Williams Companies, Inc. (The)

Good day everyone and welcome to the Williams Company's 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 and thank you for your interest in the Williams Company. Yesterday afternoon we released our earnings press release and the presentation that our CEO, Alan Armstrong, will speak to momentarily. Joining us today is our chief operating officer, Michael Dunn, our CFO, John Chandler, and our senior vice president of corporate strategic development, Chad Cameron. I will also mention that we refined our quarterly earnings materials and our format for this call. We've adopted a clear earnings press release format and we've integrated the previous standalone analyst package into the earnings release document. So 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 and 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 material. And so with that I'll turn it

over to Alan

Armstrong.

Great. Well, thanks John and good morning and thank you for joining us this morning as we discuss our first quarter financial performance in the key investor focus areas of the day. As John said, we took a fresh look at the format and we're going to stay pretty brief and focused in our prepared remarks to allow time for Q&A. So let's move right into the presentation to take a look at our first quarter 2019 results. Here on slide two we provided a clear view of our year over year financial performance and the results you see reflect continued steady and predictable operational performance and strong project execution from our E&C teams. And 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. And these contracts and 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. So taking from the top here, cash flow from operations increased 12%, demonstrating significant pre-cash flow in the quarter compared with the 46% reduction in the capital expenditures you see at the bottom of the slide. I 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. And also you see really nice improvement of 16% for our adjusted EPS. And 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. And then lastly our very strong 1.7 times dividend coverage also increased versus the prior year. So really nice improvement on our various earnings and cash flow metrics despite the impact of some significant asset sales. And now 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 sales proceeds coming in post the quarter's end. So 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 statement, 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 UEOM 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. And then furthermore, if you account for the approximately $600 million of 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. So I'll discuss the strategic transactions and leverage goals in more detail later. But now let's move on to slide four to discuss the main business drivers for our -over-year adjusted EBITDA growth. On a -over-year basis adjusted EBITDA increased just over 7% or 11% if you adjust for asset sales. And so on this slide you can see a 37 million comparability adjustment driven by asset sales, including the adjusted EBITDA from the Cell of Four Corners asset, the Gulf Coast purity pipeline, and the Brazos JV accounting changes. Now moving over to look at the financial performance of the continuing business, Atlantic Golf 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 Golf Connector. Really very impressive growth from Atlantic Golf driven primarily by continued projects that have been going into service on a regular basis on Transco. Next up looking at the Northeast GMP area we also see just over a 20% increase in -over-year adjusted EBITDA. This is driven by 15% higher gathering volume 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 Marcello South and Utica and high single digit growth in the Bradford and OVM areas. So overall a very nice start to the year for the Northeast GMP. And finally we have the West which is showing about a 7% decrease in -over-year adjusted EBITDA after adjusting for its share of the asset sales described earlier. And that decline is primarily driven by lower NGL margins due to a temporary surge in natural gas prices at O'Pow and the effect 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 as 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. Atlanta Golf was up about 30 million over fourth quarter driven by lower O&M costs and transco revenues were higher related to Golf Connector but lower due to Golf Star 1 volumes caused by well maintenance. Northeast GMP was pretty flat the fourth quarter where increased revenue and lower O&M expenses were offset by lower wet Utica gathering and JV EBITDA from OXSable for our interest in OXSable and Blue Racer Midstream. Recall that OXSable was a non-op interest in a processing complex in Illinois and as we discussed in the past the Northeast EBITDA growth in 19 is more weighted towards the second half of 19 and we'll be covering the outlook to the Northeast in more detail in a moment. Finally the WEP was pretty stable compared to 4Q of 2018. Revenues in 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 and as you may recall our fourth quarter 18 marketing margins were unfavorable impacted by the same losses in marketing inventory. So as prices move up and down the line fill valuation is something that swings up and down. Lastly in the West also 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 19 again from the WAM Sutter volumes which were down in 1Q from weather as mentioned earlier. So generally Haynesville we had some nice growth in the Haynesville but it was pretty well offset by the WAM Sutter volume according to the freeze offs there. In summary 1Q adjusted EBITDA was within 1% of our business plan overall and as we've said before we see the overall 2019 growth be weighted more towards the second half of the year due primarily to the shape of the Northeast EBITDA growth. So 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 purity business, our Northeast JV that we've mentioned and most recently the sale of our Niobera business. So lots of moving parts since we had laid out our guidance this time last year but 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 95 cents at the midpoint due primarily to some lower depreciation expenses caused by our last year's Barnett impairment and lower expected interest expense thanks to de-leveraging 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-cast 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 de-leveraging efforts and new projects like the Blue Stem pipeline. And as we'll discuss further in a moment we are targeting a lowering of our capex in the Northeast GMP business to respond to the producer activity in the region. So our teams are doing a really nice job of making sure that we bring that capital on just in time and don't get anything out in front of the drilling operation. So really nice work by our teams here that are constantly operating in a very fragile mode up there. So 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 relief. And 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 state growth capital. And when you consider the proceeds we've received from the Northeast JV and NIDRAER transactions along with our excess cash after dividends 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 to 7% annual adjusted EBITDA growth over the long term. So 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 and since last fall delays in outages on Mariner East and delays on major gap takeaway pipelines like MVP have dampened the realized price expectations for producers in the area on a forecasted basis. So 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 back 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 and 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 and 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 and 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 and 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 giving the continuous growth in natural gas demand coupled with the discipline we have seen from the producer community. And 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 volume and growth rate. Using the current detailed forecast from our producers our gathering volume CAGR is expected to be a very impressive 10 to 15% growth through 2021 and while our EBITDAW 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. So we're encouraged to see the level of EBITDAW growth of our Northeast GMP 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 and ever in this important basin. Next up let's get an update on our new leveraging 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 UEOM and the OVM systems while bringing up immediate cash for leveraging and aligning us with 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're excited to be forming another key mutually beneficial relationship in the region much like we have with CAVETS and Southwest GDED. The NIBRERA transaction allowed us to accelerate the leveraging 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 realized in other portfolio optimization transactions. So 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 to 7% annual growth targets over this period. So let's move on to slide 7 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. So 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 increased 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're 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. And 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. And 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 project. Obviously, 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. However, 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 and our project development teams consistently do a great job of navigating those. And so beyond presidential orders, we continue to advance our key New York and New Jersey projects like the Northeast Supply Enhancement Project, the Rivervale South 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 -of-way and fast interconnection networks are really the best way to bring clean, safe, affordable, and reliable natural gaps to these northeast population centers that allow these regions to continue to lower the greenhouse gas emissions. And 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 8th to May 8th to give shippers additional time to get the approvals they needed not for just indications of interest but for binding commitments. And 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 the follow. And next up, I'll touch on our growth in the D.J. 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 Wells County area, we welcome the shift in authority to local counties and municipalities, and 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 feet a day Fort Lupton III cryo. The train is running very reliably and great job by the teams getting that started up safely. And construction is progressing very nicely on our Kingsburg Number 1 cryo that should be online in the third quarter of this year. And in February, we signed up another new package of gas along with NGO marketing rights right in that same area where we continue to develop infrastructure. So, 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 NGO marketing businesses, including the Bluestem Pipeline Project and associated upgrades at Convoy. And next on to deep water. 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 EBITDAB contributions from our Norfolk Project, including those from the purchase of the Norfolk Pipeline and additions to our Mobile Bay Processing Complex that we did last year. And that is going to get paid for. Actually, our Norfolk 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. So as I promised on the introductory side, we'll 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 deleveraging. 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 Tannett of JPMorgan. Please go ahead.

