State-mandated Renewable Energy Certificates (RECs) are a key financial incentive for solar projects in the U.S. As we first outlined in “Renewable Energy Certificates: A Patchwork Approach to Deploying Clean Technologies,”Oxford Journal of World Energy Law & Business, Vol. 5, Issue 1 (February 2012), the patchwork approach to the regulation and administration of RECs across the US is an inefficient way to incentivize renewable energy deployment.
Some of the figures such as installed capacity and REC values may have changed since our article was published over a decade ago, but the overall picture has not improved during that time. Within each state program, the annual value and term of RECs, as well as the number of available RECs, inhibits the growth of the renewable sector. These limitations make project planning a challenge for developers, investors and utility and state public service commission officials responsible for generation and transmission forecasting and design.
Although the sun shines less than half the days of the year in New Jersey, the state is second only to California in total installed solar photovoltaic (PV) capacity with 293 MW, 14 per cent of the US total. Colorado, the third-ranking state in USA, has less than half of New Jersey’s installed solar PV, just 103 MW—only 5 per cent of the national solar market. The driver behind New Jersey’s robust solar industry has been the state’s Solar Renewable Energy Certificate (SREC) program, which has garnered prices over $600 per megawatt-hour (MWh). While SRECs in New Jersey can be sold within the state, they have little-to-no bearing on REC prices elsewhere in USA because the fungibility of RECs is inhibited by jurisdictional inconsistencies within the country.
The term ‘renewable energy certificate’ (REC) is often used in the energy industry to describe a transferable document created for the purpose of establishing compliance with a state renewable portfolio standard (RPS), which requires a certain level of electricity generation from renewable resources.6 As the term ‘REC’ is typically referred to as a general concept, common parlance masks the important nuances in approximately 30 different REC markets across the US.
This article describes how the use of RECs in promoting the deployment of renewable energy in the US has to navigate quite heterogenous treatment among each of the US States. That heterogeneity impedes the successful commercialization and proliferation of corresponding technologies.
1. Introduction to RECs The obligatory renewable portfolio standard (RPS) adopted in certain states (but not by the federal government) requires regulated utilities and electricity retailers to acquire a minimum percentage of the energy they sell in a given year from renewable energy resources. The amount of energy obtained from renewable resources is proven either by records submitted to the applicable regulatory agency or by RECs issued by a certifying organization to represent the production of electric energy by generators using eligible renewable resources. In many cases, utilities demonstrate compliance with applicable RPS standards through the submission of RECs obtained directly by the utility from the certifying organization for utility-owned renewable generation, RECs obtained from the seller of energy to the utility or through purchase of the REC from available markets. In most, but not all, states, RECs generally reflect a MWh of energy produced. They accrue monetary value through purchase and sale either in bilateral arrangements or through sales in markets.
The sale of RECs by renewable electricity generators provides a source of revenue for development of renewable energy generating facilities. Such projects generally have substantially higher capital costs per kilowatt than traditional fossil fuel-powered generation facilities. Although the revenues from RECs do not generally close the gap between the capital costs of renewable energy and fossil fueled generating resources,8 they are nevertheless viewed by project developers as contributing to the project’s realizable return on investment (ROI). In the aggregate, therefore, RECs have supported the development of renewable energy.
2. Background The REC concept was borrowed from the tradable obligations created in New Jersey under a mid-1980s program that allowed suburban municipalities to transfer a portion of their affordable housing obligations to low-income households in urban areas. California first considered the use of RECs in 1994 during the California Public Utilities Commission’s (CPUC) electricity market restructuring proceedings. Renewable energy advocates were concerned that requiring regulated utilities to maintain ‘public purpose’ programs, such as energy resource diversity and energy efficiency, would jeopardize the deployment of renewable electricity generation due to their longer investment horizons and increased investment risk.
The CPUC directed the formation of a working group to study the effect of imposing an RPS on utilities. The working group’s August 1996 report provided an overview of an REC program. It suggested the use of tradable certificates of proof that a given amount of electricity has been generated by an appropriate renewable fuel source and that could be marketed separate from the power itself.
