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Policy and Regulatory Options
Because changing the status quo for nuclear will require that choices be made, we have organized this menu of policy options according to those who will face them, starting from those governing bodies closest to these plants.
State regulatory commissions could make customers pay more for nuclear or nuclear-style generation, arguing that it has special or newly desirable attributes.
The most significant electricity sector policy and regulation decisions occur at the state level. Public utility commissions, also referred to as public service commissions, are generally the primary actors: long-lived bodies, often with independent or quasi-constitutional powers, directed by a board of commissioners either elected or appointed by the governor. They are empowered to set the rules by which vertically integrated monopoly utilities (in traditional "regulated" states) or electricity distributors and retailers or other power producers (in reformed "deregulated" states) do business. They also often act as system-wide planning bodies, are arbiters of system risk and reliability, set electricity consumer rates as well as profit margins for regulated utilities, and can be charged with implementing broad directives and goals handed down from the state legislatures. In short, they have both power and flexibility in shaping a state's electricity system.
States with Traditionally Regulated Environments
State regulatory commissions could choose to encourage nuclear power generation by developing various mechanisms to direct more ratepayer money toward it. In most regulated states with monopoly utilities, such bodies already have broad discretion to do so, with public support (or intervenor lawsuits) as the primary moderating factor to ensure that such decisions are made in the public interest. While a regulated nuclear utility has to provide an economic basis for its proposed investments, including an evaluation of alternatives, there is substantial asymmetry in anticipated cost, benefit, and investment risk information between a monopoly utility and its regulator. Moreover, it may not be possible to definitively argue the optimization of "public interest."
In some states, such as Washington, the definition can be more objective: cost minimization. Elsewhere, though, the target can be more value-laden: diversity, reliability, etc. In Mississippi, for example, the public service commission's decision criterion is to enable the state's "economic development." In either case, the regulator's influence comes down to its support or rejection of various proposed nuclear investments through a "prudence review" or the conditions it applies to such investments that could affect their desirability. The primary vehicles for such decisions include the periodic regulator-driven "integrated resource planning" process, which provides a road map for a state's electricity development and can take into account current and future customer electricity demand trends, technological availability, fuel prices, grid infrastructure needs, reliability, overall costs, and investment risks. Utilities can also approach regulators with individual proposed investments or as part of periodic required broader bundled "rate cases" which evaluate overall utility costs and allowed profits.
Recent examples include a series of uprates totaling 522 megawatts across four reactors under Florida Power and Light's ownership: the utility won approval to pass on the $3.4 billion cost of this program from the traditionally regulated state's Public Service Commission, completing the work in 2013 (Florida PSC 2014). A 2006 Florida law furthermore authorized the commission to let Florida Power and Light capitalize the work in progress, meaning that customer rates were increased to cover expenses during construction, as opposed to after commissioning, thereby reducing the utility's project financing costs. (Other regulated Southern states, including South Carolina and Georgia, have adopted similar pro-nuclear measures.) While some advocates challenged project costs during the course of the uprate projects, the commission generally approved the utility's cost requests. Elsewhere, a recent decision by the Georgia Public Service Commission demonstrated the discretion available to such bodies in traditionally regulated states: Georgia Power filed a request alongside its broader integrated resource investment plan to recover $175 million from customers in order to do early site evaluation work for a potential new nuclear plant in Stewart County. Following a commission staff report which recommended delaying a decision on the new plant, and testimony from advocates that the early evaluation cost be borne by the utility's investors rather than passed along to customers, the commission reduced Georgia Power's cost recovery authority to $99 million and required a status report to be filed before pursuing a 2019 project investment decision.
