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Midstream Energy Offers Moats at a Discount

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The midstream oil and gas industry has long been one of Morningstar’s classic examples of an efficient scale moat source. Of the 25 midstream firms Morningstar covers, 19 have an economic moat, and 17 have an efficient scale moat source. An efficient scale market exists when a market of limited size is effectively and efficiently served by one firm or a small number of firms. Would-be competitors are discouraged from entering because doing so would drive market returns below the cost of capital. As the oil and gas pipeline industry is made up of numerous regional markets and further stratified by the quality and type of hydrocarbon transported between specific locations, it is clearly an efficient scale market.

Hydrocarbons are produced and consumed in different places and in different forms from how they come out of the ground. Midstream firms transport and process hydrocarbons. Once a transport route is established, there’s usually little need to build a competing route. Doing so would drive returns for both routes below the cost of capital. Thus, pipelines are generally moaty because they efficiently serve markets of limited size.

New pipelines are typically constructed to allow shippers or producers to take advantage of large price differentials (basis differentials) between two market hubs because supply and demand is out of balance in both markets. Pipeline operators will enter into long-term contracts with shippers to recover the project’s construction and development costs, in exchange for a reasonable tariff that allows a shipper to capture a profitable differential, and capacity will be added until it is no longer profitable to do so.

Pipelines are approved by regulators only when there is an economic need, and pipeline development takes about three years, according to the U.S. Energy Information Administration. Regulatory oversight is provided by the Federal Energy Regulatory Commission and at the state and local levels, and new pipelines under consideration have to contend with onerous environmental and other permitting issues. Further, project economics are locked in through long-term contracts with producers before breaking ground on the project. If contracts cannot be secured, the pipeline will not be built.

A network of pipelines serving multiple end markets and supplied by multiple regions is typically more valuable than a scattered collection of assets. A pipeline network allows the midstream firm to optimize the flow of hydrocarbons across the system and capture geographic differentials, use storage facilities to capture price differentials over time, and direct more hydrocarbons through its system via storage and gathering and processing assets, ensuring security of flows and higher fees. Finally, it is typically cheaper for an incumbent pipeline to add capacity via compression, pumps, or a parallel line than it would be for a competitor to build a competing line.

Midstream moats have primarily been destroyed via changes in oil and gas flows. This occurs when demand or supply for a given hydrocarbon disappears at one end of the pipeline because of poor drilling economics or a change in market dynamics that makes it more economic to send the hydrocarbons elsewhere. In recent years, this has occurred more frequently with the changes in geographic pipeline flows across the U.S. due to the increase in production from tight oil and gas plays such as the Permian and the Marcellus/Utica. For example, moving oil from the Gulf Coast north to Midwestern refiners has become uneconomic on the Capline pipeline, and its operators are now seeking to reverse the pipeline to move oil south to be exported from the Gulf Coast. Also, growth in gas production from the Marcellus/Utica region has increasingly displaced gas imported from other Eastern states, forcing the massive Rockies Express pipeline to spend the past few years actually seeking to move more gas westward instead of its original plan to move gas east.

Given our expectations for costs and drilling opportunities by basin over the next few decades, we don’t anticipate another monumental geographic shift in U.S. oil and gas production similar to the shale revolution. As such, we don’t forecast big changes in the direction of hydrocarbon flows.

Moat Consideration Number 1: Asset Quality
The major consideration for assessing evidence of a moat for a midstream firm is asset quality, where we consider the firm’s competitive strengths and assets within the efficient scale regional markets they serve. Asset quality is evaluated based on the location of the individual assets, the type of asset (for example, pipeline versus gathering and processing), the cost-competitiveness of the basins the assets serve, capital intensity, and the overall quality of the network. Basin cost-competitiveness is important as pipelines are likely to remain relevant longer if connected to a low-cost hydrocarbon supply. Further, some of the highest-quality midstream firms have a dense network of assets that connect to key refineries, basins, and market hubs and are a reliable transportation provider for shippers. This connectivity encourages shippers to use the pipelines but also protects the midstream entity. The asset integration prevents another third party from extracting rents by owning an asset that is part of the route to the most profitable market. Because differentials between the regions where the hydrocarbon is produced and delivered can fluctuate substantially over a short time frame, delays in delivery can be costly, particularly if there are relatively few options to reach a particular market. These type of temporal specificities can be exploited by the midstream firm by owning storage assets, for example, and it can prevent a third party from taking advantage of it by owning assets at each part of the value chain.

