The electricity system is facing new pressures from a changing generation mix, new technologies, consumer demand, and evolving utility business models. Planning for these changes will require participants in the process—utilities, regulators, consumers, and other stakeholders—not only to engage with these coming shifts but also to think critically and collectively about ways to address them. North Carolina has a range of options to institute comprehensive electricity planning that is aligned with effective planning principles and that builds on its past successes.

Release of the Clean Power Plan (CPP) marks a significant moment in U.S. climate policy, but a host of economic, technological, and regulatory factors are also driving significant change in the electricity sector, complicating state regulatory decision making. Ensuring access to reliable and affordable electricity while protecting public health is a central goal of state regulation of electric utilities. Thus, expectations about the future of the electricity sector in general, and the future of electricity demand and emissions trajectories in particular, will likely play an important role in state CPP decisions. This policy brief discusses load growth—rising electricity demand—in the context of CPP design choices and demonstrates that it may occur under either a rate-based or mass-based approach. Following a brief overview of the Clean Power Plan and state choices, including rate-based and mass-based performance standards, it summarizes recent trends in load growth and carbon dioxide emissions in the U.S. electricity sector, showing how electricity demand growth in the United States has been low for more than a decade while the carbon intensity of electricity generation has declined. It then explores how both rate-based and mass-based plans can accommodate load growth and future emissions. Although no CPP approach limits electricity generation growth to meet new demand, rate-based approaches and mass-based approaches that cover only existing sources also allow emissions from new sources to increase. Mass-based plans that cover new sources would not limit electricity generation growth, but they would limit emissions from all covered sources.

On August 3, 2015, the U.S. Environmental Protection Agency (EPA) finalized carbon dioxide (CO₂) emission guidelines for two categories of existing power plants under section 111(d) of the Clean Air Act. The final rule, referred to as the Clean Power Plan, requires each state to develop its own plan that applies equivalent standards of performance to affected units. If a state fails to submit an adequate plan, the Clean Air Act authorizes the EPA to develop and implement a federal plan for the state. In a separate action, the EPA proposed mass- and rate-based versions of a federal plan as well as mass- and rate-based model rules, which states could choose to adopt or to adapt by substituting their own provisions subject to EPA approval. The proposed model rules are similar to but more flexible than the federal plan proposals. This policy brief summarizes the final Clean Power Plan rule, describes the mass- and rate-based proposed federal plans, identifies areas in which the model rules differ, highlights key issues for states and other stakeholders as they evaluate the tradeoffs among plan pathways, and discusses the EPA’s timeline for finalizing the federal plan and model rules.

The proposed Clean Power Plan gives U.S. states flexibility in how they attain state-level carbon dioxide emissions rate goals from existing power plants. This analysis explores the potential impact of the proposed CPP on Southeast states across a range of compliance options relative to a baseline without the CPP. The analysis presents modeling results from the Dynamic Integrated Economy/Energy/Emissions Model for eight primary compliance scenarios involving rate-based or mass-based compliance, unilateral state action or regional cooperation, and inclusion or non-inclusion of natural gas combined cycle (NGCC) units as regulated entities under the CPP.

Regarding electricity sector adjustments, the modeling shows that a rate-based approach initially decreases coal generation, encourages use of existing and construction of new NGCC units, and incentivizes renewable generation, although use of renewables is not cost-effective in the Southeast under baseline cost assumptions. By comparison, a mass-based approach initially increases coal generation and removes incentives for use of existing NGCC units while significantly increasing new NGCC generation. Including new NGCC units under CPP compliance shifts generation from those units to existing NGCC units under mass-based compliance and increases coal generation under rate-based compliance.

Regarding policy costs, the modeling shows that individual state compliance costs vary considerably, that a mass-based approach initially entails half the costs of a rate-based approach, and that both regional rate-based and mass-based approaches create significant net cost savings over unilateral state compliance.

