Reimagining REC Markets: Integrating Additionality and Emissionality into a New Carbon-Free Paradigm

Reimagining REC Markets: Integrating Additionality and Emissionality into a New Carbon-Free Paradigm

By Yuri Horwitz

With the recent passage of the Inflation Reduction Act, the federal government has taken a bold step towards a carbon-free future for America. There remain critical obstacles; including rising interest rates, supply-chain issues, tariffs, and module costs. But we have embarked.

States looking to follow the federal government’s lead on climate -a refreshing change- have a powerful framework to leverage and replicate: renewable portfolio standards (RPS) and corresponding renewable energy certificate (REC) markets. Corporations looking to offset their carbon footprint, specifically Scope 2 but indirectly also 3 emissions that represent the Scope 2 emissions of their supply chain, can (and should) engage in updating these markets to ensure the markets are designed to achieve their carbon-free goals.

This article takes a fresh look at RECs, why they are important, how they can drive additionality and emissionality, and how RECs can be an integral part of customers’ carbon-free goals.

PART I: What Is a REC?

A REC is an intangible certificate that represents the environmental benefits associated with a specific amount of electricity produced by a renewable energy resource, generally one megawatt-hour (MWh)[1].When renewable electricity is produced, it enters a shared electricity grid and becomes indistinguishable from electricity generated by other sources – similar to water flowing into a network of pipes. Although individual electrons cannot be tracked on the grid, RECs enable renewable energy to be independently measured, tracked, and traded like other commodities. REC markets also ensure integrity because the environmental benefit of a REC can only be counted once when a customer “retires” the REC to claim it.

Each REC can be tagged with information about the project that produced it, the project’s location, technology type, and the time period when the electricity associated with the REC was generated. The electricity production is first recorded by a project’s electric meter and is then communicated electronically to third-party environmental registries or regional transmission organizations (RTOs) who validate and award the REC.[2]

There are generally two types of RECs in the United States: compliance RECs and voluntary RECs.

Compliance RECs were first introduced in the 1980s as part of an incredibly successful state market-based mechanism, the Renewable Portfolio Standard (RPS), for driving the expansion of renewable generation. In these RPS compliance markets,[3] retail electricity suppliers and utilities are mandated to purchase a defined (usually increasing) percentage of their electricity supply from renewable sources. These buyers are generally referred to as “compliance buyers,” and they are required to either produce renewable electricity themselves, where allowed, or buy RECs in order to satisfy their RPS requirements. If these buyers do not meet the RPS requirement, they are required to pay an Alternative Compliance Payment (ACP), a non-compliance fee that acts as the price ceiling for RECs within a given compliance year.

Demand within a compliance market is set by the RPS and generally increases year over year. If demand is high and supply (renewable energy projects producing RECs) is low, REC prices will rise towards the ACP. As more renewable energy gets built within the market, REC supply will increase, and REC prices will decline.

Renewable energy projects that do not sell RECs into compliance markets can still sell RECs to businesses, homeowners, governments, and non-profits who are interested in purchasing these RECs on a voluntary basis. These voluntary customers may purchase voluntary RECs to meet their renewable procurement goals, or to combine these RECs with “brown” electricity from coal and other fossil fuels and “green” their energy supply. If a family purchases green energy through their utility or retail energy supplier, this supplier is likely combining their preexisting brown electricity with voluntary RECs to offer renewable energy to customers.

Voluntary market pricing has been increasing over the past couple of years, largely driven by corporate appetite for RECs to meet Environmental, Social, and Governance (ESG) goals. Unlike the compliance markets, the pricing in a voluntary market is not tied to an ACP. It functions more similarly to a traditional market; as demand for renewable electricity goes up (relative to supply), prices follow until supply begins to meet that demand. Conversely, as demand for RECs goes down, so do prices. Increased corporate demand has helped incentivize the development of renewable energy projects in non-compliance markets, providing another revenue source for these projects.

The owner of a renewable energy project can either sell the electricity and the RECs produced by the project together (called a “bundled” product) or sell the electricity and RECs separately. The value of a REC can vary depending on the type of renewable project that produced it, the duration of the contract to purchase it, whether the RECs are being sold into a compliance market or a voluntary market, and what the ACP – essentially the price ceiling in compliance markets – is set to.

