Williams Companies, Inc. (The)

Good day everyone and welcome to the Williams Company's fourth quarter and full year 2019 earnings call. Today's conference is being recorded at this time for opening remarks and introductions. I would like to turn today's call over to Mr. Brett Craig, Director of Investor Relations. Please go ahead, sir.

Thanks Carrie. 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 board of directors, John Brown, will speak to momentarily. Joining us on the call today are our Chief Operating Officer, Michael Dunn, our CFO, John Chandler, our General Counsel, Lane Wilson, and our Senior Vice President of Corporate Strategic Development, Chad Zamrin. In our presentation materials you will find a disclaimer related to forward-looking statements. This disclaimer is important and integral to 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 materials. So with that, I'll

turn it over to Alan Armstrong. Okay, great. Thanks Brett and good morning and thanks for joining us as we discuss our fourth quarter and the full year 2019 financial performance and our key investor focus areas. So let's move right into the presentation and take a look at our strong year-end performance. Here on slide two, 2019 was another year of strong predictable growth and solid execution. This is now the third year in a row we have exceeded the midpoint of our guidance range on key financial metrics. This highly reliable and predictable performance is a result of continuously improving execution by our operating teams on many fronts. Capital project execution, reliable on-time services for our customers, safety performance, environmental stewardship, capital discipline and operating efficiency. All of these efforts circle around a deliberate strategy to deliver long-term shareholder value by accomplishing the following. First is our focus on being V-Very best at providing infrastructure services for natural gas as an economically and environmentally superior energy source. Second is to reduce direct commodity margin exposure and basis risk to focus on highly predictable fee-based revenues and certainly the reason that our business has become so predictable is largely focused on that one and we've very much achieved what we'd hope to accomplish in terms of that reduction. And third is to deliver the balance sheet to provide flexibility and unquestioned financial stability. These efforts grow predictable record results in 2019 across key performance metrics. The company produced record annual adjusted EBITDA of $5.02 billion and growth of 8% over the record 2018 performance of $4.64 billion. Distributable cash flow, also a record, grew by an impressive 15% to an amount of $3.3 billion and this financial performance was driven by continued growth in the very large volume of natural gas. The company gathers from a diversified array of both supply basins and a variety of producing customers. Our record average daily gathering volume of 12.9 BCF per day for the full year of 2019 was a 5% growth overall and it was 15% in the Northeast. In fact in the fourth quarter on that comparison we saw volume growth of over 10% up to 13.3 BCF per day and for the whole gas, against the whole gas gathering portfolio and a 12% growth in the Northeast GMP segment. So the company also continued to realize growth in the interstate gas transmission driven by 11% growth in the long-term firm contract capacity on Transco, the nation's largest and fastest growing pipeline system. Turning now to slide three, I wanted to take a brief moment to acknowledge some of the key performance metrics we are using to manage the business and to measure our continuous improvement efforts. First of all, our financial performance along with the company's disciplined approach to capital investment and successful efforts to monetize assets brought our leverage ratio under 4.4 times which is significantly inside our originally guided leverage ratio of under 4.75 times. So we are certainly well on our way to reaching our target of 4.2 in 2021. Also as an enterprise we are focused on improving our return on capital employed or ROCE. While it is only a snapshot and is certainly not a perfect measure of long-term returns, measuring the -to-year improvement keeps us very focused on preserving our precious capital and a 13% compound annual growth rate on the very large capital base the company has employed is great improvement but we look to continue bringing ROCE up with our continued strong discipline around capital investment. Our operating margin ratio shows how much of our gross margin gets to the bottom line after operating administrative costs and to improve on that we have to utilize our scale to grow gross margin faster than our unit cost. We have improved this metric even in a slowing growth environment and dwindling commodity margins and target continued improvement here through both cost management and growth. And finally, our total recordable incident rate is a measure of our safety performance among several safety metrics we monitor. There has been a great improvement in our total recordable incident rate over the last several years as our safety culture continues to improve and our employees find and eliminate hazards from the workplace and protect the public while operating our assets. Every employee has full stop work authority and when they recognize a safety issue and are empowered to make it right. Our employees own this metric and are responsible for this great improvement and I'm pleased to report on that group's improvement here and in fact in 2019 our TRIR came in at 0.55 which is well below the toughest of industry benchmarks. And finally, all this discipline and focus has culminated to drive an impressive 25% CAGR on our EPS from 17 through 19. Now we're going to move on to slide four. And here on slide four we provided a clear view of our full year and fourth quarter 2019 financial performance