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%.