States with Deregulated Environments
With the actions of traditionally regulated state public utility commissions more or less accepted as an understood baseline, the more relevant question might therefore be the options available to regulatory bodies in deregulated states. One approach here would be for commissions to require competitive electricity retailers or other load-serving entities in such states to enter into long-term power purchase agreements (PPAs) with existing independently owned nuclear power plants as part of their wholesale power supply portfolio, rolling the costs of doing so into the rates they charge end-use customers. This would be somewhat similar to recent developments in Ohio, where local distribution utilities owned by FirstEnergy, following a series of stakeholder compromises over an eighteen-month proposal period, in 2016 received approval from the Public Utilities Commission of Ohio to enter into an eight-year above-current-market-rate power purchase agreement with the nuclear power plant belonging to its competitive generation affiliate, FirstEnergy Solutions. That plant, Davis-Besse, had otherwise failed to clear recent PJM-territory energy auctions. In this arrangement, the distribution utilities would pledge to purchase Davis-Besse generation over the period at a set price and then immediately resell that energy (along with associated capacity value and ancillary services) onto the daily and hourly PJM wholesale market. Utility end-use customer rates would reflect the difference between the agreed PPA and market price, whether higher or lower over time. (The expectation was that this would amount to extra costs in early years of the PPA and potentially lower prices later in the PPA if rising natural gas prices were to increase PJM average power market prices.) FirstEnergy described the deal as a sort of consumer hedge that would also provide financial stability to a threatened nuclear plant, while rival natural gas-oriented utilities decried it as an unfair subsidy. In this way, supporters argued that while the step would undeniably result in customers paying more for nuclear power today, it might save customers money — or not necessarily end up costing customers more — over time. Despite the state regulator's approval, however, the Federal Energy Regulatory Commission struck down the PPA deal before it could begin, arguing that the deal was anticompetitive given parent FirstEnergy's ownership interest in Davis-Besse. It is possible that such an arrangement — with the distribution utility entering into a nuclear-specific PPA, even if above market — could nevertheless be attempted elsewhere with different circumstances, ownership or otherwise. Requiring above-market PPAs of distribution utilities for particular generation assets is a mainstay of utility-scale solar and wind development in competitive or semi-deregulated power markets (though such mechanisms are generally carried out "voluntarily" by distribution utilities with a generator of choice, albeit under a mandatory renewables portfolio standard or similar directive).
As this example illustrates, recent years have found regulatory commissions in deregulated, regional transmission market states more encumbered by FERC or FERC-related decisions. Though FERC's jurisdiction of the power system is limited to interstate wholesale markets, that lens has been applied in surprising ways to the efforts of individual states to direct the form of their own power system development. For example, in a 2016 ruling, the US Supreme Court ruled that Maryland's proposed "contract for differences" approach to incentivizing new (in this case, nonnuclear) generation capacity by committing local distribution utilities to enter into twenty-year fixed PPAs, for later resale on the wholesale market, unlawfully infringed on FERC's jurisdiction of interstate electricity markets. At the same time, the justices noted that their decision in this case does not address "the permissibility of various other measures States might employ to encourage development of new or clean generation, including tax incentives, land grants, direct subsidies, construction of state-owned generation facilities, or re-regulation of the energy sector." Despite these assurances, the experiences in Maryland and Ohio have made deregulated state commissions think more carefully about potential jurisdiction or other legal challenges to new incentive or subsidy programs.
New York's Approach
Utility commissions within deregulated states who wish to at least temporarily direct additional customer funds toward nuclear power may wish to model their efforts on existing mechanisms. For example, New York State was faced with the potential shutdown of three in-state nuclear plants for market performance reasons, with aggressive electricity sector carbon reduction goals to be met. The New York State executive and regulatory organs, including the governor's office, the cross-cutting New York State Energy Research and Development Authority, and the New York State Department of Public Service (the regulator), in 2016 proposed a nuclear zero-emission credit program to ensure that a minimum level of nuclear energy (or capacity) is maintained in the state.
This approach is nominally akin to that used to implement renewables portfolio standards, whereby each megawatt-hour of generation is awarded a transferrable renewable energy credit, of which distribution utilities are obligated to hold a certain number over time. Practically, however, the Department of Public Service later determined that given the market concentration of nuclear generators, it was not viable to establish a fair market price for the zero-emission credits that they would generate. Instead, the state's Energy Research & Development Authority was named as the sole buyer of credits at an initial administratively set price of $17.48 per megawatt-hour with a rising cap to as high as a nominal $29.15 per megawatt-hour over a twelve-year period. This agency would then resell the credits to obligated local distribution utilities or other designated load-serving entities in proportion to their share of total statewide electricity sales. Meanwhile, if the regional wholesale electricity market price were to exceed a nominal $39 per megawatt-hour price over that period (up from a current average of about $30 per megawatt-hour), the subsidy would be adjusted down using a set formula.
