Economic consequences of stranded assets for energy market participants

July 2021 | SPOTLIGHT | SECTOR ANALYSIS

Financier Worldwide Magazine

July 2021 Issue

The changes brought about by evolutions in renewable energy technologies are upending traditional relationships between different forms of energy, the customers that use them, the enterprises that construct and operate facilities and financial institutions and other investors that face resulting changes in risk exposures. These changes present serious challenges to market participants’ recovery of sunk costs, in electric, methane and oil markets. How these challenges are addressed will affect how rapidly and how efficiently the US transitions to a low carbon economy.

Renewable generation equipment’s cost continues to decline. Output from solar and wind is available at $0 short-term incremental dispatch cost. Battery research is identifying ways to lengthen the duration of output from that form of storage, and to lower its cost. But the location of renewable assets is not necessarily the same as the location of conventional thermal generation facilities, which typically have been located adjacent to sources of large amounts of water. Wind and solar facilities may be in entirely different locations. Hence the transmission system built around conventional generation usually will not suffice in a market where renewables play the kind of role envisioned by states’ renewable power standards. The result will be the stranding of electric transmission assets. For instance, the expansive plans for offshore wind generation on the East Coast must address the existing transmission grid which was built for an entirely different set of onshore generation assets often located to optimise access to coal resources. Moreover, because renewable sources have no cognisable variable costs of generating an additional kilowatt-hour (kWh) when their source of power is available, conventional generation resources that do incur an incremental expense to generate another kWh of electricity will experience reduced demand, and some will simply not be economical in competing with renewables.

Similarly, gas pipelines that transport volumes to be burned in power plants will experience de-contracting, reducing use of their systems and revenues. Eliminating the single largest market for methane in the US – electric generation – threatens to create a domino effect if the costs of idled capacity are redirected to the remaining diminished throughput. Stranding of hydrocarbon resources because of declining demand as an electric generation fuel will also impact hydrocarbon exploration and development enterprises’ credit profiles, and thus the credit profiles of their contract counterparties, such as pipelines and methane-fired power plant operators. Because of the US’s sheer scale of natural gas pipeline networks and the large share of its generation capacity fuelled by natural gas, stranded costs associated with methane will be materially greater in the US than in Europe or Asia. When collected in regulated rates, such as in bundled electricity retail markets, for generation, for electric transmission and more or less on pipelines (depending on both the degree of undersubscription and the proportion of a pipeline’s capacity subject to negotiated rates), these various forms of stranded costs will contribute to increased costs or reduced revenues for conventional generators.

The disadvantaged posture of thermal resources may hasten their downfall. Higher unit costs for conventional resources in the generation stack means that renewables will come out on top in hours when the latter can dispatch at an incremental cost of $0, possibly to the exclusion of conventional generation. If conventional generators respond to reduced demand by relinquishing firm gas transmission capacity in favour of interruptible service, the result will be the addition of another incremental cost (the interruptible gas transportation rate) to each hour of generation from such a source, to say nothing of diminished reliability if they cannot call upon firm transmission capacity to ship their gas.

The upshot is that costs all along the supply chain will become skewed under at least existing rate design principles, undermining the economic viability of thermal generators and their fuel suppliers, with significant financial consequences to many other contract counterparties of energy industry participants, such as other service providers, their sources of capital and their customers. Consumers may face an extraordinary set of rate changes, based on massive new plant investment, both to build enormous non-thermal generation capacity and for transmission reconfiguration, which could include not only new transmission assets, in a world where potentially impacted landowners are increasingly sophisticated and contentious, but for stranded assets, in the electric transmission, generation, gas pipeline and oil pipeline industries. Because most of the newly incurred, as well as stranded, costs are fixed, not variable, customers’ unavoidable energy costs would increase to a far greater degree than the variable energy charges in their rates. That in turn may induce a bias to greater consumption, as each additional unit of consumption would be much less expensive than currently, but the fixed monthly cost would be far greater. Several public policy arguments around rate design and cost recovery, more or less laid to rest 20, 30 or more years ago, may become much more controversial again in light of the disappearance of avoidable commodity costs and fuel prices. The regulatory constructs that have been in place for the recent past will become increasingly stressed by this set of costs, and that will create pressure for changes in regulators’ policy choices, if not to changes in governing legislation itself.

How stranded costs are treated will critically impact participants in all segments of the energy industries. The options include exclusive recovery through exit fees, demand rates, or through variable, energy or commodity rates, assignment to investors, accelerated recovery from current customers, such as increased depreciation, recovery from services replacing the asset or services that were stranded, recovery by a surcharge attached to $0 incremental cost dispatches of renewable energy, universal recovery, or some mixture of the foregoing. The allocation of new facilities’ costs will also significantly impact various market segments. Resolution of issues associated with, and establishment of concrete rules for, responsibilities for costs of stranded assets would expedite a transition in energy resources and promote efficiency.

The rise of greater environmental, social and governance (ESG) investing disclosures also means that financial risks presented by hydrocarbons may assume a more important role, not just for disclosure, but also more active management of portfolio assessments. The rise of a self-perpetuating stranded cost reassignment negative feedback loop could hasten the demise of conventional generation and methane pipelines, but failure to affirmatively come to terms with stranded costs’ treatments likewise could lead to the same consequence. Failure to anticipate, plan and execute on that plan will greatly differentiate the winners and losers in energy markets going forward.

Mark F. Sundback is a partner at Sheppard Mullin. He can be contacted on +1 (202) 747 1946 or by email: msundback@sheppardmullin.com.

Mark F. Sundback

Sheppard Mullin