by Cameron Prell, Crowell & Moring LLP
Corporate Risks of Leaving Regulatory Responsibilities to the States
This summer’s highly anticipated proposal from the Environmental Protection Agency (EPA) to regulate carbon dioxide (CO2) emission from existing fossil fuel power plants already has raised near-term risks and questions for state governments, electric utilities and business interests.
How those issues get resolved will play out through state-level negotiation with far-reaching implications.
The EPA’s proposal, called the Clean Power Plan (CPP), charts novel and untested legal and jurisdictional territory under section 111(d) of the Clean Air Act, and some or all of the proposed rulemaking might be rejected or remanded through the all-but-certain litigation challenges to come.
Yet stakeholders might not have time to find out. Absent a federal court’s staying the effectiveness of a final rule-anticipated to be issued in 2015-states will have to submit intrastate compliance plans by 2017 or multistate compliance plans by 2018.
Litigation could take five years or more (approximately 2019-2020) to conclude, well after states devise the suite of policies and regulations to meet compliance obligations by 2029 and 2030, and could involve amending existing state energy regulations to coordinating with interstate utilities, other states and regional transmission organizations in the establishment of market-based carbon pricing regimes.
In the aggregate, the CPP could initiate up to 49 sets of such complicated, state-specific negotiations (Vermont is not included in the CPP) over how to best reduce the carbon intensity of the state electric grid in a manner that achieves the CPP’s designated performance standard, called state goal, in a cost-efficient manner.
The biggest challenge for utilities is navigating this accelerated planning process while accounting for all market, legal and policy contingencies.
In some states, the calculus may be to assume, for example, out of necessity that the CPP could pass legal muster and be enforced as proposed, particularly in states where the emission-reducing activities’ being targeted require longer lead time planning.
Conversion to natural gas-fired power, increased renewable energy and distributed generation integration, and end-use energy efficiency are not new phenomena in some parts of the country.
The challenges before many utility executives will be which of these options are most cost-effective and what regulatory costs and possibly incentives may accrue if a state effectively mandates compliance with a market-driven low-carbon transition that already is happening.
Utilities could view the CPP as a chance to plan its glide path and lobby for the most efficient suite of state and regional mechanisms to make a seemingly inevitable transition to a lower carbon-intensive grid reasonable and cost-competitive.
Utilities in states that intend to reject and challenge the CPP might damage long-term market gains relative to utilities in other states.
Managing Risk in a Changing Climate
To start that discussion, it is helpful to know what the CPP is recommending.
The EPA’s proposal sets state-specific and statewide carbon intensity compliance goals to be achieved by 2029 and 2030 for all affected resources on an adjusted weighted-average CO2 emission rates basis (pounds of CO2 per megawatt-hour at the point of delivery to the transmission grid).
The EPA forecasts states can achieve their target goals by implementing some mix of the following four building block emissions-reduction strategies:
1. Improving fossil fuel facility heat rates through on-site efficiency improvements;
2. Re-dispatching (i.e., shifting) electric generation away from coal units to natural gas combined-cycle plants;
3. Increasing the amount of low- and zero-carbon energy generation; and
4. Increased energy efficiency at the point of end-use consumption.
States can devise any statewide or regional plan they want provided it will be approvable by the EPA.
The EPA merely uses the building blocks to set the goals and make a legal determination of what constitute the “best system of emissions reductions” (BSER) in accordance with the statutory requirements of CAA section 111(d).
If a state wants to retire old coal-fired plants, for example, it can.
If it wants to design a plan that emphasizes increased renewable energy, it can set aggressive portfolio requirements or financial incentives.
If energy efficiency gains are most cost-effective, a state can develop new demand response programs, increase building energy code stringency, or provide for new tax credits or financing incentives, for example.
If states want to guarantee a shift in load dispatch away from coal toward natural gas, however, they likely will need to develop plans to ensure that transition.
The EPA suggests states could adopt policies to facilitate re-dispatch, including:
“- Imposing absolute limits on hours of operation, capping CO2 emissions of coal plants or both;
“- Instituting a state tax on power sector carbon emissions directly;
“- Establishing a carbon allowance commodity trading system (i.e., cap and trade) that would enable energy market participants to price the carbon component of each megawatt-hour produced in the state or region; and
“- Establishing a tradable emissions rate system.
Given the array of possibilities and state circumstances, the CPP encourages states to consider coordinating a multistate compliance plan such as emissions trading.
Regional approaches may socialize the costs of emission-reducing behaviors, but negotiating plans that credit activities in one state on a regional basis or that adequately penalize noncompliant states will be a challenge.
The CPP provides little guidance to address such interstate impacts, although a few model examples exist (e.g., the Regional Greenhouse Gas Initiative).
Balancing Business, Legal Risks
Utilities also will have to evaluate potentially vulnerable legal issues raised by the CPP before concluding their strategic interests relative to state plan design discussions.
For example, the EPA introduces new concepts (e.g., the interconnected nature of the electric grid, rather than the emission source itself, as the best system for emission reduction) that have not been used in previous EPA emission guidelines or litigated previously.
The EPA also traditionally has interpreted the best system to mean that emission standards should be based on demonstrated technology, although on two occasions the EPA adopted standards that were based on a best systematic approach to reduce emissions.
The CPP estimates that only a small share of the reductions targeted in state goals can be achieved through technology.
If a court rejects nonsource reductions as being eligible for use in compliance, utilities might want to consider prioritizing natural gas fleet conversion, recognizing that all other utilities might respond the same way.
Finally, because the EPA’s proposal implicates state energy regulatory authorities, questions of EPA jurisdiction to force states to revise such laws arise.
If a state were to fail to submit an approvable plan or if it falls out of compliance, it is unclear how the EPA would enforce a federal implementation plan.
Ostensibly, the EPA may revert back to forcing states to set emissions rate caps for all the affected units in the state, which, absent further state regulatory action, may force greater plant curtailments as the best system of emission reductions.
Whether the EPA has that ultimate authority under section 111(d) of the CAA to tell an emission source not to operate will be debated in court but needs to be included now in any discussion over designing state strategies.
In some ways, the specter of carbon regulation raised by the CPP is, at least over the next few years, as impactful as its reality.
It will have lasting impacts on integrated resource planning and state climate mitigation activities.
While the CPP is by some measures an unprecedented attempt by the EPA to expand its regulatory authority that makes it vulnerable to legal challenge, its success may be establishing climate mitigation as a dominant context framing and restricting federal and state electric energy regulation for years.
Cameron Prell is a counsel in the Energy Group in Crowell & Moring’s Washington, D.C., office. His practice focuses on the business of climate change and the convergence of energy and environmental law and finance.