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Renewable Energy Certificates and Renewable Portfolio Standards

To participate in the Renewable Energy Certificate market, one must be able to navigate differing state standards and to adjust to still-evolving state, regional and federal initiatives.
By Jonathan Dettmann, Andrew Ritten and Angela Snavely | April 29, 2011

In recent years, Renewable Energy Certificates have surfaced as one of the more viable of several environmental entitlements supporting a shift to cleaner energy. This is due at least in part to the fact that the regulatory mechanisms supporting these certificates—most notably, renewable portfolio standards (RPSs)—have emerged more quickly than mechanisms supporting other types of entitlements such as cap-and-trade systems giving rise to markets for carbon credits or offsets. In this article we will describe the regulatory landscape for RECs and what opportunities and challenges they afford.   


An REC, sometimes called a Renewable Energy Credit or a Green Tag, is a tradable commodity that represents the right to the environmental, social and other nonpower qualities of renewable energy generation. One REC can be created for every 1 megawatt hour of renewable energy generated. The REC can either be sold bundled with or unbundled from the renewable energy itself. If sold separately, however, the energy itself is no longer considered renewable because that attribute is now bound up in the REC. 


RECs were created as tools for measuring and monitoring a utility’s compliance with any applicable RPS, which is a regulatory mechanism for incentivizing the development of renewable energy. Today, RECs continue to be used to satisfy these compliance requirements, but they also can be used for voluntary renewable energy targets that certain organizations might have. Once the REC is used for either compliance or voluntary purposes, it cannot be used or sold again. Instead the REC must be retired in order to prevent double counting of the renewable energy. 


Two mechanisms are used to facilitate the REC trading market: contracts and regional tracking facilities. Of the two, REC tracking facilities, described in more detail below, provide greater transparency when tracking RECs from their point of creation to their point of final use. 


This article reviews the various aspects of state RPSs, focusing in particular on standards applicable in California, Colorado, Minnesota, North Dakota and South Dakota. In addition, we will provide a brief description of two regional REC tracking facilities, the Midwest Renewable Energy Tracking System (M-RETS) and the Western Renewable Energy Generation Information System. Finally, given ongoing interest in enacting a federal renewable or clean energy standard, we will provide a description of the various elements of those proposed standards.


State RPS Programs


Among other things, RECs can be used toward compliance with an RPS, also called a renewable electricity standard (RES). An RPS is a target for renewable energy set as a percentage of overall power consumption, with targets gradually increasing over a period of time. Roughly 30 states have now established RPSs, with RECs counting towards compliance goals. In addition, seven states have enacted renewable portfolio goals. 


A renewable portfolio goal differs from an RPS in that compliance with the objective is voluntary and there are no penalties or sanctions for a retail provider of electricity that fails to meet the objective. For example, both North Dakota and South Dakota have established voluntary renewable goals of 10 percent by 2015. The renewable energy sources that count for compliance purposes are consistent in both states and include the following: solar, wind, hydroelectric, biomass, geothermal, hydrogen produced from certain resources, and recycled energy producing electricity from unused waste heat resulting from combustion. Both North Dakota and South Dakota allow a portion or all of the renewable energy objective to be met by the purchase and retirement of RECs that represent renewable energy produced from those sources. 


While state RPSs have helped encourage the development of the REC market, one problem is that the requirements for the various RPS programs can vary significantly—not only in terms of the percentage goals, but also in terms of the types of RECs that count toward compliance. For example, states can differ in terms of what renewable sources they allow (hydropower), and even the geographic proximity of the generation source can matter. The result has been an increasingly fractured market for RECs, with wide differentiation in pricing. Following is a brief comparison of the RPS standards for California, Colorado and Minnesota. 


California:  California’s RPS was originally established by the California legislature in 2002 and is collaboratively implemented by the California Public Utility Commission and the California Energy Commission. Under the RPS, California’s retail sellers of electricity were required to have 20 percent of their retail sales per year derived from eligible renewable energy resources by Dec. 31. The following renewable energy sources are permitted to satisfy the California RPS: solar thermal electric, solar photovoltaics, landfill gas, wind, biomass, geothermal, municipal solid waste, digester gas, hydroelectricity if produced by certain facilities, tidal energy, wave energy, ocean thermal, biodiesel and fuel cells using renewable fuels. 


