Cost recovery and rate mechanisms in a brave new world increasingly impacted by renewables

January 2021  |  SPECIAL REPORT: ENERGY & UTILITIES

Financier Worldwide Magazine

January 2021 Issue

Goals and mandates to achieve increased clean energy production already cover over a third of the US’s population due to state, city and individual utilities’ actions, and president-elect Biden has endorsed achieving economy-wide net-zero emissions by 2050. These goals are accelerating the transition from fossil fuels that will undoubtedly impact existing industry assets. Residual fossil- and nuclear-fuelled generation may be required for reliability, fuel diversity and security reasons. Nonetheless, natural gas pipeline assets may become stranded or underutilised, pressuring pipeline owners during the near term to increase rates or alter rate design. Foreseeable future decreases in throughput or contract demand for electric transmission assets built for a fleet of fossil-fuelled generation, may leave related costs stranded as those assets are retired, replaced with renewable and distributed generation resources, or underutilised. Owners of underutilised energy industry assets may be unable to recover costs of these facilities that are ‘stranded’ due to, for example, local, state or federal changes in energy policy or regulation. These challenges will only increase in coming years.

The electricity industry faces daunting challenges to meet clean energy goals while continuing to provide reliable service at reasonable rates, which has typically been provided by fossil- and nuclear-fired plants. In the Midwest, freezing temperatures plus diminished wind generation caused dangerous brownouts as energy producers, seeking fuel for gas-fired generation, and consumers, trying to heat their homes, competed for gas supply. In California, a combination of spiking demand due to a heatwave, underperforming wind generators, decreasing solar generation diminished by wildfires blocking the sun, and natural gas generation that went out of service, caused blackouts. Various technologies are jockeying for position, along with better grid planning, to address reliability and resilience issues, and in response, regulators are experimenting with new policies, but at least some existing conventional generation may need to be retained for reliable service during low-frequency, high-stress events.

How will the owners of such fossil-fuel generation assets be compensated? Considering the limited hours when such generators will be used and the low energy prices caused by many zero incremental dispatch cost renewable generators, energy markets may not adequately compensate the required fossil-fuel generation. Similarly, capacity markets have not been designed to plan, or properly compensate generation owners, for reliability issues that a fossil-fuel generator may solve in the future. Owners of such generation may require an annual cost-based revenue requirement recovery mechanism. Generators have received cost-based compensation for certain ancillary services, black-start capability and reliability purposes. Reliability-must-run agreements have been used at state and federal levels and by grid operators to ensure that generation does not retire when it is still needed for reliability. Typically, these agreements have not been used to meet long-term needs. However, the cost-of-service framework may provide a prospective model for compensating fossil-fuel generators. Who will pay for the contracts underpinning those assets? For instance, if some conventional generation is required precisely because of increased renewable resources on the grid, should the former’s cost be spread across all load on the grid, or charged only to customers consuming in the hours when conventional generators must operate, or based on consumption above some base level? Regulators will need to grapple with cost-causation and allocation considerations when deciding whether such costs should be charged to load (and if so, which customers) or generation, on commodity, reservation or hybrid bases. Some regional transmission operators in North America have implemented commodity-only compensation schemes for generation resources, which may dramatically impact the recovery of under-utilised facilities’ costs. Another issue involves whether a utility may recover the stranded costs of its fossil-fuel resources when that utility has voluntarily elected to move to renewables sooner, or to a greater degree, than required by applicable federal, state and local law.

Methane pipelines already face numerous markets with transmission capacity overbuilt by competitors that lack franchised service territories (in contrast to retail electric utilities). Demand for the products they transport will be diminished by mandates and goals, such as renewable portfolio standards and carbon pricing.

The form and date of certification by the Federal Energy Regulatory Commission (FERC) may significantly affect a pipeline’s ability to recover costs when faced with declining demand. Pipelines placed ‘at risk’ by FERC, which could be implemented in a number of different ways, may be unable to reapportion to remaining billing determinants costs of desubscribed capacity. In contrast, some pipelines certificated using traditional Natural Gas Act (NGA) Section 7 certificates could seek to reapportion to other shippers the costs of desubscribed capacity. Even traditionally certificated pipelines, however, are constrained if their transportation contracts preclude rate increases, for instance to recover revenue the pipeline loses when other contracts expire. As pipelines lose firm contracts and demand, the availability of interruptible service will improve. Shippers may elect interruptible service, paid for only if, as and when used, rather than reserved by monthly fixed payments owed regardless of a level of transportation that actually occurs, further diminishing pipelines’ revenue.