relative to 2018 periods. And as you can see we continue to enjoy steady growth across our key measures despite the impact of asset sales and much lower commodity margins on a full year basis. We covered some key annual performance metrics on the previous slide but on this slide from an annual perspective I'll just point out that growth in our gap cash flow from operations of 12% is right in line with the adjusted EBITDA and DCF performance we've already discussed. And the per share metrics both DCF per share and adjusted EPS showed equal or stronger growth with DCF per share up 14% and adjusted EPS up that 25% again this year. Another key piece of 2019 performance is the improvement in an already strong coverage ratio. Our DCF exceeded our dividend by 1.79 times or nearly $1.5 billion. This healthy and growing coverage is one of the key items the management team and board evaluated as we raised our dividend here in 2020 by 5%. Our impressive performance on leverage was the result of strong operating performance that we've already discussed but also importantly a disciplined approach to capital investment. In fact I think this is one of the great highlights here for the year and for the quarter that our total capital both growth and maintenance came in under $2.5 billion for 2019 and that was a $1.7 billion or 40% reduction from 2018 and well below our original guidance on both growth and maintenance. So during 2019 we saw an environmental, sorry, we saw an environment shaping up that would challenge the growth plan some of our producer customers have laid out. We quickly responded to the realities we were seeing in the market by moderating our capital spend versus the budget we had created in late 2018 and in fact in the northeast alone our total capital spend came in approximately $400 million under that original budget. So against the backdrop of a much lower commodity price environment that we had in 2018 the company produced strong growth in our various earnings and operating metrics and grew dividend coverage while also realizing over $1 billion in net proceeds from our portfolio optimization efforts and lowering leverage. We are certainly very pleased with the performance that we saw across many of these facets for the full year. So let's move on to slide five and discuss the main business drivers of our 4Q19 over 4Q18 on an EBITDAO basis. And so here on slide five now we compare fourth quarter 2019 to fourth quarter 2018 adjusted EBITDAO increase about 7% or 8% if you adjust to the bigger transactions that affect the year over year comparison. This 4Q growth came at a point in the year when GMP customers had already begun to talk about moderated growth plans and commodity price concerns. Our business showed growth against a tough comp where the prior year period already included contribution from the Atlantic Sunrise Project and the associated gathering volumes that grew dramatically in the fourth quarter of 2018. On the left side of this slide you can see a net unfavorable $7 million comparability adjustment in the gray bars which includes removing the adjusted EBITDAO from the various asset transactions netted against the favorable addition of 38% UEOM interest. Normalizing for those items you see adjusted EBITDAO growing 8%. Now moving over to the right side of the chart to focus on the financial performance of our continuing business the Atlantic Gulf increased by $43 million or 8% from the fourth quarter of 2018 driven by transco revenue growth from the Gulf Connector and Rivervale South the market expansion projects. Additionally for fourth quarter of 2019 results include the increased EBITDAO from the transco rate case settlement and lastly while total deep water gas volumes were up 17% we saw a decrease in revenue due to temporary producer operational issues on our Gulf Star deep water platform and this issue appears to be corrected now as we've seen volumes come back very strong here in first quarter. Also the Norfolk pipeline which serves Shell's deep water appomattox field in the Gulf East continues to see volume increases after flowing first gas on the pipeline in the third quarter of 2019. Next the Northeast GMP area led the fourth quarter performance with a 19% increase driven by an increase of about 970 million cubic feet per day or 12% on higher gathering volumes and higher gathering fees that were associated with expansion projects and escalators that are built into those contracts. Volume increases were led by Susquehanna Supply Hub and Bradford areas which grew about 600 million cubic feet per day but all our operated Northeast franchises saw volume growth over this time period so overall our operated assets in the Northeast continue to see very strong growth across the board. Finally even though we enjoyed an impressive 10% increase in total gathering volumes on our remaining assets during the fourth quarter comparison the West EBITDAO was relatively flat due primarily to a $31 million decrease in revenues for our Barnett gathering business as a reminder from our third quarter results this decrease was associated with the end of a Barnett MDC or minimum volume commitment and a related step down in deferred revenue amortization. The Barnett MDC's expired at the end of June 2019 and once that happened the revenue recognition rate of fixed payments that we previously received began to reflect actual volumes rather than the MDC levels. We also overcame about 13 million of lower NGL margins in the West which was a 45% decrease from the prior year fourth quarter. Now moving on to slide 6 we'll look at the full year drivers of adjusted EBITDAO which increased about 8% or over 11% if you adjust for the bigger transactions that affect this full year comparison. Once again on the left side in the gray bars if you net these out you'll see an unfavorable $110 million comparability adjustment from the various asset transactions that occurred during