Hi, good morning. I wanted to start off with the Northeast GMP 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?

Yes, Jeremy. Thank you. Good morning. Yeah, 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. So a lot happening out there right now all over the place, both in the Northeast and the Southwest. And so 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, transitioned from Chesapeake, and that 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 Cabin and Southwestern. So 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. And so I would say the Northeast PA continues. They continue to invest with or support our expansions, further expansion on our gathering systems out there, and of course are very interested in additional takeaway capacity out of the area given the big reserves and the low cost reserves they have in the area. So 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 in to some of the other areas as well like in the Bradford area. So Northeast though I think is very predictable and steady. And the areas that have more I would say volatility in terms of ups and downs and perhaps being a little more reactive, the prices is in the wet gas areas like I mentioned earlier both the Marcellus wet and Utica wet. And a lot of that I would tell you is driven by pretty sharp real-life price declines on NGLs that were associated with the Mariner East up and down. And of course now hoping for expanded capacity out of their own mariners too. So I would say that the pricing forecast on NGL has been difficult to predict. And of course the gas takeaway situation particularly with MVP has been pushed back a little bit as well. So I think those things will resolve themselves as we get in. Obviously as we get into 2020 I think those things will resolve themselves. But we are seeing those producers be very responsive and I would say very strict about living within their cash flows and their forecasting cash flows. Of course that requires them to forecast prices. But 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. And so that's what you see reflected in some of our capital pullback and reduction in capital that you see here in our guidance.

