Williams’ second-quarter results met our expectations, as the firm reaffirmed 2023 EBITDA guidance of a midpoint of $6.6 billion, matching our forecast. After updating our model, we will maintain our $32 per share fair value estimate and narrow moat rating. The diversity of the firm’s operations, in our view, really allows it to drive growth in just about any natural gas price environment, including the current weak environment. Quarterly EBITDA increased 8% to $1.6 billion from last year’s levels, primarily due to contributions from the MountainWest and NorTex acquisitions and higher revenues from its Northeast G&P systems (for example, the Ohio Valley Midstream joint venture, the Susquehanna supply hub, and the Blue Racer joint venture). At this stage, the ongoing contributions from new projects and organic volumes should more than offset the expected weaker contributions from gas marketing in the second half of 2023.

The firm’s diverse operations help shield it from gas price weakness and provide it with a large set of growth opportunities. We count at least 12 major supply centers for its gathering and processing operations, with Transco, of course, the major driver on the transmission side. Looking forward, Williams has $7.8 billion of projects in the backlog, stretching across 25 projects (about 10 billion cubic feet per day) with in-service dates through 2031. Transco remains the key growth driver, helped by significant growth expected in U.S. LNG exports. However, several key deep-water projects in the Gulf of Mexico are expected to double William’s deep-water EBITDA (about 5% of the overall firm at this point) by the end 2025.

Williams Companies has shifted its strategy in recent years to focus on organic growth investments that improve its legacy assets' returns and competitive position. This is a positive for investors, creating a more stable financial profile and more high-return growth opportunities than most of its midstream peers. Clean energy investments could become a material growth area in the next few years, with the recent Orsted partnership a particularly attractive growth engine for its Northwest portfolio.

With nearly half of its earnings and cash flow coming from rate-regulated gas pipelines, Williams increasingly looks more like a utility than an energy company with the resulting steady performance through energy market volatility. Williams has expanded its marketing operations with the recent Sequent deal, added storage and transmission assets with the NorTex and MountainWest deals, and bulked up its Haynesville position with the Trace Midstream acquisition. While it is too early to tell with MountainWest (especially as the asset geography differs from Williams' existing assets), the other deals look to be winners.

Most of Williams' growth will continue to be directed toward its Transco gas pipeline, which runs from the Gulf Coast to the Northeast. Transco links low-cost gas supply in the Gulf Coast and Marcellus shale to high demand for retail use, LNG exports, gas power generation, and increasing industrial gas demand. We expect Transco capacity will reach 21 bcf/d by 2024 from 10 bcf/d in 2014 and continue to grow as natural gas demand in the eastern U.S. grows. Transco faces no major competitive threats with over 100 bcf/d in interconnects and material regulatory hurdles for competing projects.

Williams' other businesses demonstrate their favorable competitive positions through volatile energy markets with steady results. The Northeast gathering and processing business has a captive customer base in low-cost regions. The Northwest pipeline benefits from steady demand from utilities in the Western United States. Deepwater is now emerging as a growth area with several projects expected to double overall EBITDA contributions to 10% of EBITDA by 2025 from 5% today.

We have greater than 50% confidence that Williams Companies can generate economic profits on a consolidated basis during at least the next 10 years based on its efficient-scale competitive advantage. Williams owns a number of high-quality assets, including Transco, the Northwest pipeline, and much-better-than-average gathering and processing assets. Taken together, we consider the entire business to be worthy of a narrow moat. We expect adjusted ROICs of 7%-8%, above our cost of capital.

Natural gas pipelines typically exhibit moaty characteristics because of efficient scale advantages and high barriers to entry. Federal, state, and local regulation and high capital costs effectively prohibit direct competition. Williams owns and operates two of the largest and most critical natural gas pipelines in the U.S.: Transco and Northwest Pipeline. These alone contribute 40% of EBITDA. Williams’ total natural gas pipeline business represents more than half of EBITDA.