For example, solar RECs are generally sold at a premium; longer duration contracts are usually signed at lower prices; and RECs generally trade at higher prices in compliance markets than in voluntary markets. Prices in compliance markets range from $3 per REC for some types of technologies to hundreds of dollars for solar RECs in some compliance markets. Compliance RECs compose anywhere from 25-80 percent of a project’s revenue depending on the market. Voluntary RECs typically compose 10-20 percent of a project’s revenue.

The additional revenue earned by renewable generators through REC sales is essential for enabling renewable projects to compete with heavily subsidized fossil-fuel generators. The REC markets in the United States are some of the most sophisticated environmental markets in the world.[4] They are particularly important because of their integrity and their “traceability”—their ability to trace the production of renewable energy across multiple states, a variety of technologies, and across multiple jurisdictions, and millions of owners.

The REC markets also enable governments, businesses, and the public to directly participate in valuing renewable energy and assigning long-term value to renewable energy assets – driving the energy transition.  While large organizations often negotiate complex virtual power purchase agreements (PPAs) to procure large volumes of renewable electricity and RECs bundled together, unbundled REC markets enable individuals and smaller organizations, like churches and schools, to also participate in the renewable energy market and purchase their electricity from clean sources even if they cannot procure electricity directly from onsite or offsite generation. Only if a customer owns and retires a REC can a renewable energy usage claim be made.

PART II. REC Markets and Additionality

How REC Markets Drive Additionality

The economic concept of additionality is a bit like the “but for” test in tort law: but for a specific action or intervention, a certain outcome would not take place. In the renewable energy industry, additionality generally means that but for a specific agreement to buy energy from a specific facility, that facility would not be built.[5] Many customers look to buy electricity from new renewable energy projects to create additionality.[6] Some have raised concerns that current REC markets do not effectively drive additionality or the development of new renewable generation. We disagree.  

RECs and REC markets play a key role in driving new renewable energy deployment and projects by guaranteeing an income stream for new projects. Project owners earn a significant portion of their revenue by selling their project’s RECs, either to its electricity off-taker in a bundled sale or independently to third parties. In either case, revenues from REC sales often provide the critical cash flows that enable a project to move forward.  

Large corporate and institutional customers drive around 25 percent of all large-scale solar build in the United States. Most of these customers procure their electricity through a financial instrument called a “virtual PPA.” Under a virtual PPA, a customer commits to purchase electricity from a specific project at a fixed price, and instead of delivering electricity directly to the customer, the project delivers its electricity onto the grid at a floating market price. The customer then pays to or receives from the project owner the difference between the fixed and floating prices, guaranteeing a fixed revenue stream for the project,[7] making it financeable and hence enabling the project to be built.

Even when these customers buy a bundled product (the purchase of both RECs and electricity) through a virtual PPA, they are still purchasing RECs. When the renewable project delivers electricity onto the grid, that electricity is sold through the RTO or to the local utility, and the corporate customer (buyer) is really transacting on a financial swap. The project then keeps the green attributes associated with generation in the form of the RECs and those RECs are sold to the customer for retirement.

Corporate buyers can (and should) still claim additionality (if that is their critical metric) if the virtual PPA enables new generation. However, these buyers should recognize that this approach is really a combination of a financial instrument plus a REC procurement; and should also recognize that other financial instruments may enable new renewable energy projects just as meaningfully. For example, if a customer’s goal is to provide a financeable income-stream for a project to drive new renewable energy capacity (additionality), they could alternatively purchase RECs from the project over a long period of time or finance the project with critical tax equity – or both.

Consider the following example: A project in the Southwest Power Pool (SPP) may have the opportunity to sell its RECs unbundled from the associated electricity. A project owner in the SPP might find that the voluntary REC market provides a better premium for its renewable energy than the utility - which drives healthy competition in regulated territories. A corporate customer hoping to procure renewable energy and drive new capacity could contract to purchase 10–15 years of RECs from the project, providing a financeable revenue stream and creating additionality similarly to a PPA. Further, enabling projects in SPP through such a REC strip may have a more profound impact on reducing carbon emissions than transacting on a virtual PPA in the California Independent System Operator (CAISO) given the higher carbon intensity of the SPP grid. More on that in a moment.

In short, by purchasing RECs, customers can provide critical cash flows to projects that would not have been financially viable otherwise. Over the last decade, Sol Systems has worked with over 20,000 customers to provide long-term REC financing, and by doing so has facilitated the development of tens of thousands of new projects – that is additionality.