That's helpful. Thanks for that. And turning to UEO OMB, 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.

Yeah, great question. You know, really on two fronts. First of all, the very simple front there is on the liquids front. So we have the Mountainville 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. And 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. And so we'll be taking those liquids over to the excess capacity, big excess capacity that exists at the Kensington Fractionator. And so they were sitting there, a lot of latent capacity on the Fractionation side and better markets there at the Kensington area. So 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 plan. So 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. And we're starting to run up on capacity constraints there at OVM. And when the growth continues there, we'll be looking for ways to move volumes over to UEO as well. So those are kind of some of the obvious issues. Obviously there's management consolidation and overhead consolidation that's beneficial to us. But a lot of it really just as relates to being able to take capital out of our plan that would have otherwise been in there.

That's really helpful. Thanks. And last one, if I could. It seems like NSEE could really lower CO2 emissions by displacing dirtier fuels. Just wondering how that messaging is resonating in the communities that you're working to operate in there. And 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 Michael Dunn. I'll take that. We absolutely think that NSEE is a key piece of the puzzle in 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. And we're going to be a key part of that continuing opportunities conferred. If NSEE 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. And the 401 certification deadline in New York is mid-May. And then the 401 certification deadline in New Jersey is mid-June. So 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 Schneuer 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? And 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, Schneuer. 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 into UEO, so those gathering volumes would have already been in there, so there's really not any change on that UEO. It's primarily just the fractionation of processing facilities downstream of that, so 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. So actually a lot of the capital is even more forward. So 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.

Hey, Gert, great color. Just another follow-up, kind of a bigger picture question. You sort of talked about and you prepared remarks about a longer-term growth rate of 5 to 7% for AVIDAS. 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, and I'll maybe have John Chandler take that in terms of where we would go with that. As we've said, the $2.5 to $3 billion, assuming a little more moderated returns than we've been enjoying, generates that 5 to 7% growth rate. And so obviously as we can migrate our investments, that improves and bring in synergies like we're doing on these JVs, but generally that $2.5 to $3 billion is what we think it takes to grow that 5 to 7% and all that. John, thoughts on funding?

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, but with the growth of our AVIDAS, we're able to maintain and continue to lower our leverage ratio going forward, and fund that capital that supports that kind of AVIDAS growth.

So would there 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 between 4 and 6, under 4.6 to 4.2, there's still quite a bit of work for us to do, so I think we've got time to talk about that. But 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, you know, I would just say on that front, you know, we'll see what the markets look like when we get to that point, and so it's kind of hard to answer that because we're speculating on what the returns would be on that investment, versus other investments, but I can tell you we're constantly allocating out capital return projects that a lot of the industry would accept. And so I think, you know, there'll be a balance there between increased capital investment opportunity is another thing we can do with that capital, and as I said, we're constantly allocating away projects today as we

continue to press on de-leveraging the business. Okay, and one last question if I may. Your excitement level about the Gulf of Mexico seems to be increasing. You sort of touched on it when you were preparing to march, but 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.

Yes, I would just say, you know, the opportunities are getting to be so plentiful that it's kind of getting hard to keep track of, honestly, but some of the very certain opportunities exist around the Gulf West, or operations around the Perdido area. Obviously the Whale Prospect out there is going to be a big mover for us, and Shell just announced a little bit earlier this month, or sorry, in April, the Black Tip discovery, which is also another very large discovery in that Perdido Belt area, and then to the south of that, of course, the Mexico Perdido is even a much larger, you know, kind of, we're a magnitude opportunity that we're extremely well positioned for. So on the Western Gulf, it's going to be a matter of maximizing our return on investment. There is plenty of production to fill up our existing capacity and then some more, and so, you know, really important opportunities 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 Gulf East, of course, really excited about the Valleymoor Prospect that will likely get produced across the Chevron's blind base platform, and that's also a very large find there, and again, just big, free incremental cash flows coming our way with very little to no capital on our part, so we're excited about that. And then the Norfolk Prospect, you know, while we kind of thought that was almost singular as an investment originally, we'd like the returns to singularly across that one field. We've seen a lot of new development out there around the Norfolk, not just by Shell, but also by Chevron now in that area. So a lot going on in the central Gulf, lots of new opportunities. The LLOG, Repsol, JB will bring some promise to us in the area, and a lot of new development going on there as well. So I'm not even getting into the, you know, multitude of smaller projects that are coming our way, but 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, and when oil was $80 to $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, but now with the 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, and that is really good for us and really good for the industry as a whole. And so I would say, if I were going to describe one big change from the last time we saw the deep water takeoff, that is really it, that there's this intense focus on the utilization of existing infrastructure, and of course that's when you already have a lot of the big gaps in the deep water that goes very well.