Transco is one of three pipeline networks (along with Enbridge’s Tetco and Kinder Morgan’s TGP) that supplies most of the eastern U.S. gas demand. This makes it critical to U.S. energy security. Transco operates a 9,700-mile interstate natural gas pipeline with 18.6 billion cubic feet a day of capacity moving gas through Texas and 12 Southeastern and Atlantic states. This represents more than 20% of annual U.S. gas consumption. The pipeline also has about 200 bcf of storage alongside its system generating incremental fees. The Northwest system is equally extensive and supplies nearly 90% of Washington state gas demand (it serves 10 different states in total). The system is made up of 3,900 miles of pipelines with a capacity of 3.8 bcf/d.

Williams’ gas transmission business—including Transco, Northwest Pipeline, and ownership stakes several other high-value pipelines—has classic narrow-moat characteristics. Williams’ gross margins are linked to long-term fixed-fee contracts typically based on capacity, not usage. Thus, customers pay Williams a negotiated rate regardless of how much of the customers’ gas flows through the pipeline. To judge the profitability and durability of these contracts, we assess several factors. Williams scores well on all of these factors:

(1) Demand-pull versus supply-push customers: About 80% of Williams’ margin comes from demand-pull customers. Distribution utilities and power producers represent two-thirds of margin. Utilities are generally price-insensitive (costs are passed to retail customers) and primarily concerned with supply reliability (supply disruptions for utilities can result in regulatory penalties). Another 13% of Williams’ margin comes from LNG or industrial customers that require reliable gas supply to meet supply contracts or production contracts. Only 20% of fees come from supply-push customers such as producers and marketers.

(2) Price differentials: The pipelines with the strongest competitive advantages connect areas with large price differentials. Transco’s link between low-cost Gulf Coast gas supply and high-priced Northeast gas demand allows it to charge high fees for customers to use its pipelines. We expect these pricing dynamics to continue as Northeast gas demand rises due to power generation and residential heating conversions to cleaner-burning gas from emissions-intensive coal and oil. Its other wholly or partially owned pipelines have similar characteristics, connecting low-cost gas supply with areas that have high gas demand.

(3) Regulatory backstop: Federal rate regulation provides a floor for margins if market economics were to turn less favorable. If Williams and its customers can’t arrive at a negotiated rate, they can appeal to the Federal Energy Regulatory Commission to set rates that guarantee a market-based return on capital for Williams.

We also consider Williams’ gathering and processing operations to be moaty, and some of the best G&P assets in our coverage. The assets are extremely well located in the Appalachian region, where we expect substantial production growth over the coming years. Williams probably has a number of long-term (around 10 years) firm fixed-fee contracts with reservations fees, based on what peers have disclosed and the fact that G&P contracts tend to be similar on a regional basis. This dynamic means Williams’ G&P operations resemble a pipeline versus the typical G&P assets under our coverage that operate with less attractive acreage dedication agreements.

We believe these contracts reflect the efficient-scale advantages that accrue to G&P assets in the Appalachian region. We estimate that it costs to 50%-75% more to build a similar-size G&P plant in the Appalachian region than in the Permian. These higher construction costs also apply to transmission pipelines with construction costs in the Appalachian region about twice that of the Permian. However, average midstream prices for exploration and production firms in the Marcellus are nearly 4 times higher on a barrels-of-oil-equivalent basis than the Permian.

We think this level of pricing power speaks to the geographic differences between the two regions, limiting the amount of competition. First, the Permian Basin is located near the epicenter of oil and gas infrastructure in the U.S., and the area has been in production for over 100 years. In contrast, the Appalachian region was relatively underdeveloped until the emergence of the Marcellus in the last decade, so access to key infrastructure and resources is far more limited. Second, there are more practical concerns around construction, increasing costs. The Marcellus is located in the Appalachian Mountains, with rocky terrain, making it harder to construct even smaller gathering pipelines (clearing land, elevation changes, difficulty digging), whereas the Permian Basin has a relatively flat topography. Third, weather is a consideration, not only for construction efforts but ongoing operations, as precipitation in Midland, Texas, is about 15 inches annually, with 5 inches of snowfall annually, while Birmingham, New York, averages 39 inches of rain per year and 83 inches of snow.

Williams’ G&P business enjoys advantages in certain areas such as the Utica Supply Hub and Bradford and Susquehanna counties, where its market share is around 90%. Williams collects about a third of overall gas volumes across the Appalachian region. In other areas, Williams’ market share could be below 20%. Recent deals to consolidate production acreage and boost captive volumes should improve the competitive position of Williams' smaller G&P assets.