Pursuant to Executive Order S-14-08 signed on Nov. 17, 2008, the RPS requirement is increased to 33 percent by 2020 and applies to all utilities. Also, Executive Order S-21-09 signed on Sept. 15, 2009 directed the California Air Resources Board to adopt regulations for the 33 percent requirement. On Sept. 23, the CARB approved regulations for implementing what is now called the RES. Pursuant to this order, in California, the air resources board is to work with the utility and energy commissions to harmonize the 2010 standard with the 2002 portfolio standard. Furthermore, as discussed in more detail below, the CARB is to monitor the CPUC decision-making process as it relates to the use of RECs for compliance purposes (however, in the RES context they will be called RES certificates). 


Currently, RECs and the energy procured together as a bundled commodity are eligible for the California RPS. In a March 2010 order, the CPUC ruled that unbundled RECs (or TRECs or REC-only as used in the order), subject to certain restrictions, may be used for compliance with the RPS. In addition, the March 2010 decision provided that a TREC may be traded for three calendar years from the year the electricity associated with the TREC was generated before it must be retired for RPS compliance. The use of TRECs for compliance with the RPS was stayed in May 2010, however.


On Jan. 13, the CPUC lifted the stay that was issued in May 2010. In addition, the Jan. 13 order extended the sunset date to Dec. 31, 2013, for the following items included in the March 2010 order: the 25 percent temporary cap imposed on large investor-owned utilities and electric service providers for the amount of TRECs that can be used for RPS compliance purposes and the temporary limit on the price investor-owned utilities are allowed to pay for the TRECs used for RPS compliance purposes to $50 or less per TREC. 


Colorado: Colorado’s RPS requires each qualifying retail electric service provider to provide specific percentages of renewable energy and/or recycled energy for retail electricity sales in Colorado according to the following schedule:


• 3 percent for 2007.


• 5 percent for 2008-’10. 


• 12 percent for 2011-’14.

 
• 20 percent for 2015-’19. 


• 30 percent for 2020 and for each following year.


Colorado's RPS also requires all electric cooperatives and each municipal utility serving more than 40,000 customers to provide specific percentages of renewable energy and/or recycled energy for retail electricity sales in Colorado according to the following schedule:


• 1 percent for 2008-’10.


• 3 percent for 2011-’14.


• 6 percent for 2015-’19.


• 10 percent for 2020 and each following year.


Colorado allows the following renewable sources to be used for satisfying the above thresholds:  solar radiation, wind, biomass, hydroelectricity from resources with a nameplate rating of either 30 or 10 megawatts or less depending on when the facility came into existence, geothermal, recycled energy and fuel cells using renewable fuels. Recycled energy is energy produced by a generation unit with a nameplate capacity of not more than 15 megawatts that converts the otherwise lost energy from the heat from exhaust stacks or pipes to electricity and that does not combust additional fossil fuel.

Colorado applies a multiplier to certain types of renewable energy. For example, each kilowatt-hour of eligible energy generated in Colorado is counted as 1.25 kilowatt hours for complying with the Colorado RPS. The multipliers also apply to RECs representing electricity generated by applicable renewable energy sources. 


Colorado requires that all post-regulation contracts for RECs clearly specify who owns the RECs associated with the energy generated by the facility. In addition, Colorado also has specific regulations regarding provisions that are required for renewable energy supply contracts (bundled REC agreements) and renewable energy credit contracts (unbundled REC agreements). The eligibility to use RECs for compliance expires at the end of the fifth calendar year, following the calendar year during which they were generated. While there is not a specific dollar cap on the amount a utility can pay for an REC, the Colorado regulations limit the net retail rate impact of actions taken by an investor-owned utility to comply with the RPS to 2 percent of the total electric bill annually for each customer of that utility. 