Hey, Alan, if I could add to that on the number one opportunity, that was a great negotiation for us to have with Shell there, where we acquired the pipeline that they built. And it was pre-negotiated with a return, and we're obligated obviously to move their gas to shore to our mobile-based facilities, where we have percent of liquids contract with them to process that gas. But 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 that with subsea tiebacks into that Norfolk pipeline that we'll purchase upon first gas movement there. So a great opportunity for us to take advantage of that facility that has already been built, so 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. I really appreciate the color guys.

Thank you. We will now take our next question from Christine Chull of Bankleys. Please go ahead.

Good morning, everyone. You guys have talked about wanting to consolidate Northeast for some time, and obviously the UEOM transaction took you in that direction. How should we think about the potential for Blue Raider to be included under that umbrella?

Great question, Christine, as always. And 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, but certainly a lot of opportunity there. But I would just say we haven't been able to get there from a price standpoint, haven't been able to get to what we thought would make sense for us on that. And so I would say lots of opportunity, but we remain patient, and will remain patient with making those combinations. But 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 an upper-order contract.

Okay. And then 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, you know, we're always looking, we continue to see this big spread between what our stock is trading for versus what these assets are selling for. And so if we can do those kind of transactions in a way that don't dilute our future and stand in the way of accomplishing our strategies, then we'll continue to look for those. But we don't have anything, you know, specific on the drawing boards. And I think as we said before, I think looking at our strategy and looking at 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, but 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 benefits and the coupons that flow from the downstream benefits, the incremental returns just don't stand up. And so Niagara 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. So we had, you know, both partners and customers, you know, frustrated with our lack of interest in investing at those return levels. And it wasn't for any reason other than it just didn't stack up within our capital allocation process. And so 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. So 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.

I

would

also say though, there's obviously cheap money looking for opportunity out in the marketplace. And very similar to our Four Corners assets, you know, we get approached by the market all the time on assets. So, you know, again to Alan's point, while we don't have any specific thing targeted, you know, we're constantly being approached. Great. Thank you.

We will now take our next question from Gabe Morine of Mizzouho.

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? And 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 Michael. 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 resettlement. So we think it's prudent to continue that process until we reach impact with our customers, but we're certainly not there yet. So we're rapidly working with them to try to come to a settlement that both sides appreciate and like, but it certainly doesn't mean we won't be willing to litigate that if we feel like we've reached impact and 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. But 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, but I'm not afraid of the litigation path as well. Specifically on the emissions reduction, so the way we 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. And 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. And so 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

with the high

rate.

Great, thank you. And then maybe if I could just get more of an update sort of 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 sort of 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, but we've seen recent dislocation in basis from the basin, obviously, to the coast. But 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. So we're going to be really, I think, 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. And 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. And so we believe those volumes ultimately want to get to the best market, and so we think transco offers those very best markets. So again, we continue to explore participating in

a project from the Permian to the Gulf Coast. We have volumes with our partnership with Parasas Midstream

that we can leverage

for

the purpose of benefiting and improving a project. But again, I think the economics that we've looked at, 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. And so we'll continue to work it. And again, I think the most important thing for us will be that we make

sure

that

Permian Gap has a good home to come

to along our transco

market.

Thank you.

We will now take our next question from Colton Bean of Tudor Pickering Holdings Company. Please go ahead.

Morning. Actually, just to follow up on the Blue Bonnet 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?

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 in the Alpine High area. So we have seen, I think, restrictions associated with gas prices in Oaxaca. So I think we get a lot of questions around with as large the basis as why we haven't seen a stronger move towards an additional project. I think what we're seeing is, as Alan mentioned in his comment, it takes a lot of time and effort to create infrastructure that can

move all the way from West Texas to the markets. And so 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, but again, if you look at the current, the former curves from basis, Guajada to Henry Hub, right now those prices don't support an investment in a long-haul pipeline. So 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. And just circling back to the Q1 results here, so on the down-tick 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 Michael. It's not really, it's more of we had some one-off issues last year that specifically in our unregulated business with terminal overhauls and things of that nature that contributed to that higher expense in the comparable border in 2018. So it's not really a structural issue, it's just a timing issue of activity.

