Good day, everyone, and welcome to the Williams Second Quarter 2021 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. Danilo Juvane, Vice President of Investor Relations. Please go ahead.

Thanks, Mishawna, and good morning, everyone. Thank you for joining us and for your interest in the Williams Company. Yesterday afternoon, we released our earnings press release and the presentation that our President and CEO, Alan Armstrong; and our Chief Financial Officer, John Chandler, will speak to this morning. Also joining us on the call today are Micheal Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our Senior Vice President of Corporate Strategic Development. In our presentation materials, you'll 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 the presentation materials are non-GAAP measures that reconcile to generally accepted accounting principles, and these reconciliation schedules appear at the back of today's presentation materials. So with that, I'll turn it over to Alan Armstrong.

Good morning, and thanks, Danilo, and thank you all for joining us today. Our long-term strategy of connecting the fastest-growing natural gas markets with the best supplier continues to deliver solid financial results as demonstrated by our strong second quarter financials across our key metrics. Our stellar results this year were supported by equally strong fundamentals that demonstrate how sticking to this strategy has put us in an enviable position. As evidence, Williams gas gathering volumes grew 6% in the first half of 2021, while the U.S.'s natural gas production volumes actually declined by 0.4%, continuing to prove that our assets are in the low-cost basins. We expect a constructive natural gas macro backdrop to continue to drive significant value for our business. Recent commitments to Transco market area expansions coupled with producer commentary on Transco projects such as our Leidy South and Regional Energy Access projects are clear pathways to growth for our Northeast gathering volumes for years to come. We will walk through more details of our business in just a moment, but I want to first call attention to our 2020 sustainability report, which we just published last week. As this report details, we are making headway on critical ESG-related fronts. For example, becoming the first North American midstream company to set a near-term climate goal based on right here, right now emission reduction opportunities and making steady progress on developing our leaders for the future. We're also looking to the future as our nationwide infrastructure footprint is well suited and adaptable to renewable energy sources like clean hydrogen and RNG blending. Williams' ongoing focus on sustainable operations positions us well to meet clean energy demand for generations to come. In fact, we are now up to 7 renewable natural gas sources flowing into our gas transportation systems, and we have 9 more that are in progress. I hope you can find some time to visit our website and read our new sustainability report. But right now, let me turn things over to John Chandler for a review of our 2Q and year-to-date results.