Minnesota: Minnesota’s nuclear utilities are required to meet the following schedule for RPS compliance:


• 15 percent by Dec. 31, 2010.

 
• 18 percent by Dec. 31, 2012.

 
• 25 percent by Dec. 31, 2016.


• 30 percent by Dec. 31, 2020.


Of the 30 percent that must be generated by 2020, at least 25 percent must be generated by solar energy or wind energy, with no more than 1 percent of the 25 percent requirement being generated by solar energy.


The standard for other Minnesota utilities requires that eligible renewable electricity account for the following percentages of retail electricity sales to retail customers:


• 12 percent by Dec. 31, 2012.


• 17 percent by Dec. 31, 2016.


• 20 percent by Dec. 31, 2020.


• 25 percent by Dec. 31, 2025.


The following renewable sources are permitted to comply with the Minnesota program:  solar, wind, biomass, hydroelectricity produced by facilities with capacity under 100 megawatts, and hydrogen generated from certain resources. The program treats all eligible renewables equally and may not ascribe more or less credit to energy based on the state in which the energy was generated or the technology used to generate the energy. RECs are eligible for use for RPS purposes in the year of generation and for four years following the year of generation (all credits generated during 2008, regardless of the month, will expire at the end of 2012). Notably, Minnesota’s nuclear utilities may not sell RECs to other Minnesota utilities for RPS-compliance purposes until 2021. 


On Sept. 9, the Minnesota Public Utilities Commission issued an order determining ownership of RECs for power purchase agreements made pursuant to the 1994 Minnesota Wind and Biomass Statutes and the 1978 federal Public Utility Regulatory Policy Act. The MPUC determined that the utility owns the REC received pursuant to power purchase agreements entered into under the Wind and Biomass Statutes, unless the generator can demonstrate that the power purchase agreement is not silent as to REC ownership and explicitly provides otherwise. Essentially, the REC ownership goes to the utility in this instance because the utility likely paid a premium for the renewable energy so that it could claim the energy to fulfill its renewable energy obligations arising under the Wind and Biomass Statutes. For RECs received pursuant to power purchase agreements entered into under PURPA, the generators own the RECs absent contractual provisions to the contrary because the power purchased by utilities pursuant to PURPA was purchased to meet statutory demands entirely different from those imposed by the Wind and Biomass Statutes. 


Attempts to Standardize: M-RETS and WREGIS


A tracking facility is an electronic database that is used to track the ownership of RECs, much like an online bank account. The M-RETS and WREGIS are examples of two regional tracking facilities that are in operation today. A tracking facility provides the following services for the REC market:

 
• Issues a uniquely numbered electronic certificate for each megawatt-hour of electricity generated by a generation facility registered in the system.


• Tracks the ownership of certificates as they are traded.


• Retires the certificates once they are used or claims are made based on their attributes or characteristics.


Because each megawatt hour has a unique identification number and can only be in one owner’s account at any time, this reduces ownership disputes and the potential for double counting.

Essentially, any person or entity interested in participating in the REC market can establish an account on the M-RETS and/or WREGIS systems to facilitate the participation in the REC market. 


According to the California RES, the price of RECs sold for compliance purposes ranged from $10 to $40 per megawatt hour. However, RECs in voluntary markets have sold for as low as $1.50 per megawatt-hour. Furthermore, according to the California RES, in 2009 there were more than 35 million active WREGIS certificates generated that are certified for use in California. The price of an REC will vary depending on when it was purchased, the type of resource underlying the REC, the jurisdiction, and whether it was used for compliance of voluntary purposes. 


The Proposed Federal RPS


On Sept. 21, Sen. Jeff Bingaman, D-N.M., and 23 other senators introduced the Renewable Electricity Promotion Act of 2010, S. 3813, which proposed to establish a combined renewable energy and energy efficiency standard nationwide. While the bill has lost momentum in 2011, it is nevertheless instructive in terms of what we could expect to see at the federal level if political support for such a measure resumes.


The bill defines renewable energy to include most generally accepted forms, as well as some emerging forms, including energy generated from solar, wind, geothermal, biomass, landfill gas, marine and hydrokinetic, coal-mined methane, and certain qualified hydropower and waste to energy.