The design of New York's policy approach can therefore be regarded as a hybrid to meet at least two social goals, defined by the regulator as being in the public interest: (1) internalizing to the market the external value of nuclear's zero carbon emission generation and (2) ensuring minimum market viability — but not windfall profits — for these three existing plants for their expected useful asset life, at the least cost. Notably, since the program caps credit generation from each facility at its historical maximum annual generation level, the mechanism is not intended to support plant capacity increases or new construction. In short, the regulator described the policy as a pragmatic solution to a difficult issue, one that could be relatively swiftly implemented to meet market timelines without substantively disrupting the state's numerous other energy or environmental policies and regulations.
Encouraging long-term PPAs between distribution utilities and non-regulated generators, or otherwise mandating generation-specific subsidies, might sound a lot like re-creating a traditionally regulated operating environment within a purportedly deregulated framework. A more straightforward, if radical, approach for utility regulators wishing to direct more ratepayer funds toward nuclear power could therefore be to selectively re-regulate: place existing nuclear power plants (or aspects of those assets, such as new expansionary uprate investments) within a utility rate base to recover costs from captive customers. While such a step would likely have to be taken through legislation rather than utility commission regulation, once authorized the regulator would then restart the traditional statewide integrated resource planning processes with the intent of supporting existing (or new) nuclear power. The dynamic effects of such a step could be widespread, however, potentially affecting a host of other power system modernization objectives, including price competition through new market entry, energy efficiency goals, distributed power generation, and smart grid deployment. At the same time, it would belie a power system regulatory environment which relies heavily on fledgling market structures to deliver reliable and affordable power while also increasingly leaning on the electricity system to meet growing social or environmental public policy goals through a variety of intervening mechanisms of varying elegance and efficacy. Evaluations of experiences with deregulation do suggest that the benefits of competitive markets have been only mixed in the first place (Borenstein and Bushnell 2015). No new state has begun a deregulation process since California's aborted experience following its 2001 electricity crisis. But there has been little public appetite to seriously consider re-regulation, even in a targeted capacity such as this.
Alternately, state regulatory commissions could reduce the amount that customers pay for renewables, arguing that their attributes (namely intermittency) incur external system costs.
Conversely, rather than paying more for nuclear power to improve its market viability, state regulatory commissions (or, in regional markets, regional transmission system operators) could instead reduce the amount that ratepayers pay for competitors to nuclear power, namely renewables. While states or regional system operators cannot control the existence of the current federal tax subsidies directed to renewables, they can influence electricity market rules.
For example, most electricity wholesale markets currently feature three main products: energy (both day-ahead and real-time), reserves (or ancillary services), and capacity. Energy is the obvious bulk commodity — a certain number of megawatt-hours at a certain time of day — and represents most of what a large baseload generator such as a nuclear power plant is paid. Ancillary service and reserves represent a generator's ability to offer power when called upon by the transmission operator to balance the grid in the short term. This is a major income source for standby natural gas peaking power plants, for example, and is also often won to some degree by nuclear generators, representing an income of a few dollars per megawatt-hour, depending on the region. Renewable energy generators generally do not win reserves payments because they are not dispatchable on demand. In effect, their presence on the grid helps create demand for reserve and ancillary products from other generators. Capacity markets are intended to incentivize the development of enough secure backup capability for different potential grid stress scenarios over the longer term (see further discussion on capacity markets below).
Excerpted from "Keeping the Lights on at America's Nuclear Power Plants"
Copyright © 2017 Board of Trustees of the Leland Stanford Junior University.
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Table of Contents
Diagnosing the Situation Today 13
Policy and Regulatory Options 28
State Regulators-Compensating Nuclear Plant Benefits 28
State Regulators-Internalizing Other Costs 36
State Legislators-Compensating Nuclear Plant Benefits 38
State Legislators-Internalizing Other Costs 42
Regional Grid Operators 43
Federal Agencies 58
Improving Nuclear's Value 83
Owners & Operators 83
Appendix A US Civilian Nuclear Power Reactors 101
Appendix B Recent Nuclear Plant Closures 107
About the Authors 115
Recommendations for Policymakers 7
Nuclear Power, Washington Politics, and Climate Math 11
License Extensions 22
New Nuclear vs. Existing Nuclear 27
Production Tax Credits So Far 77
Looking Ahead to Policies for New Nuclear Technologies 80