Although the State of California did not adopt these recommendations until 2002, the Automated Power Exchange (APX), a private entity, established a separate wholesale market in California for electricity generated by renewable resource technologies in 1998. Recognizing the greater flexibility and market liquidity of separating the environmental attributes from the commodity, APX began operating a market for ‘green tickets’ in May 1999. These wholesale green tickets were purchased and re-bundled with commodity electricity for retail green power sales.
The REC concept was introduced to the East Coast in 1997 during discussions between electric service providers and stakeholders regarding the implementation of environmental disclosure (‘electricity labels’) in New England. The context was a discussion of various proposals to verify the fuel mix and emissions data claimed by electric service providers. Indeed, Enron suggested trading the fuel and environmental attributes associated with renewable energy production separately from the commodity. After the wholesale markets were established in Massachusetts, Enron’s proposed strategy was implemented in the state by AllEnergy Marketing Company (AMC) in May 1998. AMC created a product that sold environmental attributes unbundled from electricity to retail customers under its ‘renewable upgrade service’.
The Texas PUC adopted the first compliance REC-trading program in the US in December 1999 after the Texas Legislature passed a June 1999 restructuring law that included an RPS. Six months later, in May 2000, the Bonneville Environmental Foundation based in Portland, Oregon, sold RECs to the US Environmental Protection Agency (EPA), the first such purchase by the US Federal Government. Over the ensuing decade, 29 states, Puerto Rico and the District of Columbia have established RPS policies. The majority of these states have permitted the use of RECs to fulfill these obligations. Although proposals to establish a federal RPS that may be satisfied by retirement of RECs have been proposed in the US Congress, none have been adopted as of the date of this article.
3. REC markets The majority of states with an RPS permit the use of RECs to comply with the RPS obligations. The markets in which RECS are bought and sold for the purpose of complying with state RPS requirements are generally referred to as ‘compliance markets’. As outlined below, these ‘compliance’ REC markets are marked by substantial inconsistencies between jurisdictions.
RECs that are used for state RPS compliance purposes generally must be issued by a recognized entity that certifies the actual production of renewable energy. The RECs used in the compliance markets must be derived from programs that use a meticulous tracking system to verify creation and transfers of title. There is no single certifying entity for the entire US. Moreover, some states place limits on the amount of RECs related to generating facilities located outside the state that may be used to satisfy the RPS, while others do not permit the use of such out of state RECs. By and large, the customers of compliance markets are utilities that obtain or generate renewable energy at wholesale to resell to end users. Once the REC is used for compliance with the RPS program, the certificate is retired.
Unlike the RECs used to satisfy state RPS programs (‘state compliance RECs’), the standards used to certify RECs developed for the ‘voluntary’ market to meet the needs of individuals, companies, etc to certify their renewable sourcing imperatives are generally uniform across USA. For example, Green-e Energy provides a certification and verification program that applies to renewable energy projects in all 50 states. The open, ‘voluntary’ markets, in which these RECs are traded, offer entities operating in multiple states the opportunity to purchase RECs in a standard system across state boundaries. In many cases, end users—whether universities, industries, residences or even public authorities and state governments—purchase RECs to improve their ‘green’ bona fides and to facilitate the development of renewable energy.
The voluntary REC markets permit participating entities to consolidate the procurement of green power, thus eliminating the need to buy RECs for different facilities through multiple suppliers. State RPS programs, which are focused on creating local standards for compliance, generally prohibit the use of voluntary RECs for compliance purposes due to concerns of ‘double-counting’, which occurs when the same REC is used to fulfill obligations under two different systems, such as a state compliance program, as well as a voluntary program.
4. How a MWh becomes a REC This section provides a general overview of the process in which an REC is created in both the ‘voluntary’ REC market as well as for state ‘compliance’ RECs. This is particularly important because it illustrates the relationship between RECs and the generation of electricity by renewable energy facilities. As noted below, there may be variations in this process from state to state.