this

time period. In 2019 Atlantic Gulf increased 20% and the Northeast was up 19% driven by the same factors discussed on the previous slide. With the addition of a full year revenue impact of the Atlantic Sunrise project that came online in early October of 2018 the West is down about 6% reflecting much lower NGL prices. Again the step down of the bar net revenue we talked about offset by growth in the Haynesville, Eagle Ford and DJ Basin. Also our Conway Frack and Storage business so that's our NGL services business continues to see strong fee revenue growth on the back of NGL production that's been coming out of both the DJ and the Bakken areas. Our team's crisp execution drove the growth we continue to show in the Atlantic Gulf and Northeast this year leading to an overall 8% growth and adjusted EBITDA despite the significant asset sales, the much lower NGL margins and the one time step down in the bar net revenue recognition. So now let's move on to slide 7 to address the key investor focus area. So first let's set the scene a bit for 2020. As of January 1, 2020 our Northwest Pipeline business will be managed and reported with our other regulated interstate gas transmission systems in a segment we will call Transmission in Gulf of Mexico. This move will streamline the management and operations of the regulated gas transmission business, combine these businesses into a single reportable segment and providing a clear picture of the very solid performance and predictable cash flow generation of these competitively advantaged assets. The deep water business will remain in this segment as well and become more important to our EBITDA and ROSI improvement as growth in this basin is coming back strong. Moving Northwest Pipeline out of the west segment will position the west of the gathering processing and NGL services business providing a full suite of midstream services to producers from wellhead gathering all the way through NGL fractionation storage and NGL logistics especially after the Blue Stem NGL project is placed in service later this year. And the Northeast GMP segment will continue to provide all midstream services to the prolific Marcellus and Utica Shales, the largest source of gas production in North America. We will continue to separately report the west and Northeast GMP segments but combined management will allow us to take better advantage of our tremendous scale and continue to grow our operating margin in this producer facing business. So I'd like to talk for a moment about how we see the GMP business both in the near term and the longer term and how we have positioned this business. We saw record gathering volumes in 2019 because of continued production successes by our upstream customers, continued growth in natural gas demand and great execution by our teams. But over the last year robust production growth has outpaced very healthy demand growth and in fact demand has grown significantly 21% over the last three years but domestic production has grown even faster. This imbalance will be a near term headwind of volumes and EBITDA in the GMP business as current prices don't support investment in gas drilling in most cases. So producers of course are acting rationally, slowing their capital investment and reducing production growth. While some producers are still forecasting growth, others are focused on keeping production flat and while lack of recent investment from the upstream will cause declines in other production areas. Some producer balance sheets are stressed. We have already seen some bankruptcy filings. While a customer bankruptcy filing is often disrupted to the normal course of business, it affects various midstream services and contracts very differently. After a very long time in this midstream business I have seen and experienced many instances of producer stress and even bankruptcy and it's very clear to me that the most protected service by far is that of wellhead gathering. Wellhead gathering is absolutely essential to any reserves that are going to be produced. Gas cannot get to market and cash flow cannot be realized if wellhead gas gathering is not available. While counterparty credit is important, the physical nature of the service is even better security. We believe that supply demand imbalance is only a near term concern as last week's storage was only 215 BCF above the five year average. We see continued demand growth bringing supply and demand back in balance and our long term strategy is as we have told you many times before is predicated on the belief that the economic and environmental benefits of natural gas will support continued long term demand growth both domestically and internationally and that U.S. domestic supply is well positioned to grow its share of global demand as well. In the long term whatever demand is supply will grow or decline to meet that demand and importantly we expect low cost gas basins to continue to be the majority of supply that will meet this demand. Associated gas will be important no doubt but gas directed drilling the source of approximately 65% of today's gas supply will remain the bedrock of domestic gas production. So we feel confident in the long term position of our assets and strength of our strategy but the current price environment is a reality that the market will navigate through here in the near term and we have built a very resilient G&P business that can succeed in a wide range of market environments. The dramatic growth we've seen over the last three years and the currently challenging price environment for our producing customers. We built this business very intentionally not by accident we've been at this a long time and we have moved away from direct commodity exposure and from reliance on marketing and basis spread for profit. We have taken strategic action to broadly diversify our sources of EBITDA both in the 15 different supply areas our G&P businesses serve and the very wide variety of customers we contract with to provide those services. Another thing I want to point out is that continues to demonstrate our ability to work with a wide range of stakeholders is that the free cash flow produced by our onshore G&P businesses grows dramatically when drilling activity pulls back. Capital spend declines significantly driving near term RoC improvement and tremendous free cash flow growth. So as we've said before when we do see investment pull back on the drilling side we see tremendous continued increase in free cash flow growth from the G&P business our West is a great example of that. And with regard to our 2020 guidance we are reaffirming the guidance we provided at Analyst Day in December. For the largest near term uncertainty is producer activity we feel comfortable with our 2020 guidance. We will keep a keen focus on capital spending and cost management as the year evolves and importantly we are expecting to fund dividends and capex with internally generated cash flow which benefits the company as we look toward our long term goal of reaching a net debt to adjusted EBITDA leverage ratio of 4.2 or lower. And so I just want to comment a little bit more here on the