As states and stakeholders evaluate compliance options under the U.S. Environmental Protection Agency’s proposed Clean Power Plan, many recognize the potential economic benefits of market-based strategies. In some states, however, market approaches trigger administrative and political hurdles. A new policy brief by the Nicholas Institute for Environmental Policy Solutions offers a compliance pathway that allows states to realize the advantages of multistate and market-based solutions without mandating either strategy. With the common elements approach, states develop individual-state plans to achieve their unique emissions targets and give power plant owners the option to participate in cross-state emissions markets. Power plant owners can transfer low-cost emissions reductions between states whose compliance plans share common elements--credits defined the same way and mechanisms to protect against double counting. The common elements approach offers the following benefits: (1) allows cross-state credit transfers without states negotiating a formal regional trading scheme, (2) leaves compliance choices to power companies, (3) builds on existing state and federal trading programs, and (4) maintains the traditional roles of state energy and environmental regulators.

Author(s): Jonas Monast, Tim Profeta, Jeremy Tarr, and Brian Murray

Achieving a widespread adoption of innovative electricity generation technologies involves a complex system of research, development, demonstration, and deployment, with each phase then informing future developments. Despite a number of non-regulatory programs at the federal level to support this process, the innovation premium—the increased cost and technology risk often associated with innovative generation technologies—creates hurdles in the state public utility commission (PUC) process. This article in the Hastings Law Journal examines how and why innovative energy technologies face challenges in the PUC process, focusing on case studies where PUCs have approved or denied utility proposals to deploy high cost, first-generation energy technologies. It concludes with an outline of possible strategies to address PUC concerns by allocating the innovation premium beyond a single utility's ratepayers.

On June 2, 2014, the U.S. Environmental Protection Agency proposed guidelines under section 111(d) of the Clean Air Act for the control of carbon dioxide emissions from existing fossil fuel–fired power plants. The proposed guidelines are expected to reduce total power sector carbon emissions 30% from 2005 levels by 2030 through the setting of individual emissions targets for each state. States can choose from a range of emissions reduction strategies to develop their preferred approach for achieving their targets. This policy brief provides an overview of the proposed guidelines’ key elements.

With finalization of the EPA’s section 111(d) guidelines, states will make decisions about how to reduce carbon dioxide emissions. These decisions could fundamentally affect the U.S. power sector and will be made in an environment of uncertainty about the timing, stringency, and compliance costs of future air quality regulations. In light of this uncertainty, states may wish to look beyond carbon dioxide when developing section 111(d) plans. The Clean Air Act allows them the flexibility to reduce carbon emissions in a way that hedges the risk of anticipated air regulations and that potentially lowers long-term compliance costs. This paper discusses these benefits, summarizes air quality regulations that could affect the power sector in the future, and describes how states can use the flexibility afforded them by section 111(d) to manage this regulatory risk. In addition, it identifies elements of state 111(d) plans that may lead to reductions in criteria pollutants.

Forthcoming carbon dioxide regulations for existing power plants in the United States have heightened interest in thermal efficiency gains for coal-fired power plants. Plant modifications to improve thermal efficiency can trigger New Source Review (NSR), a Clean Air Act requirement to adopt state-of-the-art pollution controls. This article in the journal Energy Policy explores whether existing coal plants would likely face additional pollution control requirements if they undertake modifications that trigger NSR. Despite emissions controls that are or will be installed under the Mercury and Air Toxics Standards and Clean Air Interstate Rule or its replacement, 80% of coal units (76% of capacity) that are expected to remain in operation are not projected to meet the minimum NSR requirements for at least one pollutant: nitrogen oxides or sulfur dioxide. This is an important consideration for the U.S. Environmental Protection Agency and state policymakers as they determine the extent to which carbon dioxide regulation will rely on unit-by-unit thermal efficiency gains versus potential flexible compliance strategies such as averaging, trading, energy efficiency, and renewable energy. NSR would likely delay and add cost to thermal efficiency projects at a majority of coal units, including projects undertaken to comply with forthcoming carbon dioxide regulation.

The U.S. electricity sector is in the midst of a significant transition driven by changes in markets, technology, and regulation, including a forthcoming obligation under section 111(d) of the Clean Air Act to limit carbon dioxide (CO₂) emissions from existing fossil fuel-fired power plants. The broad statutory language of section 111(d) presents state regulators with an opportunity to pursue strategies that simultaneously reduce CO₂ emissions and address other electricity sector needs. This report discusses challenges facing the electricity sector and the potential to implement section 111(d) compliance strategies that provide multiple benefits for the sector.