Each REC is unique and tracked such that it can be claimed by only one buyer. When the REC is generated, it is assigned a unique serial number that can be tracked by a web-based system. The approach most often used in both the compliance and voluntary markets for verification of RECs is to examine the ‘chain of custody’ in electricity contracts—ie the number of RECs owned and retired by the parties to the transaction.
The tracking systems used in the administration of the state RPS compliance markets support multiple users and provide market participants with the ability to manage their own certificate accounts. The tracking systems work in a multi-phase process: (i) generator registration; (ii) issuance of certificate; (iii) verification; (iv) transfer (if applicable); and (v) retirement when the REC is used for compliance with an RPS obligation.
Registration Generators register with a tracking system as an ‘account holder’ and provide essential information regarding facility characteristics. This information, which may be verified by the system administrator, is used to establish the facility’s generation data. The data is typically drawn from the project’s meter automatically. However, in other cases, spreadsheets displaying the generation data may be sent to the tracking system and used for REC creation.
Certification A registered generator reports metered generation to the tracking system, which issues electronic certificates. Each certificate contains a unique serial number, the issue date of the certificate and details regarding the renewable generation’s attributes, including the resource used to generate the electricity, facility location, facility vintage and emissions. While the issuance of certificates is relatively standard across REC markets, the creation and compliance cycles differ by state.
For example, in New Jersey, the certificate is typically credited to the participant’s account on the last day of the month during the month following generation of the renewable electricity. By contrast, RECs are created on the 15th day in Massachusetts and Connecticut, one full calendar quarter following the quarter of generation. Thus, a REC created in January is created on 15 July. Similarly, although most states base their compliance cycles on the calendar year, New Jersey schedules its compliance cycle from 1 June through 31 May of the following year. This is important because market participants must factor in the varying procedural rules into their financial statements.
Verification RECs are subject to an annual audit by the tracking system’s administrators to confirm the accuracy of marketing claims and that RECs are sold only once. The regulatory authority is entitled to read the meter of the generated electricity and provide that data to the tracking system. This reading of the meter generally occurs monthly. REC purchasers generally are permitted to make inspections of the generating facility for the term of the REC purchase agreement. The inspection is for the sole purpose of ensuring that the generating facility is being operated and maintained in accordance with applicable standards.
Transfer The tracking system records changes to certificate ownership after both the buyer and seller have confirmed the trade. The effect of the registration of a transfer through a tracking system is that the seller no longer has the right to use the REC for any other purposes (ie compliance with an RPS program) and the buyer is granted the exclusive right to verify and take advantage of the rights of the certificate upon delivery. Transfer of a REC generally does not necessarily affect the seller’s eligibility for production tax credits or other incentives for generating electricity from renewable sources.
When RECs are traded, the seller agrees to transfer all liens, security interests, encumbrances and claims or any other interest in the transferred REC. Delivery is considered to have occurred only after: (i) title and risk of loss have both been transferred from the seller to the buyer; (ii) the transfer is properly recorded into the tracking system; and (iii) the REC has been credited in the buyer’s account. The seller pays the costs, fees and expenses associated with the sale of the transferred REC, while the purchaser pays the charges incurred in connection with the certification of the transferred RECs and any other third-party verifications concerning the transferred certificates.
Retirement The certificate is retired by the tracking system when it is used for compliance with a state RPS. When each certificate is retired, it is transferred to a specific account and the retirement is noted, which restricts the ability of a supplier from using the REC for future RPS compliance or other purposes. The utility can demonstrate compliance with the RPS program by providing a screenshot or similar disclosure that displays the disposition of the RECs in its retirement account.
5. Inconsistencies in REC Programs The general use of the term ‘REC’ misleadingly suggests that these certificates are readily fungible across state lines and RPS programs. In reality, there are important differences in the ways that state regulations characterize RECs. In addition to the variation in state compliance cycles, these differences include: (i) definition of RECs; (ii) ownership of the certificate; (iii) bundling of the renewable attribute with the commodity electricity; and (iv) price signals based on state regulations, such as the penalty for non-compliance or guaranteed minimum prices set by a state agency. These differences are important because the price and also liquidity of the certificates are impacted by the way in which RECs are characterized.