Midstream Entities Are More Than Just Pipelines
Midstream firms are typically characterized as pipeline operators. While pipelines are an important part of the industry’s operations and moats, many midstream partnerships own many different types of assets. These major assets can be grouped in the following categories: gathering and processing, oil, gas, and natural gas liquids pipelines, fractionation, refined product pipelines, and marketing and related logistics activities, which would include storage. We think the degree of competitive advantages varies by asset type, as the competitive dynamics for each asset are different, particularly as midstream entities own different assets across the entire midstream value chain.

Beyond ownership of assets across the midstream value chain, we note that many of these assets are situated at market hubs. Storage, fractionation, railcars and trailer tank cars, petrochemicals, and export assets are all typically located at centralized locations where, depending on the size of the individual hub, one to several midstream firms would own the majority of the assets. The geographic and physical closeness of assets along the value chain makes it more likely that a single midstream firm can control the delivery of the molecule to and from a market hub, earning multiple fees and capturing time differentials based on storage ownership.

Gathering and Processing Is Weakest Part of Value Chain
Gas gathering and processing is the process in which impurities in raw gas (which can be dry or wet, with wetter gas including a large amount of NGLs) is gathered at the wellhead and has the impurities (water, carbon dioxide, sulfur, acids) removed. Once the gas is purified, the residual gas can be transported via pipeline without damaging it and meet pipeline quality standards (typically 1,000-1,050 Btu per standard cubic foot). Compressors boost the pressure in the pipelines to move the natural gas to market, which can be local distribution companies for distribution to consumers, or industrial consumers.

We believe gathering and processing assets have no moat because of the lower levels of capital intensity and poor contract quality. Producers typically have no shortage of G&P providers to pick from. Further, contracts are typically acreage dedication contracts that can last for 10-20 years but expose the G&P provider to capital risk and changing basin economics. Given high well decline rates, there’s constant investment required by the G&P provider to maintain and increase volumes, and if basin production peaks and declines, the G&P assets risk being stranded.

Crude oil is gathered in a similar fashion to gas, via small pipelines. It can be injected into a major long-haul pipeline and sometimes segregated or batched, depending on the quality of the oil. However, it is not processed until it reaches a refinery. The newly refined product then moves via a refined product pipeline to a storage terminal, where it is stored in tanks for transportation to retail or industrial markets via tank trucks or cars.

Railcars, tractor tank cars, and barges are valuable assets in terms of taking advantage of arbitrage opportunities where there is not a direct connection via a pipeline. These assets tend to be critical to the overall logistics operations of certain midstream firms. A product may move from the wellhead to a fractionation plant, then back to a storage well, then to the isobutylene plant, back to a storage well again, and then transported to the customer. Trucks, barges, and tractor tanks cars are critical to the last mile of distribution logistics.

Fractionation Assets Benefit From Operating at Market Hubs
After gas processing, the NGLs are separated into individual components via fractionation. NGLs typically move to market via tank cars, trucks, or NGL pipelines. NGL content can vary per basin, with some areas very being rich (lots of NGLs) and others dry (low quantity of NGLs). NGLs are typically used as feedstock for plastics and petrochemicals, heating, and refinery blending. The profitability of the industry generally depends on the value of the extracted components (net of extraction and transportation costs) being greater as separate components versus being left in the natural gas stream. Generally, NGLs are priced relative to the price of oil, so the greater spread between the price of oil and natural gas, the more profitable it is to extract NGLs from natural gas.

We do consider fractionators to be higher-quality assets than natural gas and processing assets because of the more concentrated nature of the market. Gas processing plants typically connect to a single NGL fractionation plant because it is uneconomic to have multiple connections, whereas shippers often have multiple options for gas gathering and processing. We estimate around 4.5 million-5 million bpd of fractionation capacity is in the U.S. versus about 77 bcf/d (or 13 billion bpd) of natural gas processing capacity. We estimate that 70%-80% of the fractionation market is concentrated with about seven or eight key players, all quality midstream firms and generally at relatively few key market hubs. Given that NGL fractionation plants are between natural gas processing plants and other parts of the midstream value chain, we think these investments are more likely to be sanctioned by a firm that owns all three parts of the chain versus an independent third party that will not be able to guarantee enough upstream and downstream supply to make the investment profitable. Contracts are also typically fee-based.