Got it. So 2018 was probably an elevated level and this is maybe a better look at the go-forward rate?

Well, and 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 terminal overhauls, they're pretty expensive, a couple million dollars to do one terminal overhaul and those have to be done at certain intervals of runtime hours and so we have to accomplish those when we hit those runtime hours and so 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. And 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. So it's just a timing of overhaul

aspect and it's highly dependent upon runtime. Understood. And just a quick final clarification here. If for the $400 million reduction at the capital program, I think you all had noted previously that around $90 million was associated with Jackalope. So is the balance of the entirety there solely attributable to the Northeast? And then as you think about the Northeast, Alan, I think you mentioned a -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, Colby. 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. So, yeah, it's getting pushed into 2020, but you'll see some of the benefit of its energy show up in the 20s would offset that if it makes sense to you. And then finally on your question of the $90 million, the Jackalope, $400 million 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 was going in there. We've got 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. And as those push out and get closer, you saw we've advanced one of our transco projects into 2020. And so we're actually seeing really good performance on that front. But for the most part, it is coming out of the Northeast, but not all. 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. And in fact, there never really had been a regulatory process to establish that. And I think 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. And that's exactly what we have been asking for. We haven't been asking for easier regulation. We've been asking for clear and consistent regulation. And that's exactly what we thought the order tried to address without overreaching towards any one particular project. So it's something that needs to be cleaned up. And 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. And it's obvious to us there was great experts involved in that. So 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 regs within the EPA. So anyway, pretty impressed, frankly, with

the sophistication of that order. Okay, it makes sense. Just one more. You've mentioned Mountain Valley a couple of times, maybe ignoring timing on in-service that they've built a lot of that project. Assuming they get to Station 165, you talked about Synergy. Has that moved into commercializing anything at this point? Does that 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? Yes, sorry about that. Mountain Valley pipeline. Okay, thank you. This is Michael. You know, just seeing what the Mountain Valley pipeline backers have said about their project, obviously they feel certainty in regard to completing their project, and we're obviously watching that very closely along with them. It ultimately will hit Station 165 area, and there very likely should be takeaway opportunities for us from that point on the transcoast system, on that project, get closer to some certainty there. So 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, and we certainly think there's opportunities to do that.

We will now take our next question from Jean Ann Salisbury, please, of Bernstein, please go ahead.

Hi, good morning. It looks like latest flows into transco from the northeast Marthellas are around 4.5 BCFD, including Atlantic Center. 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?

You

know, I'm going

to say there's, just to remind everybody on that, transco's capacity is fully sold, so it's consistently sold out. I think communities, you know, have a lot of perspective on that. And so really what we're talking about is just interrupts, just loads, and how much we can physically flow during a period. And that's very dependent on local loads, where the gases need to be delivered to. And so there's a lot of variables that go into play there. But I would say generally we are constantly maximizing the capacity out of that basin right now because the morgans support that. But a lot of that is managed by the shippers. In other words, they're the ones dictating, you know, where they want to move the gas to and from, so a lot of that is dictated by them. But I think that's, you know, we're, I would say every day we're optimizing as much as we can move out of that area.

Okay, that's our book. That's our state full, like Atlantic Sunrise is virtually full almost since day one. So that does bode well for the future opportunities to move additional expansion volumes

out of their new project. So, you know, regional energy access, and regional energy access, though, takes advantage of a lot of existing infrastructure, as does the Lighting South project that we're working on for national fuel gas and for capping. And so there is obviously some pretty easy expansions out of the air relatively to the project teams that are working on that wouldn't clarify. But 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. And do you still have any spare capacity and gathering in the Haynesville and perhaps in the Eagleford, or is your system pretty much maxed out there?