Thanks, Alan. To summarize the quarter, we saw notable increases in profitability from our Northeast gathering systems, higher revenues on our Transco pipeline due to new projects initiated last year, and contributions from our upstream operations in Wamsutter. However, these gains were slightly tempered by increased operating expenses tied to higher incentive compensation, reflecting our strong performance this year. As shown in our statistics, we achieved improvements in our key financial metrics. Our adjusted EBITDA for the quarter increased by $77 million, or 6%, and we recorded a 9% rise in EBITDA year-to-date. We will delve into the details of EBITDA variances shortly. Adjusted EPS rose by $0.02, or 8%, and AFFO for the quarter grew in line with our EBITDA growth. AFFO, which represents cash from operations including joint venture cash flows but excluding working capital fluctuations, amounted to $1.948 billion year-to-date, against $737 million in capital investments and $996 million in dividends, resulting in approximately $250 million of surplus cash year-to-date. Notably, $160 million of maintenance capital is included in our capital investments. Additionally, our dividend coverage, calculated as AFFO divided by dividends, stands at a healthy 1.96x year-to-date. The solid cash generation and robust EBITDA for the quarter, coupled with our disciplined approach to capital, have allowed us to surpass our leverage metric goal, now sitting at 4.13x debt-to-EBITDA. Later in our guidance update, you will see we have revised our yearly guidance to below 4.2x debt-to-EBITDA. Overall, we are seeing strong performance for the quarter and year, and we are positioned well for a strong second half. Now, let’s take a closer look at our EBITDA results for the quarter. Williams performed admirably, with upstream operations contributing $19 million of additional EBITDA from the Wamsutter area this quarter. We fully owned the BP Wamsutter acreage throughout the quarter but had Southland acreage for only one month. Combined production from these assets was 6.9 Bcf for the quarter. Meanwhile, the Haynesville upstream acreage generated minimal EBITDA due to limited PDP reserves, necessitating time for new production and subsequent EBITDA. Moving to our Transmission & Gulf of Mexico assets, we achieved results that were $31 million higher than the previous year. New transmission pipeline projects added $25 million in incremental revenues compared to last year’s second quarter, including contributions from the Southeastern Trails project and part of the Leidy South project, both of which started service last fourth quarter. This growth is reflected in our firm reserve capacity, which increased by 5% from the second quarter of last year. Additionally, revenues from the Gulf of Mexico improved somewhat due to fewer shut-in issues compared to last year. Commodity margins from processing Gulf of Mexico gas reached around $5 million due to increased NGL prices and higher volumes. These revenue gains were partially offset by a modest rise in operating expenses, mainly due to employee-related costs, particularly higher incentive compensation accruals. The Northeast G&P segment continued to perform strongly, generating an additional $46 million of EBITDA this quarter. Total Northeast gathering volumes grew by 750 Mcf a day, or 9%, compared to last year, while processing volumes surged by 33%, setting a new record. This volume increase was largely due to our joint ventures in the Bradford Supply Hub and the improved productivity in our Marcellus South supply basin. To clarify, as we do not operate Blue Racer Midstream, its volumes are not included in our statistics. However, this growth allowed our EBITDA from equity investments to improve by over $36 million, including additional profits from our increased stake in Blue Racer Midstream acquired last November. In contrast, our West G&P segment saw a decline of $21 million compared to last year. Notably, we had agreed to reduce gathering rates in the Haynesville in exchange for upstream acreage in the South Mansfield area. Although we have not yet seen returns from those upstream assets, we have identified an operating partner for development. The impact of this gathering rate reduction was about $15 million for the quarter. Moreover, we experienced a $9 million reduction in EBITDA due to a deficiency fee received from One Oak last year related to OPPL, which allowed them to defer volume submissions to OPPL. This year, One Oak does not have that volume obligation, resulting in an absence of such revenue. We also saw a $9 million decline in deferred revenue from our Barnett Shale gathering assets, representing a noncash reduction in revenues. Excluding these three negative factors, our West assets were up $12 million compared to last year’s second quarter, driven by improved NGL margins as our commodity marketing group benefited from higher NGL prices. Overall, although gathering volumes in the West dipped by 3.5% compared to last year’s second quarter, the rise in rates more than compensated, particularly as our contracted rates are influenced by commodity prices in the Piceance and Barnett regions. Moving to year-to-date results, we are reporting a $230 million increase in EBITDA, roughly a 9% rise, fueled by Winter Storm Uri in Q1 and other favorable factors affecting Q2 growth. Our marketing activities and upstream operations in Wamsutter contributed a combined positive impact of $77 million from the storm. Furthermore, our upstream operations have added an additional $27 million year-to-date. The Transmission & Gulf of Mexico assets are up $22 million year-to-date or about 2%, courtesy of increased revenues from new transmission projects and better performance in Gulf of Mexico revenues tied to reduced downtime this year. These upsides were partially balanced by lower revenues attributed to one fewer billing day on a regulated transmission pipeline and rising expenses compared to last year, which had been impacted by COVID-related delays. Our North G&P assets increased by $78 million, primarily due to profits from joint venture investments in the Bradford Supply Hub and Marcellus South gathering systems, complemented by our increased stake in Blue Racer Midstream. Year-to-date gathering volumes in the Northeast rose by 10%, and processing volumes surged by 24%. Lastly, our West E&P segment increased by $23 million year-to-date, on top of the $55 million earned from Winter Storm Uri. This growth stemmed from enhanced commodity margins and lower operating costs, though offset by reduced Barnett deferred revenues, lower Haynesville gathering rates traded for upstream acreage, and the absence of OPPL deficiency revenues noted earlier. While we did see a 5% decline in gathering volumes year-to-date, this was effectively counterbalanced by market conditions and raised gathering rates as mentioned. We are indeed on track for a very successful year. I'll now hand the call back to Alan to discuss a number of key areas of interest for investors.