With an estimated 40% of fractionation capacity in the U.S. at Mont Belvieu,  Targa Resources (TRGP),  Energy Transfer Partners (ETP) (via Lone Star), and  Enterprise Products Partners (EPD) are dominant at this important market hub. The barriers to entry are sizable in terms of obtaining the necessary real estate, the related upstream and downstream parts of the value chain, and more specifically for Mont Belvieu, the salt caverns for NGL storage are quite important. These storage assets are critical for managing the logistics of exporting liquefied petroleum gas, for example, but also for allowing midstream firms and producers to take advantage of seasonal changes in demand and prices. Given fractionation’s position in the overall value chain, it only makes sense to expand capacity when new pipelines are added to deliver NGLs to the hub, and those assets are likely to be controlled by the same players that control the fractionation capacity, ensuring a rational and profitable market.

Storage is also a hub-based activity in general, and it plays a crucial role in the market in terms of managing flows by type and quality from multiple pipelines at a central hub. For example, Cushing, Oklahoma, is the largest crude oil storage hub and serves as an important market indicator in the oil world. Rates are generally market-based, with limited amounts of regulation, and contracts are typically a few years. Storage assets provide an important market buffer between the production of a given hydrocarbon (which can vary depending on flows) and consumption (which can vary daily as well as seasonally). Storage also allows midstream firms to accommodate scheduled or unscheduled outages at certain assets. Similar to oil storage, certain midstream firms use storage to take advantages of seasonal changes in demand, earning incremental fees.

Natural gas storage is typically in depleted reservoirs or underground salt caverns, and its purpose is to meet base and peak load requirements. As a result, it tends to be seasonal, with gas injections during the summer months and withdrawals during the cold winter months. Like oil storage, certain midstream firms use storage to take advantages of seasonal changes in demand, earning incremental fees.

Demand-Pull Pipelines Are Extremely High-Quality Pipelines
Pipelines are some of the highest-quality assets we cover, thanks to long contract lives and strong efficient scale dynamics. New pipelines are typically constructed to allow shippers or producers to take advantage of large price differentials (basis differentials) between two market hubs because supply and demand is out of balance in both markets. Pipeline operators will enter into long-term contracts with shippers to recover the project’s construction and development costs in exchange for a reasonable tariff that allows a shipper to capture a profitable differential, and capacity will be added until it is no longer profitable to do so.

Demand-pull pipelines are the highest-quality pipelines, our view. There are two reasons we think gas pipelines with demand-pull economics have wider economic moats than pipelines with supply-push economics. One is the ability of a demand-pull pipeline to earn economic rents by connecting constrained demand markets that struggle to add pipeline capacity with production regions. We can see this effect in the basis differentials between regional gas pricing hubs. Pipelines between areas with wider, more stable basis differentials typically can charge end users and producers higher rates to reserve pipeline capacity. For example, if the marginal cost of gas supply in one region is $2/mmBtu and local fixed prices in the demand region are $5/mmBtu, producers and end users both should be willing to pay the pipeline owner up to $3/mmBtu to access the gas, all else equal. To the extent that the $3/mmBtu covers the pipeline’s operating costs and return of capital, any additional earnings determine the pipeline’s return on invested capital. Thus, the wider the basis differential, the higher the pipeline’s ROIC, all else equal. The pipeline’s capital investment, operating costs, and stability of the basis differentials also are key to a pipeline’s economic moat. Pipelines serving areas with inelastic demand, a shortage of pipelines, and state regulator resistance to adding new capacity tend to have wider moats. State and federal regulation typically limits a pipeline’s return on capital to a modest spread over its cost of capital even if basis differentials would allow the pipeline to charge much higher rates and earn much higher ROICs.