I think in the Haynesville we bump up against the top end there quite often as the weld has come on. You know, we get max capacity there last year and continue to find new volumes coming in there that put us right at max capacity. So 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 seat recline on those wells. And in the Eagleford 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 as possible looping. So it's just highly dependent upon where the

producers are drilling their pads. Yeah, you know, a system like the Haynesville, that system actually has a south and a north component to it. And so while you might see one part of the system get loaded up, the southern part, you know, maybe more than the north sometimes or vice versa, that really dictates. And so it's not like it's a processing plant where you just have a fixed amount of capacity through the plant. The system, the capacity is very dependent on where the gas goes up. But our team has done a really nice job out there working with other midstream operators in the area to use up the capacity to build a cross-border system and they continue to do that. On the Eagleford we would remind you that that is a cost of service agreement. And so as we add capital there, that gets covered in a race where the Haynesville is not

that. Perfect.

That's

all

for me. Thank

you.

We will now take our next question from Michael Lapaydas of Goldman Sachs. Please go ahead.

Hey guys, thanks for taking my question. I'll be quick. I know there have 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, you know, making it untenable, how do you think about the solutions that Williams could offer into Virginia North and maybe in the South and Atlanta and the ability, the timeline to realize some of those solutions?

Yeah, Michael, obviously, you know, a topic that's been getting a lot of discussion. We have a lot to offer in terms of distributing the product, the gas, the 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 -of-way. MVP is more just kind of a downstream issue, so to speak, because obviously, you know, they get across the trail with those supplies. And so that's really the struggle there. But I would say we have a lot more to offer ACP in terms of meeting their market distribution goals. And as to MVP, they need, 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. So that's how I would, you know, 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 costs down, and that's what we're very focused on in both these cases.

But 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, you know, a lot of routes already into some of those markets, but it is significant in terms of the investment. It's not, you know, it's obviously quite a bit lower cost by using existing facilities, but it would be pretty significant investment required. And it's very dependent on where the supply comes from. So, you know, a lot of variables here, depending on where the supply comes from, 165 to 194 to work, we have a lot of ability to help distribute that gas into the market.

Got it. Thank you. Much appreciated.

We will now take our next question from Justin Jenkins of Raymond G. Please go ahead.

Great, thanks. Just want to follow up from me. Just to take a one-queue run rate for CapEx, we're a bit below the full year guide. So is it more balanced throughout the rest of the year here, or is it back-end loaded, or maybe just to help on the cadence of CapEx, if you could?

Yeah, this is Michael. Well, I would say, you know, Q1, you can't take that really as a run rate because our construction projects really ramp up in the second or third quarter of the year with our growth projects that we're working on. So I would 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, you know, it will ramp up as the summer construction season heats up. Got it. Thank you.

We will now take our next question from Chris Sayenalfi of Jeffreys. Please go ahead, sir.

Hey, everyone. Thanks for the ad color this morning. Alan, you guys have been very active since the last day or go with asset sales, JV rationalizations, and clearly a focus on view leveraging. I guess I have two questions that stem from all of that. The first is to follow up on Janir's earlier question about your longer-term 5 to 7 percent annual with David Dogbrook guidance. Just curious how to interpret, you know, your longer-term phrasing for periods beyond 19. Just wondering maybe how you or John would think about the outlook versus the forecast contained in the WPZ S4 last summer.

Well, the WPZ S4 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. So, you know, 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 two and a half billion on expansion capital, again, we continue to see a de-leveraging and at the same time we see this level, even dog growth, that runs in the 5 to 7 percent range. So I really wouldn't put too much weight in the WPZ document.

Yeah, I would just say, Chris, we are focused on delivering on both of those ends, both on the 5 to 7 percent growth as well as the de-leveraging. And, you know, we're constantly balancing that and obviously being able to sell assets that are, you know, well at these high multiples is a pretty attractive way to get there. But we also, you know, are very focused on making sure we have plenty of reinvestment opportunity to drive that growth, that 5 to 7 percent growth. And so far, I would say, we feel very comfortable about our ability to, you know, continue to place that capital. And, you know, projects just continue to develop that are moving along pretty nicely. And within this period, I would tell you that, you know, one sizeable project that's developed is the Regional Energy Access Project. It's come along very nicely and with a lot of strong support all of a sudden. So I think, you know, we're really feeling pretty good about the opportunity, high return of dust and opportunities that continue to come. And as we get into the 2022 timeframe, the deep water, if this isn't speculative on our part, the deep water cash flows there are going to be pretty big because the FIDs for those projects are moving ahead and a lot of that business will be coming to us. And so 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. So anyway, feeling very good about the ability to see that kind of growth rate and continue to be leveraging. But we are managing both of those as we think about transaction.

