We Must Discourage Electric Utilities from Making High-Risk Investments

By Amelia Schlusser, Staff Attorney

Ceres recently issued an update of its 2012 report, Practicing Risk-Aware Electricity Regulation. The updated report concludes that large fossil fuel and nuclear power plants are the riskiest investments for utilities, and that renewable energy, distributed generation, and energy efficiency are lower-risk investments with potentially lower price tags than baseload alternatives. According to Ceres, these relative investment risks are driven in part by recent developments in the U.S. electricity sector. Notably, the EPA is poised to regulate carbon emissions from new and existing power plants in the near future. In addition, renewable energy costs have decreased significantly in recent years, and some renewable technologies are either approaching or have already become cost-competitive with fossil fuel resources. Impending carbon regulations and increased deployment of distributed generation and energy efficiency are placing added pressure on entrenched utility business models, and, as GEI’s Nate Larsen recently discussed, regulators are beginning to explore strategies to modernize the grid.

Renewable energy resources such as onshore wind and solar PV are insulated from risks associated with fuel price volatility and emissions regulations, and the levelized costs of these resources are on par or below the levelized costs of fossil fuel resources. Nevertheless, many utility integrated resource plans continue to identify renewables as higher cost, higher risk resource options. For example, PacifiCorp’s 2013 IRP concluded that new wind resource additions were not cost effective. PacifiCorp also determined that a resource portfolio with extensive coal plant retirements or conversions represented both a high-cost and high-risk investment. PacifiCorp thus proposed to keep its coal fleet operating and only invest in new wind capacity if necessary to comply with state RPS requirements. Duke Energy Progress’s (DEP) 2013 IRP asserted that “[m]odernizing the power plant fleet is an important investment in the Carolinas’ environment and its future,” and noted that utility will need to invest in new incremental resources to compensate for future coal plant retirements. However, while DEP planned to procure enough renewable resources to comply with its RPS obligations, it determined that it should meet its future energy needs with new natural gas plants and nuclear resources.

The question of the day is whether EPA’s proposed Clean Power Plan emission goals will motivate utilities to adequately account for the risks and long-term costs associated with all fossil fuel resources. If so, the final 111(d) rule has the potential to incentivize investments in renewable energy. If not, the rule will likely encourage substantial investments in new natural gas plants and accompanying infrastructure, such as interstate pipelines. Realistically, the rule will likely result in construction of new natural gas generating units either on-site or in close proximity to existing coal plants or interstate transmission lines, and incremental deployment of renewable energy resources in the vicinity of existing transmission corridors. States, however, have the power to incentivize investments in less risky, more sustainable infrastructure through their 111(d) implementation plans. 

Clean Air Act section 111(d) directs states to establish “standards of performance” for emissions of covered pollutants from existing sources within a listed source category. Each state must draft a plan to implement and enforce these standards and submit its plan to EPA for approval. EPA’s 111(d) implementing regulations refer to these state-issued standards as “emission standards.” The federal regulations mandate that states establish these emission standards as either an allowable emissions rate or an emissions allowance system. The proposed 111(d) rule for carbon emissions gives states flexibility to comply with the rule’s requirements on an individual basis or enter into multi-state compliance agreements. If states prefer to implement their 111(d) emission standards through a state-based or multi-state allowance system, the proposed rule would enable them to establish a program that favors electricity generation from specific resource types. For example, state allowance systems could work in tandem with RPS requirements to incentivize renewable energy production.

A carbon emissions allowance program that places a premium on renewable energy generation is one potential strategy to deter investments in high-risk fossil fuel resources, but it is by no means the only available strategy. State public utility commissions should consider revising their resource planning and procurement rules to send a clear message to utilities that investments in baseload fossil fuel plants are not prudent and that zero-emitting resources are in the public interest. Ratepayer advocates should closely monitor levelized cost projections and oppose investments in resources that are vulnerable to long-term cost increases. And finally, policymakers should ensure that applicable legal and policy frameworks incentivize energy infrastructure development that mitigates ratepayer and taxpayer vulnerability to risk over extended timeframes. Infrastructure constructed today will likely operate for multiple decades, and it is imperative that we discourage investments that will lock-in exposure to rising costs and environmental degradation for years to come.