From a contract coverage perspective, we believe Williams operates similarly to peers with long-term contracts for its pipelines (15-20 years) while using a mix of acreage dedication agreements and fixed-fee contracts for its gathering and processing operations. Acreage dedication agreements can be 10-20 years; however, we believe they are low-quality contracts because they depend on the availability of producers’ capital and well economics. If the acreage is never developed or produces relatively little, Williams’ fees and returns are correspondingly lower, and these contracts form the lion’s share of the impairments the entities have taken over the past few years. Williams’ Northwest system has contracts average about 10 years in remaining life, and about 80% of the pipeline’s capacity is contracted by demand-driven utilities and end users.

Incremental investments for nonregulated pipelines to connect to its larger regulated pipelines would be supported by contracts necessary to recover the capital cost. Williams’s G&P contracts range from simple fees based on volumes, keep-whole contracts, and percentage of liquids, where Williams takes ownership of the NGLs extracted and is exposed to NGL price movements. While the volume-based fee exposure is beneficial, we note that a large producer, Chesapeake, was able to convert its G&P contracts to a percentage of Henry Hub prices, which is more favorable to Chesapeake, from a minimum volume contract when its financials were under pressure. That said, sometimes Williams can obtain minimum volume commitments for its G&P assets where it is particularly well positioned in terms of takeaway capacity.

Over the next decade, we expect gas transmission earnings to reach nearly two thirds of consolidated earnings. This is consistent with our view that U.S. gas demand will continue growing for at least the next decade due to exports and power generation. Pipeline extensions or expansions have high incremental returns on capital because each new end point of supply means more customers paying for the core Transco network. It also creates more customers bidding for increasingly scarce capacity. We estimate Williams can consistently invest at 6 times EBITDA for mid- to high-teens returns. Regulatory and geographic restraints on competitors remove incentives to build similarly situated pipelines to compete with Transco’s expansion.

Material environmental, social, and governance exposures create additional risk for midstream investors. In this industry, the most significant are greenhouse gas emissions (from upstream extraction, midstream operations, and downstream consumption) and other emissions, effluents, pipeline spills, and opposition and protests. In addition to the reputational threat, these issues could force climate-conscious consumers away from fossil fuels in greater numbers, resulting in long-term demand erosion. Climate concerns could also trigger regulatory interventions, such as production limits, removal of existing infrastructure, and perhaps even direct taxes on carbon emissions.

Midstream emissions are relatively low in the life cycle of oil and gas, and midstream firms have relatively lower risk than upstream and downstream firms from carbon taxes. Canadian firms already pay carbon taxes on their carbon emissions, most of which are generally passed to their shippers and other customers. Spills represent a major threat and have created great resistance from environmentalists, Indigenous groups, and other climate-conscious people. Examples of the opposition are seen in President Joe Biden’s revocation of the Keystone XL presidential permit and the legal challenges with the Dakota Access Pipeline system.

Williams has laid out some of the more aggressive targets on greenhouse gas emissions compared with U.S. midstream peers. Williams plans to reduce Scope 1 and 2 emissions on an absolute, not intensity, basis by 56% by 2030 from 2005 levels. It has also committed to net zero emissions by 2050. We consider its $1.3 billion emissions-reduction capital spending through 2026 as something that helps Williams stand out from its U.S. midstream peers. The investment includes the replacement of compressor stations, which will reduce methane emissions by over 50% and other types of emissions by over 75%.

After updating our model for second-quarter earnings, we are maintaining our fair value estimate at $32 per share. Our fair value estimate implies a 2023 enterprise value/EBITDA multiple of 9.3 times and a 2023 EBITDA multiple of 9.2 times. We now expect EBITDA to reach $6.6 billion in 2023, primarily due to contributions from the MountainWest and NorTex

acquisitions and higher revenue from its Northeast G&P systems (for example the Ohio Valley Midstream joint venture, the Susquehanna supply hub, and the Blue Racer joint venture).