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, 10 percent K-GARs at 10 to 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 transfer projects coming on at the end of this year and next year. So it will be adding EBITDA. And of course it goes without saying the DJ-based assets that we acquired late last year, there's a significant ramp up in growth coming from that as well.

Okay. And one clarification on that, John, just to my own purposes. It's very clear that you've omitted any trans-GRO rate case-related impact on the formal 19 guidance. But as we think about 5 to 7 percent over the next couple 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 puts you higher up in the range? It would put us higher up in the range. Okay. And then I guess that's very helpful. My second question, you know, very much appreciate the revamp of the presentation materials and something that, you know, we've long acknowledged but still illustrated clearly. I think it's slide 13. It's just, you know, the significant non-cash items that do present a drag to EPS. And I guess I'm just curious, you know, 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, you know, we get a lot more questions from investors about EPS. I'm assuming you could too. And I'm just wondering what more could be done on that front.

Thanks. That's a weird commentary for CFO to look for impairments. But 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. And to the extent we moved assets from a consolidation to a non-consolidation type approach to 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, any other tests for impairment is based on gross cash flows. And 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, but it forced us to revalue a lot of the access assets at a very high valuation level. While those are at high levels, the gross cash flows still exceed those book values. So anything short of actually some kind of partnership for JV that would force some level of decontolidation, that's the only thing that allows really to help bring that depreciation down.

Okay. That's helpful. I appreciate it's unorthodox to sort of line questioning for you. The focus seems to have totally changed. It seems like the recent deals you've done in the Northeast maybe are structured in a way that helps on that as well. So that was where I was coming from. Appreciate the call.

We will now take our next question from Craig Shear of Toohy Brothers. Please go ahead.

Good morning. Most of my questions have been answered. I did have a quick one. Alan, you commented on the wheat and wet gas and the Marcellus and Utica in terms of recent trends and NGL pricing. It 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, you know, I think, Craig, the investment we have there feels pretty good about that filling up. And it is, as I mentioned earlier, we've got a lot of pads being turned online. And so we're really starting to see that come up. It doesn't take a lot of them as big as those pads are to make progress on that front. And we have some contracts coming our way that are shifting volumes our way. So I feel pretty good about the TXP2, the existing base capacity plus TXP2. And we were able, as a result of the synergies and knowing we have excess processing capacity, the UEO, that takes, puts us in a position to not have to pre-build any capacity out in front. It won't grow any further. So the synergies or the, 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. And so I would just say that gives us a lot more breathing room and allows for better capital efficiency as it relates to the OVM processing capacity. And we intend to take full advantage of that.

Sounds

good. So your

TXP2 is basically contracted up. The slowdown is not really going to impact it. But you're de-risked on the fact that you don't need new capital because you have the ability to work between bases. Right. Correct. That's terrific. Thank you.

We will now take our next question from Tim Schneider of TXP2. Please go ahead.

Hey, good morning, guys. The majority of my stuff's been asked to. 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 long-term. And 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 four times? Are you happy kind of being in the low fours just interested in your thoughts here?

Yeah, I would just say, you know, our asset mix, because we don't have a lot of – in fact, 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, which is trading around the assets. We don't have that kind of variability to our cash flows. And I think you can see that with the remarkable predictability through our cash flow streams that continues to flow. So, no, I don't think they ought to get marked all the same. But I would say that, you know, the rating agencies have told us that on their basis it's a 4-5 kind of number to be triple-B flat. And we want to be there, be confidently there at that triple-B flat level. And so that 4-2 mark on kind of a steady run rate basis is why we're seeking that, because that happens to be coincidental with that triple-B flat from the rating agencies.

Yeah, I mean, in that sense, I guess if you guys are getting feedback from the investment community, do you really want to see something below four 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?

You know, I would just say from my own personal perspective on that, I think, you know, there tend to be fads that move through the investment community. And I think, you know, from our vantage point, keeping our debt costs down and the capacity to flex when we need to is what we're targeting from the business trajectory. And I think we think that's really the smart place for us. And I think the market has to figure out, and it should figure out, you know, who has volatility in their cash flows and who doesn't. And that ought to be driving the numbers that each company should aspire to, not just because somebody magically came up with a four-times number.

Okay. 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, and appreciate the opportunity to visit with you on this. I'm really excited about the continued, very predictable way our business is running and the way our teams are executing on projects. So I look forward to speaking with you in the future and at the next quarterly call.

Thank you. Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.