Definition State governments diverge in the way that they define RECs. While some states provide a high level of detail in defining RECs, others simply use vague references to their use for compliance with the state’s RPS. For example, Colorado specifies the attributes that must be included for compliance with the state’s RPS, including ‘credits, benefits, emissions reductions, offsets and allowances... directly attributable to a specific amount of electric energy’ generated from a renewable source of energy. Other states provide similar detail, but fail to mention whether the definition of RECs include such attributes. A handful of states merely define an REC as evidence of energy generated from a renewable facility.
Also, the definition of a ‘renewable’ source of electricity differs by state. All states regard electricity as ‘renewable’ if it has been generated from biofuels, biomass, hydro-electric, landfill gas, solar PV or wind. Also, 30 of the 34 states with an RPS obligation or goal permit the use of solar thermal technologies for compliance purposes, while 28 states permit the use of geothermal. Other technologies permitted in some states include waste heat, tidal, wave energy, energy efficiency and fuel cells. The lack of uniformity in the way that states define both ‘RECs’ and ‘renewable’ electricity leads to uncertainty and costly compliance programs for participants in the interstate energy markets, while also deterring project developers from building new generation across state lines.
Ownership REC ownership and the limitations placed on title to the certificate are determined by bilateral agreements formed between generators and power purchasers. However, where contracts are silent on the issue, the right of ownership is established under state law—by legislative, regulatory or judicial action, depending on the state. In the early 2000s, the Federal Energy Regulatory Commission (FERC) held that the administration of RECs shall fall under the jurisdiction of the states, as opposed to that of the Commission.
The output of a substantial number of existing renewable energy facilities, which may date back to the 1980s, are dedicated to specific customers under long-term power purchase agreements (PPAs) that do not separately identify either RECs or the type of ‘environmental attributes’ of renewable generation that later attained value for compliance purposes. Most of these facilities were constructed under the impetus of Section 210 of Public Utilities Regulatory Policies Act of 1978 (PURPA) and the output was sold under standardized contracts approved by state regulatory commissions pursuant to the mechanism of PURPA. In general, Section 210 of PURPA required electric utilities to interconnect with, and purchase the output of, qualifying facilities (QFs), including renewable resources, at a price equal to the purchasing utility’s avoided cost.
After the REC concept was created and their value from the generation of renewable energy from these units became evident, disputes arose between the buyers and sellers as to who owned the ‘environmental attributes’ or RECs associated with such renewable energy. In the wake of the rapid growth of the REC markets, several QFs petitioned FERC in June 2003 to determine the issue. The QFs asserted that the Commission had jurisdiction to decide whether avoided cost contracts under PURPA, which did not directly address environmental attributes and RECs, nevertheless inherently conveyed those attributes and any RECs representing those attributes, to the purchasing utility.
The QFs argued that utilities were not the intended beneficiaries under PURPA for a number of reasons. Primary among these was the limitations of the incremental cost rate for renewable energy under PURPA x 210(b). That section provided that the rate paid by utilities to a QF for renewable energy must not exceed the incremental cost to the electric utility purchaser of the next unit of energy generated or purchased. A similar limit applied to any capacity payments made. The QFs noted that environmental attributes were not mentioned in either PURPA x 210(b), or in FERC’s regulations pertaining to this section and allowance for such costs were not established by the state regulatory commissions that were responsible for setting the incremental costs for each rate-regulated electric utility purchaser. The QFs also argued that avoided cost compensates the facility for energy and capacity that are unrelated to environmental attributes. This compensation was alleged to be insufficient to account for the value of RECs or environmental attributes. Since FERC was endowed by PURPA x210 with the authority to establish the rules for determining incremental cost as well as other implementing details of Section 210, it was alleged to be the appropriate authority to make the determination whether sales by a QF included RECs or not.