Thanks, John. We are now going to discuss the key areas of focus for investors as outlined on Slide 4. First, concerning our financial expectations, we are on track to achieve EBITDA near the upper end of our recently updated guidance range from the last earnings call. The strength of our business has supported our financial performance and helped us exceed our previous leverage goal of 4.2x. Consequently, we received a rating upgrade to Baa2 from Moody's, placing us at a BBB equivalent rating among the three major rating agencies. Our outlook for free cash flow in 2021 remains unchanged, and our long-range plan, shared during our latest Board strategy session, anticipates ongoing steady growth in EBITDA and improvements in our credit metrics. Notably, the long-term strategy indicates that even after investing in growth opportunities, our business is set to generate substantial excess free cash flows, enabling a robust capital allocation strategy to enhance shareholder returns, including possibilities for share buybacks, so stay tuned for updates on that. Next, regarding our recent transactions and project developments, firstly, we commend our team on the upstream joint ventures. As we announced last month, we finalized an upstream joint venture with Crowheart in the Wamsutter basin, combining our legacy BP Southland and Crowheart upstream assets into a single footprint of over 1.2 million acres. This consolidation is crucial for developing these assets efficiently, which is vital for our upstream business and midstream operations by leveraging existing capacity. Recently, we also established a joint venture with GeoSouthern in the Haynesville, which brings several benefits: it unlocks midstream value for Williams through GeoSouthern’s commitment to develop the South Mansfield acreage, where they'll cover part of our drilling costs while increasing ownership in the leaseholds as they meet development milestones. Additionally, this partnership allows us to optimize natural gas production in the region through fixed fee agreements from our Sequent business and opens future development opportunities near Transco, enabling us to source and deliver responsibly-sourced natural gas to the expanding LNG market. Both of these joint ventures enhance our value in the Wamsutter and Haynesville basins by collaborating with strong local operators, driving property development towards increased volumes for our midstream and downstream operations. From a project execution perspective, we are successfully advancing several areas, including launching key projects like Leidy South, which is set for early service before the winter heating season. Furthermore, Transco has visible growth prospects, and we have secured customer commitments for two new market expansion projects in the Mid-Atlantic region. Transco also has significant potential for low-risk growth through rate-based modernization projects. In the deepwater Gulf of Mexico, we have made substantial progress, recently finalizing agreements for the Shenandoah and Whale projects which are expected to significantly increase EBITDA starting in 2024. On sustainability, I referred to our sustainability report at the beginning of the call and mentioned our recent carbon emissions disclosure submission to the Carbon Disclosure Project. We are actively using our natural gas-focused strategy and existing technologies to address immediate emission reduction opportunities. Additionally, our natural gas infrastructure supports the next generation of clean energy technologies. Renewable energy boosts will face two primary challenges: the transmission and storage of energy. There is no other energy infrastructure that combines a reliable delivery network into crucial population centers with extensive storage capabilities equivalent to natural gas transmission. We believe our infrastructure plays a pivotal role in both short- and long-term solutions. We are progressing with our solar projects announced last year, and I am happy to report that six projects are awaiting approval from the grid operator, with another ten set to seek the same regulatory approval by the end of this year. These 16 projects represent a total capital expenditure of about $250 million and are anticipated to generate cash flows starting in 2023. Additionally, we have roughly $150 million in comparable projects under development. We are eagerly looking ahead for innovations and technologies to enhance our energy networks to support our country's clean energy future. In collaboration with the University of Wyoming, we recently received a $1 million grant from the State of Wyoming to conduct a feasibility study for establishing a green hydrogen hub near our operations in the state, exemplifying our efforts to leverage our existing assets for clean energy solutions. In Wamsutter, we have dedicated 1.2 million acres to midstream assets through the Crowheart joint venture, along with around 200,000 acres where we control surface rights, aimed at facilitating clean energy development. In summary, our strong commitment to a natural gas-centered strategy has established a steady, predictable business with continued growth, improving returns, and significant free cash flow. This has resulted in a solid balance sheet and a well-supported, growing dividend. Our top-tier long-haul pipelines, Transco, Northwest Pipeline, and Gulfstream, are strategically located in optimal markets. Additionally, our strong gathering assets are situated in low-cost basins that will meet the growing gas demand. We maintain a positive outlook on natural gas due to its crucial role in the transition to a clean energy future. Natural gas is essential in today's energy mix and should be emphasized as a vital tool for significantly reducing more carbon-intensive fuels globally. Our networks are essential for meeting both domestic and international energy needs in a low-carbon and economically sustainable way. With that, I will now open the floor for your questions.