The major valuation driver for Williams is the Transco system. Not only do we expect pipeline volumes to continue to ramp up as Williams executes on its multi-billion-dollar expansion program, but also we expect it to be able to increase fees. With the Atlantic Coast Pipeline cancellation in July 2020, we now think Transco can boost its capacity and throughput by 5%-7% annually on average during the next five years.

Williams’ Northeast gathering and processing assets also should realize higher volumes and fees in the long run based on their location in low-cost producing basins with captive customers. We expect double-digit growth in the near term. We expect a rebound in pricing over the next few years with steady 3%-4% increases.

We assign a Morningstar Uncertainty Rating of Medium to Williams. The primary risks facing Williams include natural gas demand and production volumes. The firm's gathering and processing operations are most exposed to changes in drilling activity depending on basin economics. The long-haul pipelines are exposed to long-term natural gas demand. Falling U.S. natural gas demand would crimp Williams’ performance and returns on projects.

After adjusting its portfolio and customer mix during the last few years, about two-thirds of Williams' earnings come from power generators or gas distribution utilities typically on fixed-fee contracts. Williams reports 90% of its customers have investment-grade credit ratings. That is a big shift from several years ago when upstream energy companies, notably Chesapeake, were large customers.

If capital markets freeze up, Williams will struggle to fund new projects. Like many yield-oriented investments, Williams is exposed to interest-rate risk. If interest rates increase, Williams shares could underperform, as a steepening yield curve increases the value of competing income alternatives.

Williams faces ESG risk given its primary business involves handling fossil fuels. Williams has offset some of its environmental risk by focusing on natural gas, which has a lower carbon-emissions profile than oil or coal, especially for retail and power generation use. Williams also plans to spend more than $500 million during the next few years investing in renewable natural gas, hydrogen, and solar to reduce its total carbon footprint. Management has set what we consider ambitious targets to reduce the company's greenhouse gas emissions by 56% by 2030 and reach net-zero emissions by 2050.

We assign Williams a Standard capital allocation rating based on management's moves in the last few years to simplify the corporate structure, balance sheet, and growth strategy.

We think Williams' current strategy focusing on natural gas transportation, gathering, processing, and marketing is a positive for shareholders. Management faces a key test in the coming years as organic growth investment opportunities become scarce and free cash flow grows. The board's $1.5 billion share repurchase plan is welcome news as it signals that management is willing to return more capital to shareholders, and the firm is starting to

buy back some shares in 2023. In the second quarter of 2023, it bought back $56 million in shares.

The 2018 consolidation of Williams Partners turned the company into one of the few midstream C-corps with a qualified dividend. This gives Williams access to a wider investor base than its master limited partnership peers and results in a lower cost of capital. Management now operates the company more like a utility, prioritizing consistent cash flow and disciplined capital investment. Williams' recent efforts to invest in renewable energy, including the Orsted partnership, position it to be an early leader among its U.S. peers. The firm has outlined a decade-long series of projects under development related to LNG, industrial gas demand, and power generation opportunities, a time frame that is materially longer than most of our U.S. midstream coverage, providing additional confidence in long-term demand for Williams' assets.

The recent deal for Sequent appears to be a winner, with the area enjoying strong profits in 2022 due to the wide spreads available in the market, and Williams recently added to its gas storage and marketing position with the NorTex deal. This looks to be a profitable move in 2023 with still fairly wide spreads available. Similarly, we think the Trace Midstream deal has allowed Williams to capture growth in the Haynesville play as producers seek to ramp up production there. We think the MountainWest deal looks like a reasonable price, but in order for it to be a real winner, we need to see multiple attractive projects at very low capital cost that can generate incremental volumes. With less of a clear geographic overlap with Williams' existing asset portfolio, this will depend on Williams' ability to source new projects and good execution.

Management has overcome a series of moves during the past decade that turned sour for shareholders. Midstream acquisitions at the height of the 2012-14 U.S. energy market cycle resulted in more than $7.5 billion in impairments. Some of those assets continue to have challenging economics but are shrinking as a share of the total business. With growth investment dedicated to its legacy gas pipelines and the bulk of its assets tied to fixed-fee contracts, the marginal gathering and processing assets have a minimal impact on total company returns. The collapse of the Energy Transfer merger in 2016 has been a positive for Williams shareholders given the opposite direction the companies have headed.