These circumstances require federal ratemaking reforms. Denying pipelines reasonable opportunities to recover prudently incurred costs contravenes the NGA’s benchmark of just and reasonable rates. Additionally, it would signal that existing rates of depreciation were not adequate. This result could deprive the pipeline of the opportunity to earn a reasonable return as required by the US Supreme Court in Hope.

Potential resolutions could take several different reforms. For instance, assets could be depreciated on an accelerated basis in the earliest remaining period of an asset’s remaining life, before 2035 or 2040, for example, so long as the method did not impede the use of tax normalisation. Alternatively, accumulated depreciation associated with facilities having a longer viable economic life could be, with regulatory approval, shifted to another account or facility with a shorter economically viable life, e.g., those primarily transporting gas used as a fuel for electric generation. Depreciation cost also could be recovered on a unit-of throughput, rather than a strictly chronological, basis. These greater risks may justify a higher equity return, but the result might be counterintuitive, increasing unit costs as market share decreased.

Costs of electric transmission assets will become stranded because of increased renewable generation development. Traditionally, electricity has come from fossil- and nuclear-fired plants. Transmission facilities were built from those generating plants to move electricity to load centres. However, recent local, state and federal initiatives are dramatically increasing renewable generation in locations that do not overlap with conventional generation resources. Output from these renewable facilities may in some measure displace that of existing generating facilities (and thus the transmission facilities interconnected therewith), hence existing transmission utilities serving the latter type of generation may experience reduced demand and fail to recover costs, and therefore their costs would be stranded.

The potential stranding of these costs raises several questions. For example, which customers should be responsible for these stranded costs? Should stranded costs be spread across all rate classes to avoid disproportionate impact upon a particular rate class? That type of cost allocation may be challenged by rate classes as conflicting with cost causation principles. Alternatively, should stranded costs be recovered only from certain rate classes? Impacted rate classes may contend existing transmission infrastructure benefitted all rate classes and therefore stranded costs should be shared. Additionally, should stranded costs be offset by commodity price savings offered by renewable resources? This may reduce stranded costs’ impact upon individual rate classes, but be administratively burdensome, because of both the difficulty of accurately measuring stranded costs and uncertainty and controversy regarding projections of commodity price and alternative dispatch scenarios – for example, what dispatch presumption should be assigned to renewable resources going forward? How will forced and unforced outages of conventional resources be affected by reduced, increasingly intermittent, dispatch levels? Regardless of which method is used, regulators must weigh whether cost allocation, rate design and recovery approaches create the appropriate incentives to make necessary prudent investments, particularly where new renewable generation encounters inadequate transmission capacity.

The transition costs from conventional to clean energy resources will dramatically impact consumers, investors and competitors. The energy industry has several examples of how stranded costs could be handled, such as pipeline take-or-pay contracts, desubscribed pipeline capacity and electricity industry restructuring at federal and state levels in the 1990s. Handled poorly, this challenge could produce widespread economic disruption, including to financial markets (consider, as a parallel, the decline of railroads during massive technological changes in part funded by a large government highway programme from 1900-1960), and hinder the US economy and efficient transitioning to renewables. Handled well, the transition will honour constitutional parameters, and longstanding statutory standards, as well as reducing emissions.

 

Mark Sundback and Bill Rappolt are partners and Andrew Mina is an associate at Sheppard Mullin. Mr Sundback can be contacted on +1 (202) 747 1946 or by email: msundback@sheppardmullin.com. Mr Rappolt can be contacted on +1 (202) 747 3317 or by email: wrappolt@sheppardmullin.com. Mr Mina can be contacted on +1 (202) 747 2327 or by email: amina@sheppardmullin.com.

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BY

Mark Sundback, Bill Rappolt and Andrew Mina

Sheppard Mullin

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