Your first question comes from Jeremy Tonet with JPMorgan.

I was just wondering if you could start off a bit expanding on your thoughts on the current gas macro outlook, and whether that backdrop drives the higher end of guide expectation. How does this position your trajectory into 2022 at this point?

Yes, certainly. Jeremy, as you are aware, the recent increase in prices and ongoing demand growth is starting to exert pressure and stimulate the forward markets. We are definitely observing reactions from our producers who are eager to capitalize on this trend. The Haynesville area is likely to see the quickest response, given the significant drilling activity that is ramping up there. Additionally, you may have noted the strong response to price increases from Cabot in their recent earnings call. We're also observing robust reactions in the Southwest, as well as in the Marcellus and Utica regions. It's important to emphasize that this situation is not solely a production issue; demand is continuing to rise. Comparing the second quarter this year to 2019's second quarter, we've seen demand grow by 9%, and compared to the second quarter of 2020, the growth was about 5.6%. Thus, there is consistently strong demand growth, and we are seeing prices adjust accordingly. From our perspective, as we've stated before, demand is what will drive our business, and prices will fluctuate as necessary to maintain balance, but ongoing steady demand growth is evident. As we experienced last year, we do not anticipate any impact from COVID or its resurgence on this trend. The natural gas market is exhibiting healthy growth. Looking ahead to 2022, it is challenging to predict future gas demand, but the current fundamentals appear strong, and we are witnessing a positive response from producers.

Got it. That's helpful. I realize I might be getting a bit ahead of myself, but regarding buybacks, I'm curious if Williams has authorized a buyback plan. If not, what would be needed to authorize it? If you were to consider buybacks, would a generally opportunistic approach make the most sense, or would a systematic method that allocates a percentage of cash flow each year be preferable? I’m interested in your current thoughts on buybacks in this regard.

Yes, Jeremy, thank you. I anticipated that question. I'll address it directly. We had a significant discussion with the Board last week, and what stood out the most was the continued generation of free cash flow, even with our commitments to growth capital and ongoing deleveraging alongside the growth in EBITDA. This allows us to fund both rate base investments and new energy ventures while still showing a substantial excess of free cash flow. That’s likely the main takeaway. We're currently working with our Board to outline a buyback program with specific parameters. The recommendation will be opportunistic, but it will also be structured regarding appropriate pricing levels and underlying drivers. From my perspective, it will probably be linked to where our debt is trading. Our debt has remained stable while stock prices fluctuated. There will be instances where market volatility occurs, similar to what we experienced in March and April last year, but, generally, the debt markets have been consistent even as stock prices have varied. This will help identify the right times for stock acquisitions. The program will have defined parameters; it won't be random, and it will consider both size and drivers. We may not disclose the specific debt multiples, but that’s our current outlook. We do plan to announce the program once we finalize the details with our Board.

And Jeremy, probably I'm self-evident here, but what Alan is really referring to is our dividend yield in relative comparison to where our debt trades at.

To follow up on Jeremy's question, Alan, in your remarks, you mentioned that your projections to the Board indicated an increase in EBITDA along with a decrease in leverage. Should we interpret this as needing to reach a new leverage target, or is it more accurate to consider that some of the excess cash flow will be used for reducing leverage while another portion will be allocated for buybacks, possibly in a 50-50 split or as opportunities arise? Is that how we should understand it? I'm trying to align those statements.