guidance for 2020. First of all the volumes that we saw in the last half of the year certainly in the Northeast and the rates that we enjoyed there along with what we're seeing here in January and February in terms of volume as well as some pretty significant cost cuts that we made late in the fourth quarter of 2019 all compiled to continue to give us confidence on our guidance for 2020 despite the challenging pricing environment that's out there today. So now let's move on to discuss some of the key issues around our transmission in Gulf Mexico business. First we're pleased that we have filed our Transco rate case settlement with FERC on December 31. We had only supporting comments from shippers to FERC. Since the rate settlement was filed with FERC we are pleased to have reached this settlement that we expect to provide a $76 million benefit to adjusted EBITDA in 2020 versus the last full year of 2018 which was the last time we had a period with no rate case impact. I also want to point out the successes we are having on our portfolio transmission expansion projects. Since September we've placed the Riverville South and Gateway projects in service. In service both of these were in New Jersey and our Northwest Pipeline commenced service on the North Seattle lateral expansion. These are two areas with extremely rigorous permitting processes and a politically active local minority opposing natural gas infrastructure. In short challenging places to build gas pipelines. Williams continues to demonstrate our ability to work with a wide range of stakeholders in a constructive manner to address these regulatory, political, and community concerns while still getting important infrastructure expansions permitted and built. We plan to continue that track record on the over $3 billion of pipeline expansion projects that are currently in execution mode and we are achieving key milestones on each of these projects. First of all Hillelby Phase 2 is mechanically complete and ready for end service. The Southeastern Trail project has all of its federal permits and began construction in January of this year with an end service targeted by year end. The Leidy South and Gulfstream, Gulfstream 6 expansion now both received favorable environmental assessments which is a key step in the FERC certificate process and each project remains on track for scheduled end service. Leidy South by the end of 2021 and the Gulfstream Phase 6 expansion by the end of 2022. Our Regional Energy Access project is looking more attractive as time goes on. We have a project that will be between $800 million to $1 billion cubic feet per day. Once we've settled on the appropriate size of the project we'll move to complete the work to apply for a FERC certificate. So we're in the final stages of tidying up contracts there with our customers but we do have a project at this point it's a matter of the size of that project. We also continue to feel very confident about the prospects for Northeast Supply Enhancement completion and we look forward to the conclusion of National Grid's process to assess alternatives for serving Brooklyn and Long Island's growing energy needs. We continue to see this project as the most reliable, most environmentally beneficial and most economically friendly alternative. At full load the fuel oil to natural gas substitution for this project would enable an emissions reduction that's equivalent to taking 500,000 cars off the road. So that along with the savings to the customers and the residents in those areas we think are powerful motives for getting that project approved despite the very noisy minority around that and we certainly know that this is by far the best solution for the area. Beyond these projects in execution we continue to make good progress on our backlog of projects in development and we expect several of these to move into execution mode this year. Transco is well positioned to continue growing our contracted volumes in a well established corridor serving a large portion of the U.S. population. The forces you see working in the market today are only increasing the competitive advantages of Transco. Low prices continue to incent demand in all sectors and our access to many geographies and types of demand is unmatched. LNG, industrial, power, residential, commercial are all growing along Transco. Difficulties seen by greenfield pipeline projects will also benefit Transco in the long run as Transco is uniquely positioned to meet new capacity demand by expanding along its existing rights of way which are irreplaceable and unmatched in terms of their proximity to demand. Our Gulf of Mexico assets are similarly positioned against a growing market opportunity. Chevron made a positive final investment decision on their Anchor project in December of 19. Anchor is near our Discovery-Keefley Canyon connector and we are excited to be finalizing the definitive agreement to provide a full range of services for this very rich gas to be produced by the Anchor project. Anchor represents continued realization of the strategy that supported the original Keefley Canyon connector investment capturing new volumes from significant nearby deep water prospects. Given its proximity and our pre-planning we will not have to invest any significant capital for this new business. Williams will continue to pursue similar connections as other nearby prospects move towards FID and first production including the L-Log operated Shenandoah, Yucatan, Leon, and Moccasin, the Equinor operated Monument, and the Toth-Tow operated North Platte. The Shell operated Whale project is an even larger opportunity for us and the services we expect to provide to this dedicated field include gas transportation, gas processing, and importantly the crude oil transportation as well. Shell continues to make progress on this very large scale project and expects to make their FID decision this year. And in fact in November of 19 Shell awarded Singapore's Semtorp Marine the contract to build the Whale floater. In addition Williams has executed a reimbursement agreement with the Whale owners to cover commitments in 2020 to keep the project on schedule for first production. Williams will secure several long lead items including the line pipe, valves and fittings, and the installation contract, and ongoing engineering costs. Whale and Anchor would represent a significant increase in the volumes we are currently handling on our consolidated assets, but these are just two of the many opportunities our deep water assets are competitively positioned to win as producers in the area are looking to align new development with existing infrastructure to lower cost and decrease time to market. We believe our business is very well positioned to benefit from continued demand growth in natural gas over the long term and that our strong competitive position and conservative financial model makes us a resilient business that can deal with the near term challenges in the market while positioning ourselves for the strong growth that's ahead. So with that let's go ahead and transition to our Q&A session and thank you again for your time today.

