Renewable energy credits (REC) have been around for more than a decade. The development of state REC markets has been intrinsically linked to increasingly prevalent renewable portfolio standards (RPS) throughout the United States since the late 1990s. In combination with federal tax incentives, such as the production tax credit (PTC) or the investment tax credit (ITC), state RPS requirements have been the driving force behind renewable generation capacity additions (see Figure 1). To date, the RPS requirements and their associated REC markets have been instituted and operated at the state level. Now, the United States Congress has pending legislation—H.R. 2454 in the House of Representatives and S.1733 in the Senate—which creates, among other things, a federally mandated renewable energy standard (RES). However, since this new federal mandate hasn’t yet been approved and signed into law, RPS requirements and REC markets continue under state jurisdiction.
Currently, state RPS requirements have a common goal of encouraging and increasing the renewable energy supply. However, the design of these RPS requirements varies so dramatically that there’s debate over what exactly constitutes an RPS. This is because despite fostering the installation of renewable generation, the tailoring of RPS designs by states to satisfy particular objectives and political exigencies in some respect creates “laboratories” for RPS policy experimentation.
The lack of standards in RPS mandates also can be observed in the differences among states regarding how RPS compliance is achieved. Three distinct RPS compliance models thus far have emerged:
• States with competitive retail markets: electricity suppliers are given broad latitude to comply with RPS requirements;
• States with regulated monopolies: regulators oversee electric utility procurement and contracting of RPS; and
• States conducting procurement: a state agency or instrumentality has direct responsibility to conduct procurements under the RPS.
These compliance models and different RPS requirements have direct impacts on the development of REC markets. The reason is that states also have adopted different eligibility rules related to geographic location and electric delivery. For example, states that enact an RPS do so with the expectation that the requirement will stimulate new resource development in their state or region. This highlights the practical limitation on the actual location of renewable projects.
These limitations are one of the root causes for the sub-optimal progress being made in developing new renewable generation resources and one of the main reasons the United States should consider some form of a national REC market. A national REC market would be an invaluable tool that could be used to satisfy RPS requirements without any geographic constraint.
The current design of the regional REC market clearly isn’t ideal. Nonetheless, it has allowed RPS goals to be fully, or almost fully, achieved. The overall level of RPS compliance in 2008 was an estimated 96 percent, and a few states achieved renewable energy deliveries, exceeding 97 percent as a proportion of RPS targets.
Although RECs are used widely as one of the preferred ways to comply with RPS mandates, REC definitions aren’t uniform. Each state has defined REC in a different way. These differences are based on eligible resource definitions, generator vintages, limitations on generator location and electricity delivery, and whether or not emissions credits, if any, must be retired with the REC for RPS compliance. The result is that there are multiple state and regional markets for RECs, and fungibility across RPS markets is limited.
Consequently, the market is fractured and REC contracting practices vary considerably across states. In some states, RPS markets focus on the short-term trade of unbundled RECs. This is the case in the majority of states where retail choice is allowed and load obligations of individual LSEs are more uncertain. In other states, REC markets focus on a mix of short-term and longer-term purchases, where long-term purchases might be for unbundled RECs or RECs bundled with the underlying electricity supply. Finally, in a third group of states, where no retail competition exists, utilities rely on long-term contracts for RECs that remain bundled with electricity.
Additionally, there’s the issue of tracking certificates. Thus far, reliance on unbundled RECs for state RPS compliance often goes hand-in-hand with the development of regional certificate tracking systems. Although several states rely on manual attestations and contract audits, states increasingly are using electronic certificate tracking systems to issue, record, track, and retire RECs. No matter the system, a clear audit trail is needed to demonstrate transparency and protect market participants from fraud.
A national REC market would mitigate such problems—or possibly eliminate them—while increasing the depth of the market by creating fungible assets that could be traded more freely. Fundamentally, a nationwide market would allow market forces to balance disparity in resources and technology maturity. Furthermore, this national market would replace the state level feed-in tariffs. Under a nationwide REC system, each state would agree to a level of electricity generation from renewables, based on the availability of the renewable resource in question. Certificates would be provided to renewable generators, who then would sell them on the proposed trading platform to suppliers unable to meet their renewable obligations in their respective states.
Another benefit of a nationwide REC market is that it would facilitate the trading of international RECs, particularly RECs that are also carbon offsets. This is important since domestic offsets—with an estimated pipeline of 20 million tons per year relative to 6,000 million tons of carbon generated—hardly will be able to fill the gap. Once the REC standards are set nationwide, international REC prices can be adjusted easily, further increasing the depth of the market. International RECs are abundant and cheap now because of the global recession. However, once the economic forecast changes and emission caps are in place, the United States will have to compete for these credits with Europe and countries that have signed the Kyoto protocol. Selling the credits in the market will further reduce the need for subsidizing renewable energy generators, as these added revenues would improve the financial returns of such projects.