The bill also leaves the door open for the secretary of energy to add additional sources of qualifying renewable sources based on innovative technology.The bill further gives at least some credit to other kinds of electricity by excluding that electricity from the base quantity to which the required renewable percentage is applied. This excluded power includes certain hydroelectric power, fossil fuel-generated power to the extent the greenhouse gas emissions from its generation are sequestered, and additional nuclear power placed in service in the future.


In terms of the renewable standards themselves, the bill requires minimum annual percentages as follows:


• 3 percent from 2012-’13.


• 6 percent from 2014-’16.


• 9 percent from 2017-’18.


• 12 percent from 2019-’20.


• 15 percent from 2021-’39.


Electric utilities selling more than 4 million megawatt hours of electricity can meet these compliance obligations through one or a combination of the following options:


• RECs.


• Energy efficiency credits (for up to 26.67 percent of the compliance obligation).


• Alternative compliance payments of 2.1 cents per kilowatt hour, adjusted for inflation

.
The alternative price payment would effectively put a price limit on RECs of $21 a credit.
All credits are tradable, but not all credits are created equally. The bill allows double credits for facilities on Indian land, and triple credits for both small renewable distributed generators less than 1 megawatt and facilities that generate energy from algae.


Importantly, the federal bill leaves all state programs in place, merely requiring the secretary to facilitate coordination between the federal and state programs, and to promulgate regulations that would effectively give utilities credit toward meeting federal compliance obligations to the extent the utilities are simultaneously meeting state compliance obligations.


The bill issues a number of additional requirements to the secretary, including that the secretary make interest-friendly loans available to electric utilities for purposes of carrying out approved, qualified projects for meeting compliance obligations. It requires the secretary to monitor the costs and benefits of the program and to submit recommendations to Congress for whether the compliance obligations should be increased or relaxed. And it requires the secretary to implement regulations establishing the program within one year of enactment.


More recently, talk at the federal level has shifted towards a clean energy portfolio standard (CEPS). In general, a CEPS would broaden the types of energy that could be used for compliance purposes to include nuclear power and clean coal—namely, coal-fired plants using carbon capture and sequestration. It would also allow for more state and regional control in deciding what types of energy will satisfy compliance obligations, which some view as more politically palatable given notable regional variability in the types of clean energy that are available. 


President Obama recently supported the adoption of a nationwide clean energy standard (CES) in his State of the Union address. He proposed a CES requiring that 80 percent of the nation’s electricity come from clean energy technologies by 2035. On March 21, Sens. Bingaman and Lisa Murkowski, R-Alaska, acting on behalf of the Senate Energy and Natural Resources Committee, issued a white paper to solicit ideas on whether and how a federal CES might be implemented. At the same time, Sens. Tom Udall, D-N.M., and Mark Udall, D-Colo., have reintroduced legislation proposing an RES standard of 25 percent by 2025, 10 percent higher than the Bingaman RES bill.


Conclusion


Given the increasing RESs at the state level and ongoing debate at the federal level, RECs will remain important to both utility companies and renewable energy generators. The ability to use certain RECs for compliance purposes and the market for RECs varies by jurisdiction. The parties involved in the REC market must be able to navigate differing state standards and to adjust to still-evolving state, regional and federal initiatives. Even if some form of national standard develops, it is not likely to supersede or eliminate many if any of the initiatives occurring at the lower levels, at least not in the short term. 


In addition, participation in the REC market involves many legal considerations, including the ownership of the RECs, assessment of compliance standards, contract negotiations for REC transactions, and the flexibility to account for changing conditions. For anyone participating in the REC market at any significant level, consultation with counsel knowledgeable with the RECs and the various RPS standards is encouraged.

Authors: Jonathan Dettmann
Partner, Faegre & Benson LLP
jdettmann@faegre.com
Andrew Ritten
Partner, Faegre & Benson LLP
aritten@faegre.com
Angela Snavely
Associate, Faegre & Benson LLP
asnavely@faegre.com

 

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