Thank you. If you would like to ask a question please signal by pressing star 1 on your telephone keypad. If you're using a speaker phone please make sure your mute function is turned off to allow your signal to reach our equipment. Again that is star 1 to ask an audio question. We'll pause for just a moment to allow everyone the opportunity to signal for questions. Our first question will be from Jeremy Tonnet with JPMorgan.

Hi, good morning. Just wanted to start off with I guess some of the strategic transactions that you guys had done in recent years and kind of some sales and JVs and was wondering if you could comment I guess on the ability to kind of capture those type of opportunities going forward here and what that could mean for hitting kind of the 4-2 leverage ratio that you guys are targeting there. If you're able to do that I guess it's quicker or if that doesn't come together how long do you think it would take you to hit kind of a target 4-2?

Yeah, Jeremy, good morning and thank you for the question. I would just say first of all we're encouraged by the attraction to the kind of assets that we have which have long histories of cash flow and so that's very different than some of the other assets out there that aren't as well positioned or are more speculative in nature of cash flow. So we think assets that are stable and have a long history of cash flow are pretty important in this market today and so we're very encouraged by that. I would just say the growth that we have and the continued cash retention that we have in the business right now we certainly have our eyes on that 4-2 even without that but we look at the further transaction as a way to accelerate ourselves towards that and likely under that with any significance to the size of those transactions.

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

Yeah, great question Jeremy and thanks for asking that. I know that's an issue on a lot of people's mind. First of all I would just say obviously we have a very diverse business and some things go south on us and some things go positive if you think back to last year and you think about commodity price assumptions that we had versus how the year actually wound up we outperformed as in again good evidence of how things can go our way to offset other negatives that occur during the year. So I would just say we do have a large portfolio. I also though as I mentioned in my comments and I think this is really important for people to understand if you look for instance a lot of concern around the Northeast volume and if you look and took the combined took the average of the third quarter and the fourth quarter you would see that if all we did was repeat that we would come in above our guidance level for the Northeast for next year and I know there's been a lot of concern about that. If you took and just took four times the fourth quarter assuming the fourth quarter held where it was and didn't see any growth at all you'd see that we would beat pretty significantly that guidance that we had laid out for the Northeast and so that I would say combined with a couple of things. One is the fact that our fourth quarter did come in stronger than we were expecting for the Northeast when we were laying guidance out at Analyst Day we were working off a forecast that was actually exceeded for the fourth quarter so we're starting off better than we start than we expected to. Secondly, we've seen January and February volumes now and so we've got pretty good confidence about where actual volumes are and then finally I would say we took the cost that we took out that we'd worked on and planned around during 19 most of those costs and the impact of those costs actually started rolling out very late in the fourth quarter of 19 so we'll have the benefit of that working with us going into 2020. So I would just say a lot of positive things that are occurring as well with some deep water production that's coming on a little faster than we would have expected as well and volumes actually again exceeding where we thought they would be at this point in time when we laid out Analyst Day. So those are the things that have given us the confidence on our guidance being maintained as we sit here today.

Got it. Great. That's it for me.

Thanks. Thank you. Our next question will be from Spiro Donis with Credit Twist.

Morning everyone. Allen, appreciate your comments around GMP being one of the more protected components of the value chain but I guess as we think about quantifying a potential impact is there a way for you to help us quantify how much of your volumes or margin could be considered maybe above market or maybe subject to renegotiation? You've been pretty proactive on this front so far so I'm not sure how much your portfolio is in theory still at risk and if you're receiving any sort of inbound inquiry from customers to do a blend and extend.

