely and with a lot of strong support all of a sudden.
I think, we're really feeling pretty good about the high return investment opportunities that continue to come. As we get into the 2022 timeframe, this isn't speculative on our part, the deepwater cash flows there are going to be pretty big because the FIDs for those projects are moving ahead, a lot of that business will be coming to us. While that's hard to predict exactly the size of that and exactly how much, those projects are out there and are coming our way. Anyway, feeling very good about the ability to see that kind of growth rate and continued deleveraging, we are managing both of those as we think about transactions.
I mean, obviously, we continue to see. Even though we've softened somewhat maybe our long-term view of growth in the Northeast volumes from 15% CAGR to 10%-15%. Again, we still see robust EBITDA growth coming out of the Northeast.
We've got a number of projects, if you look in our slide deck in our appendix, a number of Transco projects coming on the end of this year, next year, that'll be adding to EBITDA. Of course, it goes without saying, the DJ Basin assets that we have acquired late last year. There's a significant ramp-up in growth coming from that as well.
Okay. One clarification on that, John, just for my own purposes. It's very clear that you've omitted any Transco rate case related impact on the formal 2019 guidance. As we think about 5%-7% over the next couple of years, is it safe to assume that if you get a positive outcome there in that period of time, that's additive to that range, or maybe put you higher up in the range?
It would put us higher up in the range.
Okay. That's very helpful. My second question, very much appreciate the revamp of the presentation materials, something that we've long acknowledged, but just illustrated clearly, I think it's slide 13, is just the significant non-cash items that do present a drag to EPS. I guess I'm just curious, are there additional transactions or impairments or restructurings that you could do to maybe trim some of those items for the benefit of EPS? Just, we get a lot more questions from investors about EPS, I'm assuming you do too, and I'm just wondering what more could be done on that front. Thanks.
That's a weird commentary for a CFO to look for impairments. It is something, obviously, that to the extent we could have that, it would benefit our depreciation by lowering our depreciation, which is way out of line with our maintenance capital. There's really not a lot we can do on that front, absent to the extent we partner on assets that we consolidate today. To the extent we moved assets from a consolidation to a non-consolidation type approach then maybe partnering through JVs. That potentially could allow us to revalue assets and impair, and bring that depreciation level down. Anything short of that, though, the test for impairment is based on gross cash flows.
While a lot of these assets got marked up to really high values back in the Access Midstream merger, which was not a cash deal, it was just a stock-for-stock trade, it forced us to revalue a lot of the Access assets at a very high valuation level. A lot of those are at high levels. The gross cash flows still exceed those book values. Anything short of actually some kind of partnership or JV that would force some level of deconsolidation, that's the only thing that allows really to help bring that depreciation down.
Okay. No, that's helpful. I appreciate it's unorthodox to sort of line a question for you, the focus seems to have totally changed. It seems like the recent deals you've done in Northeast maybe are structured in a way that helps on that as well. Just that was where I was coming from. Appreciate the time.
We will now take our next question from Craig Shere of Tuohy Brothers. Please go ahead.
Good morning. Most of my questions have been answered. I did have a quick one. Alan, you commented on the weak wet gas in the Marcellus and Utica in terms of recent trends and NGL pricing. Looks like Blue Racer had a pretty tough quarter. How do you see all this impacting the pace at which your new West Virginia Panhandle processing might fill up over the next couple of years?
Yeah. I think, Craig, the investment we have there, feel pretty good about that filling up. It is, as I mentioned earlier, we've got a lot of pads being turned online, we're really starting to see that come up. It doesn't take a lot as big as those pads are, to make progress on that front. We have some contracts coming our way. They're shifting volumes our way. Feel pretty good about the TXP-2, the existing base capacity plus TXP-2. We were able, as a result of the synergies and knowing we have excess processing capacity to UEO, that puts us in a position to not have to pre-build any capacity out in front at Oak Grove any further.
The synergy or as I mentioned earlier, one of the nice things about that synergy is it prevents us from having to put capital in place to build out in front of those increasing volumes because we do have alternatives about where we can shift those volumes to, but preserve the cash flows from it. I would just say that gives us a lot more breathing room and allows for better capital efficiency as it relates to the OBM processing capacity. We intend to take full advantage of that.
Sounds good. Your TXP-2 is basically contracted up. The slowdown's not really going to impact it, you're de-risked on the fact that you don't need new capital because you have the ability to work between basins.
Right. Correct.
That's terrific. Thank you.
We will now take our next question from Tim Schneider of [JPMorgan]. Please go ahead.
Hey, good morning, guys. Majority of my stuff's been asked too. Just real quick. From my seat, I'd say the biggest debate point among investors is capital allocation for companies in the midstream space, and I was just kind of wondering how you guys look at this strategically when you get together, kind of balancing growth, de-levering, and returning cash to shareholders over the longer term. I think you said kind of that 4.2 leverage target, but what do you think the right leverage is for a company with the asset mix of Williams? Is that something that should go below 4 times? Are you happy kind of being in the low 4s? Just interested in your thoughts here.
I would just say our asset mix is we have very little business that's marketing-based. It's not basis differential-based. It's not the term optimization that gets used often around the assets as a trading around the assets. We don't have that kind of variability to our cash flows. I think you can see that with the remarkable predictability through our cash flow streams as it continues to flow. No, I don't think they ought to get marked all the same, but I would say that the rating agencies have told us that on their basis, it's a 4 or 5 kind of number to be triple B flat, and we want to be there and be confidently there at that triple B flat level.
That 4.2 mark on kind of a steady run rate basis is what we're seeking that because that happens to be coincidental with that triple B flat from the rating agencies.
Got it. In that sense, I guess if you guys are getting feedback from the investment community, do you really want to see something below 4 times? Is that something that you would aim for in that case? Or do you think, well, let's just kind of go with what the rating agencies are saying?
I would just say from my own personal perspective on that, I think there tend to be fads that move through the investment community. I think from our vantage point, keeping our debt costs down and the capacity to flex when we need to is what we're targeting from a business trajectory. I think we think that's really the smart place for us. I think the market has to figure out, and it should figure out who has volatility in their cash flows and who doesn't. That ought to be driving the number that each company should aspire to, not just because somebody magically came up with a 4 times number.
Yes, sir. Got it. Thank you.
There are no further questions at this time. I would now like to hand the call over to Mr. Alan Armstrong for any additional or closing remarks.
Okay. Well, great. Thanks everybody. Great questions as always. Appreciate the opportunity to visit with you on this. Really excited about the continued, very predictable way our business is running and the way our teams are executing on projects. I look forward to speaking with you in the future and at the next quarterly call. Thanks.
Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.