Another reason we think demand-pull gas pipelines have wider moats is reliability. Unlike other energy sources, natural gas is difficult and costly to store. Thus, the pipeline plays a critical role in balancing supply and demand on a continuous basis. The pipeline’s role in reliability becomes highly valuable when end users experience or fear a shortage of gas supply at any given moment. End users, particularly gas distribution utilities tasked with maintaining reliable service, typically are willing to pay fixed charges year-round to ensure they have access to gas, even if that is only for a brief period such as abnormally cold days. The economics are similar to offering an insurance policy. Thus, a pipeline might be highly valuable if the demand region it serves has sharp peaks in gas use, even if only a few days per year. In these cases, the pipeline often can charge fixed rates up to customers’ opportunity cost of losing access to gas or electricity in a region with high gas-fired power generation. Those opportunity costs most often are the cost of storing an alternative fuel source such as oil or LNG, the cost of a distributed energy source off the centralized distribution network, or the cost of going without heat or electricity.

Most of the wide-moat demand-pull pipelines among companies in our coverage contract 90% or more of their capacity with fixed reservation charges that end users pay for the right to access gas on the system at any time. Wide-moat demand-pull pipelines typically can support a project’s full economics, including value-accretive returns on capital, with these reservation charges. State and federal regulators monitor these rates such that pipelines rarely earn more than a modest spread over their cost of capital even if end users would be willing to pay much higher rates. In the U.S., pipelines serving constrained gas demand regions with many peak-delivery days typically can sign multidecade reservation contracts for the pipeline’s full capacity before construction begins, essentially locking in a pipeline’s ability to earn economic rents for many years regardless of energy market fluctuations.

Petrochemicals and Export Assets Provide Opportunities
To date, only Enterprise Products Partners has pursued significant investments in petrochemical assets, and it has done so for over two decades. These investments allow Enterprise to take advantage of two key opportunities: profitable arbitrage opportunities between a lower-value molecule and a higher-value molecule such as converting ethane to ethylene or propane to propylene, and serving as a ready source of downstream demand for the NGLs on its system, effectively providing a hedge and stabilizing its overall income stream.

Export is another area where Enterprise Products Partners has staked out a leadership role, and while we do not expect its leadership to be seriously challenged, we do think other midstream firms will pursue export-oriented investments in the coming years where there are opportunities to expand on the connectivity of their existing networks. The significant advantage for Enterprise is that it can collect fees from exporting hydrocarbons (mainly LPG, ethane, and oil) as the incremental hydrocarbon is increasingly exported, given attractive international demand and low-cost U.S. feedstock. This extends the connectivity of its existing assets and reduces the likelihood of stranded assets while letting Enterprise participate in a growing stream of income.

Asset Optimization Paired With Asset Quality Adds Value
Refined product assets directly serve a refinery or transport product from a refinery to local demand centers. The moat for these assets is based on their location, either directly part of a Marathon (MRO) refinery or close by, and usually the asset is the only one of its type serving the refinery and handles all of its needs, making it uneconomic for competitors to enter the space. These assets are mainly held by the refinery master limited partnerships, which include  MPLX (MPLX),  Valero Energy Partners (VLP),  Phillips 66 Partners (PSXP), and  Andeavor Logistics (ANDX).

Many of the midstream firms we cover engage in marketing activities. Examples include Enterprise Products Partners,  Williams (WMB), Energy Transfer Partners, and  Oneok (OKE). There are a variety of activities undertaken under this marketing umbrella, and some of the most valuable activities are engaging in product, time, and location arbitrage. We believe midstream firms that own high-quality assets can extract additional fees from their networks by collecting fees based on differentials that are observed across the system. These advantages are not available to peers for a variety of reasons, including poor asset quality, weak financials (which matters from a counterparty perspective), or a too-small network (lacking the assets to take advantage of the opportunity). Further, these economic rents are extracted from the proprietary information provided by the network of assets and not shared with the actual employees of the marketing unit because the employees are not adding proprietary information in the transaction. This type of advantage gained by quality networks within midstream is referred to by academics as temporal specificity.

We think the concept helps explain why and how midstream firms can extract rents from a business that most observers would consider to become commoditized fairly quickly. Asset ownership is key, particularly for more complex transactions where a molecule might be gathered from a basin, transported to a market hub, and fractionated. If a midstream firm does not own each of the individual assets involved (gathering and processing, pipelines, fractionation), it would have to share any profits from this transaction with third parties, probably resulting in a value-neutral transaction, particularly because of the spread-based nature of the fee.