No, we are not. I think we have completed all negotiations that anybody has entertained with us on issues right now particularly with Chesapeake. We settled that in the Eagle Fort and I think you'll see this year I think you'll see that some of the assumptions that were made by some of the analysts about where that was going are going to be proven very wrong about their assumptions on that for the Eagle Fort. And I would say this in terms of incenting further drilling we've been working pretty actively our commercial teams have been working very actively in places like the Hainesville to incent drilling on acreage that's dedicated to us but not otherwise being drilled and that does require us putting an incentive rate out for new drilling but it doesn't affect the rates of the existing business so it's just a way to attract new drilling dollars against acreage that Chesapeake for instance likely wouldn't get to if we weren't out working transactions to help make that

happen. Understood. Some of the common pushback we receive from time to time just around the growth backlog and your ability to spend I guess enough to really on those demand pull projects to drive that 5 to 7% growth and so in other words I think people are struggling with maybe the scope of these projects and their ability to grow that 5 billion even up base and so are there opportunities beyond the ones you list that maybe we're not appreciating or are we seeing that the growth of the existing business GMP actually still an ongoing major contributor to growth even at these lower capex levels?

Yeah, I think certainly we had a great year of growth this last year and on an adjustment for both asset sales and margin where growth was a lot better than we would have just built into the plan in terms of volumes and fee-based rates last year. A lot of that came from good cost control and really good execution on our projects bringing them on a little earlier than expected but I would say the things that I think the market tends to miss is things like the DJ basin growth that continues to come on very nicely for us, the Blue Stem project coming on for us, the deep water which is really coming back. I think 95% of the rigs now available, floating rigs available are under contract now in the deep water and so we are seeing a lot and expecting a lot coming from that area as well. So these projects coming on in transco are pretty powerful but that's not what we're totally dependent on for our growth by any stretch of imagination.

Very helpful. Thanks, Alan.

Thank you. Our next question will be from Shanurah Gershney with UBS.

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

Yeah, you know, we certainly have quite a bit of capital still in plan and, you know, despite the narrative that's out there, we still have producers that are still pushing ahead with the drilling plan, some of those based on hedges that they have and some based on contracts that they have. But we still have some pretty big obligations to keep up with that. I know the market, you know, the narrative is very different than what you're seeing, but in reality, right now we do have that capital built in because those producers are moving ahead right now with their activities as they told us they would. And so those come with obligations on their part. So we have to be ready with that capital that's in there. If that were to change for whatever reason, then, you know, that might shift that back. But I think we should be clear that we do have customers continuing to have growth and plan growth in the Northeast. And so, you know, we'll wait and see, obviously, but right now it's getting pretty late in the process for them to be pulling back from those plans that they've laid out for the year. And again, I think a lot of that is based on hedges that they have in place that continue to support those activities. So I don't want to get into, you know, each individual customers because that's up to them to lay out their plans and communicate that. But we are responding to the very detailed planning processes that we work with in the customers. And we do have capital in the plan to help drive that. And so, you know, we like we had last year, if we need to turn that back quickly, we certainly would. But there is quite a bit of activity that's going on out there despite, you know, what the narrative is.

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

Jenner, you're breaking up just a little bit. Could you repeat that?

Yeah, would you have more flexibility on capital and cost structure for 2021 if this trend, you know, sort of maintained itself? Obviously, it's late in the year to be adjusting things for 20, but was more thinking about 2021. Do you have a lot of levers that you can still pull there if this environment maintained itself?

Yes, we certainly do. And, you know, I think part of our effort to combine the West and the Northeast GMP area is because we do expect to move. I mean, that area has been growing dramatically. It sounds really easy for us to sit here in our offices and think about the kind and talk about the growth, you know, off the spreadsheet. But the reality is the very, very hard work of our employees and the teams out there trying to keep up with all that growth, they've done a remarkable job on that. But it does take a lot of people and it takes, when you're investing in the capital, it puts a lot of cost onto the operating teams as well because there's a lot of change going on that they're having to manage. So a more mature and a slower growth environment absolutely allows us to go after and increase our operating margin in an area. And us combining our West and our Northeast from a management perspective is allowing us to get after some of that.

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

Good morning. This is Michael. I'll take that one. So on our transmission systems, we've been ahead of the curve there for a long time in maintaining our commitment to keeping our assets safe and reliable. And I would say with the timelines that have been laid out and the new rules, there's a long runway to compliance there. So I think that's going to allow not only ourselves but the industry to manage that pretty well within our maintenance capex and our neural opex. And so I'm not too concerned about having that drive any additional rate cases.