RECs are Critical Regardless of Additionality

Of course, RECs can also be purchased from preexisting renewable energy projects. Although revenue generated by REC sales can be critical to an existing project’s continued operation, these purchases do not drive new construction and therefore generally are not associated with additionality. While we understand (and support) the preference for new build, preexisting RECs are also critical to the industry for a couple of reasons.

First, RECs enable project owners and customers to track and transact renewable energy in a market in which electrons are liquid and impossible to track. Second, investors rely upon merchant unbundled RECs (sometimes from the beginning and sometimes after a PPA term) in their underwriting to finance renewable energy projects just as they rely upon merchant electricity. The opportunity to eventually sell these “merchant” RECs is an essential basis for an owner’s initial investment in a new project. Although the decision today to purchase RECs from an operational renewable energy facility does not lead to new build (because the project has already been built) the current market for unbundled RECs was a core part of the initial underwriting and financing of the project when it was developed years ago.

Customers that purchase and retire RECs from preexisting renewable energy assets can still claim renewable energy use by offsetting their non-renewable or brown electricity consumption with merchant RECs. They should just be clear about what type of RECs they have purchased,[8] and about the fact that the REC purchase did not drive new or additional solar projects. Moving forward customers should also begin to disclose the carbon “benefit” of these RECs and compare that to the carbon footprint of their current electricity needs. A concept often referred to as emissionality or locational marginal emissions.

Part III: REC Markets and Emissionality

One criticism of REC markets is that they were designed to drive renewable energy, and have succeeded, but they are not calibrated to necessarily incentivize the outcome we are all trying to achieve – a net zero economy. This is a fair criticism, and one that becomes more cogent and important as we build more renewable energy. We should not be incentivizing new renewable energy build in a market that is already saturated with renewable energy the same way we incentivize renewable energy build in a market that relies upon coal. REC markets have been critical to supporting and catalyzing new renewable energy capacity. Moving forward, they must better capture, reflect and value the carbon emissions that this new renewable energy capacity is displacing – also referred to as “avoided emissions”.

The implicit environmental value of renewable electricity corresponds to the carbon and other pollutants associated with the non-renewable electricity it displaces, usually measured in CO2e.[9] The carbon intensity of a grid changes throughout the day and is a function of the fuel sources (coal, natural gas, bunker fuel) used by generation facilities on the grid at a specific time. Each fuel source has a CO2e impact, and the carbon footprint of each utility territory or RTO at a given moment is an amalgamation of these different generation facilities that are producing. Companies like Watt-Time are endeavoring to measure this impact in real-time.

REC markets are critical tools for this endeavor. These markets could (and should) tag each REC with the corresponding carbon intensity of the grid at the time and location of their production to provide customers with both the traditional MWh displaced metric, and also a CO2e metric measured in tons.[10] This is exactly the information customers need to measure, trace, and ultimately price the specific environmental impact of RECs with an aim to fully displace carbon on the grid.  This approach to valuing renewable energy based on actual displaced emissions is often referred to as “emissionality,” and several large corporations are working to develop better methods of accounting for this metric.

While these changes would add complexity to existing REC markets, the benefits would be substantial.

First, utilities, retail energy suppliers, corporations and other consumers could better understand the actual carbon reduction associated with each REC and value RECs based on the corresponding CO2e value. This would incentivize renewable energy development in utility and RTO geographies with a higher carbon footprint, accelerating the transition to carbon-free electricity. This would also enable states to transition RPS programs into carbon-free programs by linking the language and metrics of carbon (tons offset) with the language and metrics of RPS markets (MWh produced and offset). 

Second, the changes would help large corporations, academics, and the SEC who are struggling with how to integrate RECs into Scope 2 requirements because RECs measure MWhs of renewable energy produced, and Scope 2 requirements focus on carbon displaced. Customers can currently offset the electricity they consume with RECs without an understanding of the carbon intensity of the grid in which they operate, or the emissionality of the RECs that they procure. They may be procuring too many RECs or procuring too few.[11]

Tagging RECs with a carbon intensity (in tons of CO2e) would enable these customers to precisely match their REC procurement and carbon credit procurement under one framework to achieve verifiable carbon neutrality. Creating a 7-year transition period for customers and markets to integrate RECs based on their emissionality into their Scope 2 plans would enable both the market to evolve, and customers to better measure and plan for their carbon-free future.