Moat Consideration Number 2: Contract Quality
Contract quality is primarily assessed by term, with long-term contracts (10-plus years) being preferred with take-or-pay provisions. Contract quality does not directly support the efficient scale moat source, but it more directly speaks to the sustainability of future excess returns. Entities that are primarily oriented around pipelines are the strongest positioned as they obtain the longest terms. Long-term contracts for pipelines tend to be made up mostly of capacity reservation fees and a more modest transportation fee. Shippers are obligated to use the pipeline but not required to do so; however, they must pay the reservation charges in any scenario, ensuring rents for the pipelines. The smaller transportation fees are only paid based on actual volumes shipped. Less well-positioned firms typically contain a large component of gathering and processing, storage, fractionation, or other business areas, where it is harder to argue that advantages will persist for two decades or more, and contract terms tend to be only a few years, reflecting the reduced barriers to entry compared with pipelines.

Contract quality for gathering and processing is generally poor when considering the quality of the contract and its pay structure. Acreage dedication agreements, where the producer will commit acreage production to a gatherer and processer, can last for 10-20 years and are wholly dependent on producers’ capital spending plans and basin economics. Midstream firms typically have little access to reservoir quality data and have written off billions in intangible assets over the past few years as basin economics have changed and drilling plans have been halted. These types of contracts are also typically unfavorable to midstream entities and are mostly set on basin history, which tends to be more favorable to producer economics than midstream returns. The contract can be fee-based, but percentage of liquids, percentage of index, and keep-whole contracts mean exposure to both commodity prices and weaker spreads.

Unlike more-developed MLP peers, refinery MLPs including MPLX are likely to enjoy long-term contracts with their parent for future drop-downs regardless of the actual quality of the assets due to MLP investor preference for fee-based income versus commodity price exposure, ensuring a high degree of confidence around near-term returns for the partnership. These contracts are typically for 5-10 years and include minimum volume commitments. Given the close location of the assets to parent Marathon Petroleum’s refineries, we don’t believe the contracts are needed to ensure flows to MPLX assets. In fact, the moat for these assets is based on their location--either directly part of a Marathon refinery or close by. Usually the asset is the only one of its type serving the refinery and handles all of its needs, making it uneconomic for competitors to enter the space.

U.S. LNG Contracts Are Unique
We think  Cheniere Energy (LNG) and  Cheniere Energy Partners (CQP) have wide moats thanks to an intangibles moat source. The intangibles moat source is derived primarily from the 20-year take-or-pay contracts that both entities have signed with multiple customers to liquefy natural gas; these essentially put Cheniere in an incredibly strong competitive position as a pure toll-taker with no commodity price risk. We don’t see any contract renegotiation risk, given the attractive features of the contract, and to date, only non-Cheniere contracts have been challenged, mainly because of the oil-linked status and current poor economics.

Cheniere’s contracts are highly unusual in the LNG market and provide numerous advantages. Historically, LNG contracts have been linked to oil prices either via S-curve or slope pricing. In recent years, contract pricing has shifted more toward hub pricing, to the detriment of companies such as Gazprom but to the benefit of Cheniere, given the significant growth in low-cost U.S. gas (and therefore Henry Hub pricing), making U.S. LNG exports an important driver of global LNG pricing. Typical LNG contracts contain clauses that allow price revisions either after a certain period or if oil prices rise or fall outside of a certain range, allowing customers to flex the amount of LNG delivered in any given year while holding them to the contracted quantity over the full contract. They also have restrictions on where the gas can be shipped. Customers are responsible for the procurement of gas.

In contrast, Cheniere’s contracts do not have clauses allowing price revisions, have complete freedom on destinations (allowing the gas to be shipped to the most profitable market), and are linked to Henry Hub instead of oil (thus cheaper). Cheniere takes on gas procurement and operating risks. These contracts are similar to what U.S. peers such as Cove Point and Freeport have signed. From an operational perspective, Cheniere has been performing well, and it has linked short- and long-term contracts with pipelines such as Williams’ Transco to supply all of the gas needed for the terminals.