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

Shanir, I'm sorry. You broke up again. On which project were you asking that question?

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

I would certainly hope so. But, you know, I think there's a lot of uncertainty right now within the rating systems within ESG as to, you know, where we get that. We would certainly pronounce that as a win because it certainly is going to impact the environment and we certainly would be taking a big part in making that possible. So we certainly would want to talk about that. I would say even perhaps even larger than that and more directly related to that would be the emissions reduction projects on the NSC that we still intend to follow through with some negotiations lingering post the rate case on that. But that would be very dramatic emissions reductions and exactly the kind of thing that I think the whole industry, certainly Williams and the whole industry, is really capable of reducing emissions dramatically. And if the focus got to be on actually reducing emissions and not just trying to stop fossil fuels, there's a lot to be accomplished by the energy industry in terms of emissions reductions and we expect to play a big part of that.

All right, perfect. Well, thank you very much. Appreciate the color today,

guys. Thank you. Our next question will be from Tristan Richardson from CENTREST. Tristan, your line is live. Please be sure you're not on mute. All right. Next question will be from TJ Schultz from RBC Capital Markets.

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

Yeah, TJ, great question. First of all, one of the impacts this year will be the growth in Appomattox. So remember our Norfolk pipeline that we put on line last year, that is finally starting to ramp up pretty dramatically as expected. Shell's got some big plans out there on Appomattox, so we're really excited about that. So even though the construction work is, there's nothing new on that, the actual volume growth on that we expect to be pretty nice this year. On top of that, we tied in two prospects on Discovery last year that were kind of midway through the year. Those will contribute to Discovery this year. And then finally on Gulfstar, HESS, ESOX project was brought online well ahead of schedule. They did a great job of executing on that project and really made for nice returns for both themselves. And of course we make nice fees on that business as well. So that was well ahead of our schedule, our plan as well. There's also work going on by Cosmos around some of our areas with their Kodiak 2 process well that they're working on right now. So a lot of activity out there. And we're very fortunate to have a lot of that activity directly around our assets out

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

That's more dependent on asset sales. Our guidance assumes a refinancing. But I will tell you, we do have a billion and a half of our debt maturing in March at a net rate of 5.2%. We could refinance that today. For example, 10 year, at a 10 year rate of 3.3%. So we like the rate environment right now. I will tell you though, we're holding tight and waiting. I think it's no secret that we've said we are looking at potential opportunities for asset sales or selling interest in some of our assets. And we don't want to get in front of that by paying down debt that otherwise could be paid down with cash received through one of those transactions. But I would tell you, our guidance and forecast didn't include asset sales. Perfect. Thanks. And so we could see interest savings just through the refinancing. And obviously much more significant savings if we actually did pay that down through an asset sale.

Operator, are you still there?

Colton? Our next question comes from Colton Bean of Tudor Pickering Hole and Company.

Good morning. Alan, you mentioned just the volume trends that you are seeing this far in 2020. Can you give us or just frame the activity levels that you're seeing in some of those primary basins in the west? I know we've spent a lot of time in the northeast, but just how you're seeing some of the west basins and maybe how that compares to your guidance that you laid out in December?

Yeah, Michael, you want to take that?

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

Yeah, and so it sounds like the Rockies segment there hasn't been impacted as much as you would have expected from the natural gas decline?

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

I'd if it's helpful. And then just on Lydie South, given some of the moving pieces around producer plans, there have been any discussions with anchors shippers that would impact that Q4-21 timing or is that solely contingent on the permitting process at this point?

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

Understood. Appreciate the time. Thank you.

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

Hi, good morning. Alan, at the investor day you mentioned the return on invested capital around 12 percent for projects over the last several years. And as you look to sort of allocate capital to the highest returning projects, it seems like for this year it's a mix of Northeast, regulated transmission, well, some deep water where you have some operating leverage. So I guess relative to that 12 percent number, do you see at least in 20 or at least over the next couple of years getting above that 12 percent number or is it just going to be a mix? How should we think about that relative to the 12 percent number you guys have been able to achieve over the last several years?

Yeah, great question. Well, you know, first of all, I would remind you that our individual project returns are often well, in fact, they are well above that number, but that's working against things like deep water declines, declines in basins like the Barnett and certainly deferred revenues step down on things like that. So there is there is a natural decline in some pieces of business that those returns have to offset. And but I would say that our current returns on projects are as good or better than what we've had in our previous mix of projects as we've tightened the capital budget. Obviously, as you tighten the capital, you're you're allocating stuff out. And so I would I would expect that number to continue to be as good or better than we've had on it on an overall number across the whole portfolio.