Thus far, the impact of RPS requirements and RECs on wholesale prices has been quite limited. The Lawrence Berkeley National Laboratories, in a study published in 2008, has estimated that this overall impact was less than 1 percent of rates.1
But this situation likely will change in the coming years as more states implement RPS requirements, and it certainly will change if a federally mandated RES is implemented. Today, renewable energy doesn’t represent a significant portion of U.S. generating capacity—less than 4 percent of the total installed capacity—or energy generated. For example, under a federally mandated RES of 20 percent of energy by 2025, and assuming full compliance is achieved, the United States will require an additional 255 GW of new renewable generation. Such a massive deployment of capital will impact retail rates by at least 11 percent—or 1.1 cents per kWh.2 To minimize the impact of this potential capital deployment, a combination of market forces and regulation can be used to increase the coordination of inter-regional energy flow and local REC markets.
First, the regions in the United States with the most favorable wind conditions happen to be located in the West and Midwest, far away from load centers. Developing wind generation in these regions might be highly cost effective because these assets would have high capacity factors and would require a minimal amount of backup generation from such traditional sources as natural gas. As a result, levelized wind energy costs potentially could fall by 20 to 30 percent. However, due to the localized nature of utility markets in the United States, challenges arise when trying to provide infrastructure—such as transmission—to support these new generation assets. To date, there’s been little consensus on how to resolve cost allocation issues (i.e., who benefits from a project and who should pay for it). What is clear is that the grid would benefit if transfer capacity between regions were increased. This increase in transfer capacity between interconnections would allow regions rich with intermittent renewable energy to import base-load energy on days when the sun doesn’t shine or the wind doesn’t blow. It also would allow them to export energy to other regions when available renewable energy exceeds local requirements.
Second, new nuclear generation should be considered eligible for RECs under this nationwide market. Nuclear is the only current base-load, high-capacity factor and at-scale technology that is virtually carbon free. Allowing nuclear to be eligible for RECs might accelerate the nuclear renaissance by attracting investors with potentially higher returns. This revenue stream could, under certain scenarios, reduce the need for loan guarantees from the U.S. government. Speeding the nuclear build up would help mitigate the dash-to-gas effect that market analysts have been predicting. Under aggressive greenhouse-gas (GHG) emission-reduction mandates, the utility industry and independent power producers likely would revert to natural gas as the fuel of choice for new base-load units. While this measure only would be temporary, unless and until new caps are put in place by 2025, it certainly would result in higher supply costs. And it would create just the kind of emissions that an REC standard seeks to help mitigate.
A final effect—and a worthy by-product—of favorable nuclear treatment would be helping to levelize the international playing field for new nuclear—a playing field called “countries vs. companies” by some, and one in which U.S. utilities and investors are competing with sovereign entities for resources. New nuclear, combined with a U.S. REC program, together would drive the United States towards its renewables and GHG targets.
Third, an REC market coordinated at the national level would allow optimization of the renewable generation portfolio and would provide RECs—allocated efficiently and fairly—that could be sold to reduce the cost of new renewable generation projects.
When designing this market, federal policymakers should learn from state experiences to limit the maximum impact of these requirements on electricity rates. Common approaches include alternative compliance payments in lieu of purchasing RECs, direct retail rate caps, renewable energy contract price and funding caps, per-customer electric bill impact limits, and financial penalties that can serve as cost caps in certain circumstances. Furthermore, establishing force majeure mechanisms would mitigate the wholesale price risk. Such mechanisms would allow electricity suppliers to limit their renewable energy purchases if those purchases would unduly raise electricity rates.
Overall, minimizing generation costs by increasing availability reduces the need for subsidies and saves tax-payers money by bringing down the levelized cost of generation. A national REC market then would allow utilities and other load serving entities (LSE) to choose the most economical method of compliance (e.g., asset ownership vs. contracting vs. purchasing RECs). The bottom line is that a uniform and transparent REC market will be critical for future compliance with aggressive renewable portfolio standards, will facilitate the equitable transfer of value between different regions of the country, and will help minimize the impact on wholesale prices of large capital investments in renewable energy.
Meanwhile, Europe is working to create a single energy market and China is committing vast resources to develop low-carbon technologies. While the pressure is increasing every day, the United States can take action by replacing disjointed state policies with a coordinated REC market that is tied to a federal RES mandate. Then, it can treat all low-carbon energy in a similar manner in order to promote investment, not only in wind and solar, but also in nuclear—a low carbon energy source with a long track record of efficient and reliable electricity generation.
A consistent and ubiquitous renewable energy market will allow stakeholders in power markets—like utilities, retailers and other LSEs—to optimize the choice between asset ownership and RECs. While operating in this environment will present challenges and opportunities to these different stakeholders, change is inevitable as new generation assets are needed to replace traditional fossil fuel generation, and new T&D systems are needed to replace aging infrastructure. Developing and deploying new capital, while minimizing the impact on ratepayers, is the goal. This goal cannot be met without federal coordination of renewable energy markets.
1. Renewable Portfolio Standards in the United States—A Status Report with Data Through 2007, Ryan Wiser and Galen Barbose, Lawrence Berkeley National Laboratories, April 2008.
2. Assumes average cost of $2,000 per kW installed for renewable generation, 7-percent cost of capital, 35-year recovery period; U.S. average retail rate of 9.8 cents per kWh; Accenture Analysis.