I think the simplest way to view this is that as our EBITDA continues to grow and we maintain our current debt level, our credit metrics improve accordingly. It's important to understand this dynamic. This improvement in our credit metric will be the main factor here. We'll manage and make decisions about this appropriately as we move forward, but we have a considerable amount of excess cash flow that enables us to pursue our goals. This includes ongoing dividend growth, further improvements in our credit metrics, and investments in our asset base and new energy projects. We can achieve all of this while still having substantial capacity for share buybacks when opportunities arise. The key takeaway is that our cash flow is robust, allowing us to invest in various initiatives that enhance shareholder value.

Alan, first one for you. In the past, you've expressed interest and a willingness to work with the current administration on energy transition and emissions goals. Curious what receptivity you've had early on in demonstrating natural gas' role in the transition. And what you see is maybe still some of the hurdles or areas where there's a gap of opinion on how you approach reducing emissions over the long term.

Yes, it's an interesting time right now because there's a significant focus on emissions reduction. People are beginning to realize the cost implications for consumers. As a result, there is a shift back to considering what is practical and feasible. This is where Senator Manchin comes in, emphasizing the importance of natural gas for West Virginia and the nation, as well as for job creation. He acknowledges the necessity of addressing these challenges sustainably and economically, or else we risk losing jobs and industries to other countries. There seems to be a reconciliation happening between the rigorous focus on carbon reductions and the need for sustainable solutions that keep us in control of our economic future. Natural gas is well positioned as these two priorities converge and seek sensible solutions that we can implement now. I'm noticing a growing awareness of the costs associated with these solutions, both in terms of direct costs to consumers and reliability. The discussions are becoming more pragmatic as people start to define solutions, and I believe natural gas is in a stronger position than I initially anticipated, as more individuals are recognizing its impact on consumers.

Maybe if I could just get a clarification on the leverage. What is the long-term ownership percentages for both Haynesville and the Wamsutter? What sort of timelines are we thinking about? And how should we think about how the upstream contributions are factored into the leverage calculation? Is 4.2x still the right target? And is there any change to how the rating agencies view that?

I don't think there's any change. I would just tell you, Christine, that the metrics are coming down again pretty naturally. And the cash flows start to roll from the upstream to the midstream pretty rapidly over the next 3 years. And so it does take a little bit longer in the Wamsutter. The development in Haynesville is pretty quick. So it rolls over to that pretty quickly. And certainly, the rating agencies are well aware of our strategies and design on how we get there. So John, I don't know if you got anything to add.

No, I think that's correct. The deals in the Haynesville and Wamsutter are structured to help us reduce our interest. As Alan mentioned, the Wamsutter provides us with a more significant position, meaning our interest will be larger for an extended period. Whether this interest ultimately shifts to our partner or is sold, we do not intend to stay in the upstream business long-term; we aim to leverage this for midstream value. The future of Wamsutter is uncertain, while the Haynesville is clear that if the drilling goes as we expect within a 2- to 3-year timeframe, it will transition to midstream value. Currently, our credit metrics are strong, and our dividend coverage and cash flows are solid. We've discussed this with rating agencies, and I don’t sense any concerns. As Alan highlighted earlier, we do expect growth in our EBITDA, which will facilitate natural deleveraging and allow us to pursue additional initiatives while still improving those metrics. The rating agencies are aware of these numbers.

Just kind of switching gears for a second. I was wondering if you could comment broadly on the RNG business. I know in the past, you've been a little reluctant to invest in the actual RNG facilities. But now some of your peers are moving more aggressively into the space. So I'm just curious whether your views or strategy on RNG have changed at all.

Yes, this is Chad again. We are open to investing in RNG aggregation and processing if it is financially viable. Similar to our approach with hydrogen, we see our strategic advantage in this area. We have been assessing our footprint and identifying sites that could provide attractive economics for RNG capture, processing, and delivery. Although we find this opportunity set appealing, it is relatively limited in scale, with potential investments amounting to a few hundred million dollars. We are currently evaluating several projects where we could invest in the aggregation and processing of these volumes. So far, our projects have mostly involved interconnections with our existing infrastructure. The technology needed for these investments is quite straightforward. However, this area relies heavily on LCFS credits and RINs, and we intend to be disciplined with our investments. We are not planning to base our entire business strategy on heavily subsidized economics. We believe there is potential for significant value due to our strategic footprint, and we can invest at a modest level. Because of our reliance on LCFS credits, we are focusing on opportunities that promise a quick payback on our investments, leading to attractive returns that enhance our confidence in these initiatives.