Thanks, Helen. That's it for me.

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

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

Yeah, that's a good question. And a lot of the capital, we'll start spending some this year, as we mentioned, you know, on things like well. And so in some versus an anchor prospect, I'm just going to give you the kind of the ends of the spectrum here. On one hand, pretty significant capital required on well now because the volumes came in a lot larger than we expected to. And the producers wanted plenty of flexibility in their capacity. And so that project is going to take more capital. On the other hand, anchor, we had laid a sled down when we built that Keefe Canyon connector. We had put sleds down so that we could make those connections fairly inexpensively. And the producers generally are providing that capital. And so in that case, you know, and but we're not going to make return on that invested capital. So we're going to make an existing rate. So in one case, I would tell you, well, very significant revenue contributions and EBITDA contributions that that will be, you know, in the 10 to 15 percent just by itself across the whole deep water. And then and then things like anchor would be inside of that because it's not smaller. You also know, as we've also mentioned, we have Valleymore. It's a very large prospect. That project that Chevron is in there and their partners are trying to decide if it's going to be so big coupled with some other prospects that they have in the area. They have to put a new floater in. If they had to do that, then we would have to invest new capital. The best thing for us is that they find a way to fit that onto blind faith. And that would be pure incremental EBITDA without any new capital. So it's still in the mix. But I can tell you, based on both volume and EBITDA, we think it's very significant in terms of the total percentage increase in the deep water. It is going to be a very significant step up from our current EBITDA levels in the area.

Alan, I ask the question because it's hard for us to give credit for that in evaluation when I have no idea what significant means in terms of EBITDA. I mean, or what the capex is to get there.

Agreed. And I think I would just be cautious on our part. What we have laid out, that could solve the clear, what we have laid out is that our contracts allow us to get the existing rate on our current systems, plus a 12% after tax return on any incremental capital that we spend. So that ought to give you a pretty good read. If you take the rate in the Gulf West area, for instance, you ought to be able to see a pretty nice increase in that. Obviously, we don't like to spell out exactly what our deals are with our customers. So we're not trying to be elusive as much as we are respectful of the relationships that we have with those customers. But if you look at the volume, for instance, on whale and what's been quoted out there, you'll see it looks very much like Perdido, which is what we already gather in the Gulf West. And so this would be effectively a doubling of what we get in the Gulf West there today. So it is very significant. But again, we've got contracts in place that we're not going to lay out exactly what those are. But if you look at total reserve additions versus our current reserves tied up that are out there, you would see that on both the Gulf East and the Gulf West, they were coming close to doubling those connected reserves out there.

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

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

Yeah, great, great question. And certainly, you know, as we mentioned this year, our coverage came up and so our DCF came in quite a bit stronger than we had planned. And certainly those are the things that we're looking at in terms of dividend growth. And certainly as our debt comes down and our interest payments come down, we'll see continued improvement in that as well. So I would say, you know, the capital allocation question remains out there for us as we look at some of these larger transactions that we're going to look to. But the dividend coverage that we have today is allowing us to have excess cash. And so we don't see anything really changing on that front. But as we get into some of these higher growth areas, as we get into 22 and 23 that are not requiring a lot of capital, that's going to build some pretty nice coverage even further than what we have today. So I'm not going to give you a very direct answer on that, frankly, because that's a board level decision in terms of what our growth rate on the dividend is. And I would just say this year, the factors that were considered were how much our DCF had grown and the other uses of capital that were available

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

Yeah. So the biggest impairment we had in the fourth quarter was on Constitution. We weren't depreciating that at this point since it was in construction. So that really had an impact on our depreciation counts.

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

No, I'm sorry. We couldn't quite hear that on this end. Could you try that again?

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

Yeah, thank you. Yeah, we've actually been pretty engaged with the Railroad Commission on this issue and have attended several conferences trying to come up with the right solution. And so, you know, as always, we think the Railroad Commission is going to be very constructive and work to address the concerns that are out there. I would tell you the producer community, I think, for the most part, is being very responsible on that issue as well. And, you know, we were proud to see Chesapeake in there as one of the top producers in terms of limited flaring. And, of course, we provide those services to them. And so that indicates that our reliability is strong when they're not having to flare. That tells you our reliability is strong on our service providing. And so we're proud to see that when our customers are on that list. And so I would just say, you know, we think that there's going to be an effort to both at the regulatory level and both by producers themselves to continue to reduce flaring. And we think that's important for the industry and we are very supportive of that and will continue to push the industry to do the right thing on that front.

Thank you. Those are no questions.

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

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

Thank you, ladies and gentlemen. This concludes today's teleconference. You may now disconnect.