Renewable Energy Certificates (RECs)  and Carbon Offsets

windmillRegulated and voluntary REC markets exist in the United States, Europe and Australia. Both of these markets are growing rapidly. Voluntary markets are driven by large buyers such as corporations and institutional customers. In the US, renewable energy sales in voluntary markets have grown at rates ranging from 40% to 60% annually for the past several years. Collectively, the compliance and voluntary renewable energy markets made up an estimated 1.7% of total U.S. electric power sales in 2006 (Bird, 2007).


RECs are designed primarily to track renewable energy production. In the United States, for example, many states have established Renewable Portfolio Standards (RPSs) . These standards require utilities to produce a certain percentage of their electricity with renewables. Utility companies can either choose to build new renewable facilities or buy RECs from other utilities who have more than met their requirement. Under an RPS, RECs function similarily to how allowances function in an emissions Cap-and-trade system. The lower the emissions cap, the more emissions reductions will be needed; the higher the RPS requirement is, the more renewable energy will have to be produced. In other words, in a quota system, additionality is not necessary for environmental integrity. Because of that RECs that are used in a quota system do not have to be tested for additionality. In the voluntary markets, RECs do not function under a quota and therefore have to be additional in order to fulfill their purpose of compensating for other emissions.  

Some certified RECs are tested for additionality. Yet these additionality tests are usually quite minimal: The regulatory test typically states that the same renewable generation must not be counted toward RPS compliance. The technology test confirms that electricity is generated from an eligible renewable energy technology (e.g. wind, solar, or geothermal). The start date test sets the earliest acceptable start date of a project (e.g. 1996). Projects that were built before the set start date are not eligible to produce RECs. To define RECs that have passed these three tests as additional, implies that all renewable energy generation capacity outside an RPS and built after 1996 were built because of the revenue they are generating from REC sales into the voluntary market.

If RECs are converted to carbon offsets without any strict additionality testing, RECs will tend to come from cheaper business-as-usual (BAU) projects (which by definition are economic without additional REC incentives). These BAU projects will thus tend to dominate the market. Truly additional projects will not be able to compete because they face additional costs or barriers.

In conclusion, the sale of non-additional RECs in voluntary market can potentially hamper truly additional projects and lead to increases in emissions.

In addition, many national and sub-national programs offer financial incentives for renewable energy projects (e.g. production tax credits, state/local tax incentives, and/or guaranteed feed-in or net metering tariffs) that may play a even more important role in funding renewable projects than REC (or offset) revenue. In other words, if the presumption is that a retired REC should count as an offset, the threshold question is whether REC revenue was sufficient to make a project “happen”. The very fact that RECs trade for as little as 0.1c/kWh in some parts of the US (equivalent to perhaps USD 1-2/ tCO2), and that production tax credits are worth about 1.8c/kWh in the US, casts some doubt . Also, renewable electricity plants operate with very low variable operating costs because unlike fossil fuel plans, they do not incur fuel costs. Therefore, the additionality of RECs must be determined during the project design phase, not the operation phase. Projects shown to have been started with the expectation and need for REC revenues are likely to be additional.


Offsets in general and RECs in particular face challenges about who has the right to claim ownership of a particular emission reduction. Establishing ownership of offset reductions from renewable energy projects is especially difficult. For example, if a wind farm is built, the emissions reductions could potentially be claimed by: the utility, the state the wind farm is located in, or the end-user of the electricity. Few policies are in place to prevent two parties from selling the same reduction or to prevent a single party from selling a reduction to multiple buyers. This lack of clear ownership is exacerbated with RECs, the attributes of which are often defined in general and ambiguous terms, which makes assigning ownership more difficult. The lack of a consistent REC definition in the voluntary and the compliance REC markets prevents RECs from functioning as a homogeneous environmental commodity.

RECs as Carbon Offsets

Because of the issues discussed above, the retirement of RECs does not automatically provide a solid basis for a GHG offsets. To do so, the following conditions should be met:

  • The RECs originate from an RPS compliance market, with adequately ambitious RPS targets and the likelihood of strict enforcement (i.e. they create true scarcity)
  • The attributes of RECs are clearly and unambiguously defined
  • Ownership issues have been resolved (e.g. through a registry)

If these conditions are met, then voluntarily buying and retiring RECs from a RPS compliance market could be an effective tactic to ensure genuine emissions reductions. Buying such RECs reduces their supply, leading to the implementation of more renewable energy projects to meet RPS targets.

Yet a more fundamental issue remains: If a sector that currently generates voluntary RECs and VERs becomes part of a regulated market with its own emissions cap, voluntary offsets based on RECs may no longer be valid.  For example, a region’s electric sector is capped, with allowances distributed to generators or retail electricity providers. If renewable energy projects in this region are reducing emissions from these capped sources, allowances are freed up. If these projects (e.g.via their RECs) claim offsets as well, this would lead to double counting for the same emission reductions. It is possible to avoid these double counting issues by designing a cap-and-trade system that enables offsets within capped sectors (by setting aside a fixed amount of allowances for up to that amount of offsets), but that has yet to occur in the GHG cap-and-trade systems implemented to date (EU ETS and RGGI).

For additional information, see:

Offset Quality Initiative (June 2009) Maintaining Carbon Market Integrity: Why Renewable Energy Certificates Are Not Offsets

Gillenwater, M. (2007). Redefining RECs (Part 1): Untangling Attributes and Offsets [Discussion paper].
Princeton, NJ: Princeton University. Available at

Gillenwater, M. (2007). Redefining RECs (Part 2): Untangling Certificates and Emission Markets [Discussion paper]. Princeton, NJ: Princeton University. Available at