Yes. I would like to add to the discussion about the subsidies. The low carbon fuel standard and the renewable identification numbers are significant factors in those projects. It's important to focus on the impact of the LCFS program in California, especially regarding the sustainability of the credits and subsidies available. We need to ensure that we're not overinvesting in those risks. While we may explore ways to monetize these opportunities initially or allow others to absorb that risk, it's crucial to monitor this situation closely. When considering all the projects involving carbon capture related to ethanol and the associated research and development costs, the figures become substantial. This is a key aspect to watch as an investment.

No, Christine. This is Micheal. Those outages that occurred were very short-lived. Ironically, both major operators in the area were facing some challenges at the same time, which were resolved quickly. So we didn't gain any advantage, nor did our competitors during that period. However, this could set a new run rate for us since our Oak Grove TXP III project came online in the first quarter, and we have fully utilized that project in the second quarter, currently operating at maximum capacity for the most part. We're exploring opportunities to connect with our Blue Racer facilities to leverage some potential lease capacity they may possess. There's a chance to redirect a significant amount of gas to our facilities, including our UEO that we acquired a couple of years ago, as well as the Blue Racer facility, which we intend to optimize. We're witnessing a lot of active producer activity from EQT, Southwestern, and Encino, a private operator, as they pursue those liquid-rich well pad drill outs. This is driving a lot of activity, and we're pleased that our processing capacity is not at full capacity.

The answer is yes. This year's capital expenses have been driven by upstream acquisitions and the Sequent acquisition. Some of these acquisitions are still part of the spending range we've outlined. Next year, we expect to complete Leidy South, with most of the capital spending occurring in the fourth quarter of this year. Looking ahead, we hope to begin spending toward the end of the year on Regional Energy Access, pending the permitting process, with much of that spending planned for 2023. Additionally, spending for the Whale project will also begin in 2023. Overall, it appears that capital spending will remain fairly steady, with this year's spending slightly higher due to our acquisitions, and we anticipate continued expansion in many of the projects we have discussed.

The math is quite straightforward. Using our guidance midpoint as a starting point, aside from capital, we anticipate being at the higher end of the capital range. We're spending approximately $1.2 billion on expansion capital and $500 million on maintenance this year, totaling $1.7 billion while still deleveraging. Next year, we expect EBITDA growth, although we are not providing specific guidance on that today. However, if we apply a 4x multiple to any EBITDA growth, it would still allow us to leverage from a 4.13 level today. Thus, any reasonable amount of EBITDA growth would add significantly on top of the $1.7 billion we are spending this year. This reflects our confidence in anticipating EBITDA growth, which will lead to an increase in investable capital while still enabling deleveraging from a ratio perspective.

Yes, I think that's well put, John. It's, I think, also a great example of creating a win-win for us and our customer. Chesapeake has been able to increase activity. And we, this time last year, Chesapeake was still not running rigs in the Haynesville. With the fee reduction that we offered, they now have 3 rigs running in their Springridge area. And so the fee reduction has incentivized significant activity that will show up on its own as incremental earnings over time. But also, as John mentioned, through the South Mansfield transaction, we see that as virtually tripling the value of that give back from an NPV perspective. So really, with Chesapeake made the pie much larger, and we're both able to benefit from that transaction. Okay. Well, thank you all very much. Continued great success here in '21. Teams continue to hit on all cylinders. And importantly, even though we've got great growth here in '21, what we're really excited about is how we're positioned now for the future with a number of very important drivers for growth here in the future that will show up in '22 and beyond. So really setting a nice platform for growth for our business for years to come. So we thank you for your attention today and the great questions, and we'll speak to you again soon.

Ladies and gentlemen, this does conclude today's conference call. You may now disconnect.