Our Conclusion: A New Architecture for the Future

Over the past 14 years Sol Systems has helped develop or finance tens of thousands of renewable energy projects throughout the United States. In our experience, REC markets provide a proven and effective framework for valuing, incentivizing, and transacting with renewable energy resources. It is critical for customers, utilities, policymakers and other stakeholders to understand the significant potential of these markets and also possible areas of improvement. We urge academics and policymakers, especially those who may not actually be actively involved in the renewable energy industry, to listen to and engaging with the practitioners and participants currently building this industry.

We recommend three primary adaptations for our industry:

  1. Redefine & Broaden the Concept of Additionality: Additionality is a core principle for many large corporations seeking to catalyze the development of new renewable energy capacity. Additionality is not the same as emissionality, but it does drive the displacement of carbon-intensive fuel sources on the grid. We urge corporations to rethink how they define additionality with respect to renewable energy procurement and adopt a more flexible and broader approach that could incorporate long-term REC procurement and/or tax equity financing, which can represent 30-40 percent of a project’s financing needs. From our perspective, additionality should mean providing critical additional financial certainty for a project that enables that project to move forward; and can be achieved through multiple strategies.
  2. Integrate Emissionality into REC Markets: RTOs should move quickly to integrate emissionality into REC tagging and tracking so that market participants can better integrate carbon intensity and emissionality into their REC procurement. These RTOs should meet to discuss an appropriate and uniform application of the concept. Market participants, including NGOs and interested corporations, can help fund these efforts if needed. This effort should begin in the United States, but should be leveraged and replicated in other countries, beginning with those that are most critical to decarbonization. Emissionality gives us the tools and the language to talk constructively about renewable electricity production, RECs and carbon intensity interchangeably.
  3. Integrate REC Emissionality Into Scope 2 Requirements: We urge academics and policymakers to leverage and adapt preexisting REC markets to architect and achieve the carbon-free future we are all focused on creating. Current REC markets are efficient and transparent platforms to transact both RECs and related CO2e reduction. Rather than carving out REC procurements from Scope 2 compliance, as some have suggested, REC markets should be a key tool and instrument for implementation. Corporations currently offset their electricity and related carbon footprint with REC procurement. We recommend a 7-year ramp towards a framework where corporations reach their Scope 2 requirements through the CO2e of their REC procurement, a more precise methodology that bridges RECs (measured in MWh) and carbon (measured in CO2e). This enables the appropriate development of this market architecture.

[1] For scale, the average U.S. home uses around 7-10 MWh of electricity annually depending on size, location and consumption

[2] For example, PJM-GATS uses Energy Attribute Certificates to track the regional production of electricity by all generation types in 14 jurisdictions from Illinois to North Carolina

[3] 30 states and the District of Columbia currently have compliance legislation in place. Several other states have enacted voluntary programs

[4] The combined market for compliance and voluntary RECs in the United States is valued at $5 - $10 billion annually

[5] Additionality is a determination of whether an intervention has an effect when compared to a baseline. Interventions can take a variety of forms but often include economic incentives. The concept was initially used in carbon offset markets.

[6] Actually measuring the environmental impact of displacing this electricity in a certain location and at a certain time is a bit more complicated, and new “additional” build in an electricity market that has no carbon footprint does not provide environmental benefits

[7] There are situations where this can be reversed

[8] For example, “We have offset all of our electricity for this facility with renewable energy from an operating wind farms located in our utility territory.”

[9] Currently the environmental impact of electricity production and other human activities is measured in CO2e. This measures the impact of a given activity on global warming (the global warming potential) over a century and compares it to the same impact of one ton of carbon dioxide over the same period of time. This is an attempt to standardize and measure the impact of human activities on climate. Environmental markets must improve tracking and valuation of other pollutants, e.g., mercury, nitrogen oxides, and particulate matter. CO2e is a good start.

[10] Carbon intensity of the grid could be measured at the RTO level, at the utility level, or at the actual nodal level. The greater the specificity, the more precise the market can be in incentivizing localized environmental benefits, but the more complex the market tracking and systems need to be. We would suggest utilizing a RTO average as a start.

[11] Offsetting electricity consumption with RECs is a critical first step but does not entirely reflect the carbon intensity displaced by renewable energy or the carbon intensity of the electricity consumed. Customers could be over-purchasing RECs because the grid they are operating in is has a low carbon intensity compared to where they are purchasing RECs from; or under-purchasing RECs because the grid that they are purchasing RECs from has a low carbon intensity compared to where they are operating.

Recent Articles...