A new report from the Brattle Group aims to bridge the gap between policies that aim for a future free of carbon dioxide emissions and market mechanisms to achieve those goals.
The report, How States, Cities, and Customers Can Harness Competitive Markets to Meet Ambitious Carbon Goals: Through a Forward Market for Clean Energy Attributes, calls for the establishment of a forward clean energy market (FCEM) that would create a competitive market for clean energy attribute credits (CEACs) defined as a certificate for one megawatt hour of clean energy supply to meet a state’s goal. The CEAC would be technology neutral and could come from a carbon-free resource, whether it is wind, solar, hydro, nuclear or other qualified clean resource types (depending upon the state’s energy policy goals).
The mechanism “would be a good option to resolve the ongoing debate about how states can achieve policy goals while retaining the integrity and benefits of the competitive wholesale markets,” Kathleen Spees, a principal at Brattle and a co-author of the report, said.
The Brattle report was done for NRG Energy, which submitted it to the House Energy and Commerce Committee in response to questions posed by the committee in its effort to develop comprehensive climate legislation. NRG Energy and other generators have participated in unsuccessful legal challenges to state programs under which zero emission credits (ZECs) are paid to nuclear power plants in Illinois, New York and New Jersey as part of an effort by those states to keep the plants in operation.
Under the proposal, any form of qualifying non-CO2 emitting resource could submit an offer to sell CEACs into the FCEM. The offer would be the minimum price the seller needs to develop or maintain a clean energy project. Demand for CEACs would be from a state as well as from load-serving entities, cities, companies and other buyers to meet their carbon reduction goals. The market would clear the lowest cost supply offers to meet demand and establish a competitive clearing price at which all transactions would settle.
Cleared offers would be paid that price for a future delivery term of one year; new resources would have the option to lock in a price for a multi-year period of approximately seven years to provide developers with sufficient long-term price certainty to support the financing of new projects.
An FCEM could be administered by a state agency, a multi-state organization, or an independent system operator.
The report envisions that states with mandatory targets for meeting clean electricity goals would make up the majority of bidders.
Brattle notes that over 100 cities and multiple states have committed to transition to 100% clean or renewable energy in the next two or three decades and nearly three-quarters of the Fortune 100 companies have adopted sustainability and renewable energy goals.
The FCEM concept can work with or without the introduction of plans that would charge emitters for their CO2 emissions either through a cap-and-trade program or a CO2 price. The authors say their proposal avoids one of the major pitfalls of those programs, leakage. Electricity production and associated emissions can shift or “leak” from the areas that price carbon to those that do not, unless border adjustments are applied, they note. The FCEM is also a solution that is workable in regions serving states with very different clean energy goals, including regions where some states have 100% clean electricity targets and others have no clean energy policy.
“When we flip [the concept] to the demand side, what is neat about FCEM is there are no transfer payments or cross subsidy concerns,” Spees said. “As a clean energy buyer, you establish your own procurement goals and you get what you pay for.”
In Brattle’s concept, entities could enter the FCEM market to buy only the amount of CEACs they need to meet their needs. So, in a multi-state market, any single state entity would only have to buy as many CEACs as they need for their programs, building flexibility into the program. In that respect, the FCEM concept is similar to a renewable energy credit (REC) programs that follow well established legal precedent that allows a state to set energy policies within its borders.
And while the FCEM would be modeled on some aspects of wholesale power markets, it would operate separately from those markets. Generators would still receive payments for energy, capacity and ancillary services sold into the competitive markets, but CEACs would provide a separate income stream for them.
CEACs would “provide one piece of the investment signal, but only one piece,” and it would increase the transparency of environmental program costs, Spees said. Energy, capacity, and CEAC payments would form separable, transparent portions of the customer bill, and total costs to end users would fall if these payments were unbundled and procured in a fully competitive fashion (through existing markets for energy and capacity, and through the FCEM for the environmental attributes).
The potential for rising costs associated with clean energy targets under traditional approaches that call for technology specific incentives and contracts is one of the problems that Brattle set out to solve in its white paper.
Those approaches have the potential to be expensive and to transfer risks from producers to customers, the report says. In many cases, the costs have so far been modest, but only because the goals have been modest, the authors say. As states ramp up to meet more aggressive carbon reduction targets, those costs could rapidly increase, they say.
The other problem Brattle addressed was the ability to use an in-market approach to retaining existing clean resources including nuclear plants. This could be solution to the debate surrounding the treatment in some markets of clean energy attribute payments, such as zero emission credits (ZECs) paid to nuclear power plants in Illinois, New York and New Jersey, which have been widely criticized by generators and have faced – and withstood – multiple legal challenges. ZECs have been seen as a tool in which to keep nuclear generation online. Resources receiving such payments, as well as those procured through bilateral contracts, may be treated as “out-of-market” and subject to what is known as a “minimum offer price rule,” under rule changes being considered for the PJM Interconnection capacity market.
In Brattle’s plan resources receiving CEACs would be considered “in-market” for purposes of the wholesale capacity market rules, thus avoiding the application of the minimum offer price rule and bridging “the divide between state carbon goals and wholesale market reliability and least-cost planning criteria.”
And if a “fancier” dynamic version of CEACs were used, it could mitigate the negative pricing problems that sometime affect the wholesale power market, Spees said. Under a regime with “dynamic” CEACs, a generator would be paid based upon the displacement of CO2 emitting generation.
NRG Energy is now working to revise the Illinois law and was a supporter of the Competitive Clean Energy Act (SB 135) that would establish an FCEM program to replace the existing ZEC and REC programs.
“We are looking for bold action, but a lot of policies look suspiciously like state give-aways” to nuclear generators, Travis Kavulla, vice president of regulatory affairs at NRG, said.
Kavulla sees the FCEM plan as a market-based successor to ZECs that brings previously hidden costs “out of the shadows.”
In addition to state entities and regulated utilities, the FECM mechanism could be used by a variety of buyers, including corporations and public power utilities, Spees said. “At the end of the day, states and buyers need to take leadership on this, to work for a solution such as the FCEM to help them meet their goals cost-effectively. This is what we need to maintain compatibility with wholesale markets.”