Regulators Also Factor Into Industry Dynamics
There are differences in the regulatory structure between oil (NGL pipelines are included) and gas pipelines; it is fair to state that individually, oil pipelines face lower regulatory barriers to entry than gas pipelines, but more practical barriers to entry also appear for oil pipelines. The Natural Gas Act regulates natural gas pipelines, and new construction is explicitly approved by the FERC, which decides if the pipeline and tariffs are in the public interest. This approval provides the pipeline owner with certainty regarding its projected returns, but FERC approval also comes with federal eminent domain, which pre-empts state and local laws that might otherwise prevent construction of the pipeline. Thus states, local governments, or landowners cannot block natural gas pipelines.

In contrast, explicit FERC approval is not required to construct an oil pipeline under the Interstate Commerce Act, but the FERC can regulate rates, which means it acts as a mediator for disputes. This difference means that oil pipelines must obtain approval from each state they plan to use, and individual landowners can force the pipeline owner to reroute the pipe and incur additional costs if an agreement cannot be reached and a pipeline appeal to the state fails. The FERC is not required to approve rates before construction, though it can issue an advance ruling that allows oil pipelines to have substantial certainty regarding expected capital returns.

There are also differences in how service is provided between oil and gas pipelines. Natural gas pipeline contracts are on a firm capacity basis, which means that once capacity is fully contracted, new shippers will be denied service. In contrast, oil pipelines are designated common carriers, which means they must provide service to any shipper upon request. With a fully contracted oil pipeline, a new shipper request would mean that all existing customers would see reduced capacity allocations to meet the new customer’s needs. This sometimes creates challenges in terms of landing contract commitments, as shippers commit to paying a company tariff without firm rights to that capacity, even if they are “anchor” shippers that contributed to the pipeline’s original development. To mitigate these issues, oil pipelines offer premium rates for capacity that are free from prorating, as well as a “shipping history preference,” where shippers are ranked by how long they’ve been transporting oil on the pipeline. The shipper with the longest history is the last to be prorated, and the shipping history distinction is particularly prized by producers, in our view. Finally, while the FERC approves ranges of tariffs for gas pipelines, oil pipelines typically only have a single stated rate, which we don’t think eliminates the market-based nature of rates over time for both oil and gas pipelines.

Canadian Regulatory Environment Contributes to Moat
Another form of intangibles lies in Canadian midstream. From a Canadian perspective, extensive regulatory oversight of pipeline assets acts as a barrier for new entrants, with many federal, state, and local agencies involved in permitting, siting, and rate-setting activities. As such, regulation keeps out competitors and acts as an intangible moat source for existing pipeline operations, such as  Enbridge (ENB). The U.S. is Canada’s primary crude market, which makes the approval process more stringent. Since pipelines originate in Canada and terminate in the U.S., approval is required from Canadian and U.S. regulators.

The slow-growing nature of Canada’s primary oil supply, the oil sands, coupled with environmental opposition further complicates the approval of new projects. Oil sands projects require high usage of natural gas to produce bitumen, which can take two to three years to fully heat a reservoir, coupled with high levels of greenhouse gas emissions. Because of these downsides, regulation protects pipeline infrastructure from becoming oversupplied, as projects are not approved unless economic need for expansion is demonstrated.

Investment Ideas in Midstream Despite Bearish Outlook for Oil Prices
In response to lower oil prices, the midstream industry has spent the past few years making the needed investments to reposition itself for the changing oil flows across the U.S. and emergence of the Permian Basin as a major new source of incremental oil supply. Many industry players have also spent considerable time either exiting or reducing their reliance on areas of the industry where profits are spread-based or converting spread-based contracts to fee-based ones. The end result is that some of the best-positioned midstream players offer up largely fee-based business models with limited to no commodity price exposure that are leveraged to hydrocarbon volume growth. Because we expect sharply higher U.S. oil growth going forward, we prefer midstream names with exposure to the Permian Basin and high-quality assets.  Plains All American Pipeline (PAA) and  Enterprise Products Partners (EPD) offer a compelling mix of strong assets and valuation.  Spectra Energy Partners (SEP) and  Enbridge (ENB) also offer very high-quality asset bases and attractive valuations. We would be more wary of no-moat Targa Resources, which is primarily a gathering and processor; two thirds of its contracts are exposed to changes in commodity prices (though it does hedge), and an oil price pullback would result in weaker profitability.

Stephen Ellis does not own (actual or beneficial) shares in any of the securities mentioned above. Find out about Morningstar’s editorial policies.