A group of electric utilities responded that FERC should decline to grant a declaratory order on the subject because the issue is a private contractual matter not suited for a regulatory agency. Several state public utility commissions (PUCs) intervened in support, arguing that the issue whether the QF or the purchaser owned the RECs should be left to the states. In October 2003, FERC ultimately concurred with the state PUCs and determined not to decide the issue. It found that RECs were created under state law and, therefore, should remain a state issue. FERC reasserted this position in an April 2004 ruling in which it denied requests for rehearing.
Bundling of RECs with commodity electricity Renewable power has two components—the commodity electricity plus the separate renewable energy attribute of the electricity, which attains value because it permits compliance with a state’s RPS program. Thus, the renewable energy attribute (ie the REC) can be used to create an additional revenue source for the generator. The RPS obligation creates the condition that makes establishment of a market to monetize the value of the obligation. As a result, RECs have been recognized as a commodity separate from energy that may be conveyed together (bundled) in a PPA or sold separate from the generated energy (unbundled). Developers benefit from unbundled RECs because potential customers of the renewable attribute might not otherwise be able to purchase the commodity electricity itself due to issues regarding distance, intermittency or transmission inefficiencies.
REC price limits created by state regulation A number of states set penalties for non-compliance with the RPS, called an ‘alternative compliance payment’ (ACP). The prices set on these penalties create a ceiling for REC prices because electricity providers could simply opt to pay the penalty if REC prices were to exceed the ACP. In markets where renewable energy supply is low, such as New England, REC prices tend to trade near these price signals.
Only a few states offer a price floor for RECs, which ensure minimum revenue from participating in the compliance markets. For example, the Massachusetts Renewable Energy Trust offers to purchase a limited number of RECs for a period of up to 10 years, which ensures a predictable stream of revenue from the proceeds of the certificates generated by the facility.
Similarly, the New Jersey Board of Public Utilities (BPU) authorized the state’s IOUs to establish an SREC program. Under this program, the IOUs conduct a solicitation process to enter into long-term (10-to-15-year) Purchase and Sale Agreements (PSAs) for SRECs from new solar projects with capacities of up to 500 kW. The SREC price under these PSAs is constant for the entire term of the agreement, thus providing a stable flow of revenue for the project and mitigating the associated political and market risks. SRECs created under the solicitation process are then sold by the utilities via auction to energy suppliers, who are required to pay a Solar Alternative Compliance Payment (SACP), in the event that they do not meet the requirements of New Jersey’s Solar RPS.
As discussed in this article, RECs offer a potential stream of revenue for qualifying projects. Under certain circumstances, this can lead to the development of a solar or wind industry in locations where these resources might otherwise not be an economical venture, such as solar in New Jersey or wind in Ohio. However, the less-than-ideal regulatory framework for RECs can cause difficulty for entities with interests in multiple jurisdictions.
In a best case scenario, policymakers will establish a more uniform, nationwide approach for RECs. In the meantime, market participants will be required to develop innovative ways for engaging in transactions across jurisdictions. For example, a new platform recently launched the first institutionally oriented electronic over-the-counter (OTC) trading platform focused on the REC markets. This type of OTC platform offers the REC markets something that current policymakers at the state and federal levels cannot or will not—a market-wide approach to increase liquidity, price discovery, and post-trade transparency.
The non-standardization of RPS obligations, rules and regulations is particularly problematic in the utility industry—the very participants targeted by the myriad state RPS programs. Utilities’ customer bases may be far removed from the prime locations for siting renewable energy facilities, which can be located in a distant state or even region. This underscores the importance of developing a nuanced understanding of RECs because the electrons generated from renewable resources must often be carried across multiple states, regions and transmission organizations.
The flow of renewable electricity through states with REC programs that are characterized by widely divergent ambition and based on disparate definitions and legal concepts denies the energy industry the kind of robust incentives and long-term certainty required by investors to engage in relatively risky renewable energy ventures. As these programs continue to evolve in the US, electricity producers and power purchasers operating in multiple jurisdictions will require increased guidance related to the REC framework at both the state and federal levels.