April 21, 2006 | General

Energy Recovery From Biosolids Treatment

BioCycle April 2006, Vol. 47, No. 4, p. 60
Wastewater treatment plant methane is an untapped source of green electricity with only two percent participation of plants using anaerobic digestion.
Wilson Rickerson

GREEN power refers broadly to renewable energy systems like wind, solar, small hydropower and biomass. The U.S. green power market has exploded during the past several years as concerns over air pollution, fuel price volatility, energy independence and global warming have driven a wave of green consumerism and new state renewable energy incentives. As a result, “green” energy suppliers can command a premium for their power on the open market and receive state support.
The challenge for wastewater treatment plants (WWTPs) is to find avenues for participating in the green power markets. It has been argued that waste heat capture from biosolids incineration should be considered “green power” because it uses renewable fuel to improve energy efficiency and reduce air emissions. While waste heat recovery may be arguably green, the established markets for green power in the U.S. primarily target electricity generating technologies. Within the biosolids industry, anaerobic digesters represent the largest potential source of electricity generation. According to the federal government, 3,500 of the nation’s 16,000 WWTPs already employ anaerobic digesters. Of these, only 2 percent use digester methane to produce electricity. WWTP methane, therefore, represents a large and relatively untapped potential source of green electricity. This article explores how WWTP digesters can participate in the green power markets, and reviews the experience of two wastewater facilities with green power transactions.
An article in the January 2005 issue of BioCycle, “State Incentives For Biomass Electricity,” described how state-level renewable portfolio standard (RPS) regulations are one of the primary drivers for renewable energy markets in the U.S. An RPS mandates that utilities procure a certain percentage of their electricity from renewable resources. As of January 2006, 22 states and the District of Columbia had enacted RPS laws, while 12 states were considering similar legislation (Figure 1). The Union of Concerned Scientists projects that the current RPS mandates will require the addition of 31,100 megawatts of new renewable capacity to the grid by 2017.
In order for anaerobic digesters to participate in RPS regimes, they must be considered an eligible resource under the state regulation. While some state laws explicitly include WWTP digesters as eligible resources, the treatment of biosolids under many state laws is ambiguous. As a result, some states remain uncertain as to whether WWTP methane can contribute to RPS targets, while other states have only recently granted biosolids eligibility after formal regulatory review. Table 1 lists the status of WWTP digesters in RPS, gathered from state law or through interviews with state officials. The table also lists whether on-site generation is eligible under the RPS. In some states, only electricity delivered into the electricity grid can be counted towards RPS compliance. This excludes WWTPs that consume the entire electrical output of their digesters from eligibility.
As can be seen in Table 1, the survey revealed that every state but Maine and Minnesota currently considers WWTP digester gas to be an eligible resource. Every state but Iowa, Minnesota, Montana and Vermont permits on-site generation to participate in the RPS.
While eligibility is a prerequisite for RPS market participation, the value of RPS markets to WWTPs depends on regulatory mechanics. In Illinois, for example, the renewable energy target is voluntary and no formal compliance procedure exists. It is therefore difficult for WWTPs to generate extra revenue through the Illinois RPS market. In the Northeast and Texas, on the other hand, utilities must meet a schedule of steadily increasing targets, and they are assessed a fee for any shortfalls. To demonstrate compliance and avoid paying this fee, utilities must acquire renewable energy credits (RECs). For each megawatt-hour (MWh) of electricity that a renewable energy facility produces, a REC is generated. A utility can acquire these RECs by owning renewable generation, purchasing RECs directly from renewable generators, or by buying and selling RECs on the open market.
RECs have emerged as a recognized commodity and they form the basis of formal green power markets nationwide. According to REC broker Evolution Markets, RPS credit prices range from under $1/MWh in Maine to over $50/MWh in Massachusetts. Wastewater facilities in several states have positioned themselves to sell RECs from their anaerobic digesters into RPS markets as a source of additional revenue.
Beyond the RPS, WWTPs also can contract with green power marketing firms to sell their RECs. Businesses, universities, government agencies, and private citizens, for example, purchase RECs voluntarily in order to claim either that a certain percentage of their electricity is derived from renewable resources or that they are reducing air emissions like carbon dioxide. A large portion of the voluntary REC market adheres to the Green-e standard, administered by the Center for Resource Solutions (CRS). Green-e is the leading green power certification program in the U.S. for voluntary green power products. According to CRS, methane from wastewater treatment plants is an eligible resource under the Green-e standard, and several green power marketers incorporate WWTP digester gas into their green power products.
The Deer Island Treatment Plant (DITP) serves 2.5 million people in the Boston region. Operated by the Massachusetts Water Resources Authority, it is the second largest wastewater treatment facility in the country. As part of its wastewater treatment process, Deer Island recovers methane from its 12 3-million gallon egg-shaped digesters and uses the gas to fuel boilers. High pressure steam from the boilers goes through an 18 megawatt (MW) steam turbine generator. The turbine produces low-pressure steam that is used in the plant heating loop, and generates electricity.
While WWTP digester gas is not explicitly mentioned as an eligible resource in Massachusetts’ original RPS legislation, DITP applied for, and was granted, RPS eligibility in 2002. In the October 2004 issue of BioCycle (“Wastewater Treatment Plant Builds Profit Center From Anaerobic Digestion”), it was reported that DITP sold its renewable energy credits for between $30 and $48 per REC. After the article’s publication, however, renewable energy supply constraints drove credit prices up to an average of $51.43 in 2005. As a result, DITP’s annual revenue from REC sales exceeded $1 million last year. Since it first began to participate in the RPS market in 2002, DITP has sold 74,000 megawatt-hours of RECs totaling $2.9 million.
DITP also applied for eligibility in Connecticut. While the Connecticut Department of Public Utilities Control (DPUC) acknowledged the eligibility of WWTP digester gas, the DPUC concluded that only in-state on-site generators could participate in the RPS. Because DITP consumed the entirety of its digester gas on-site out-of-state, it was judged ineligible.
Recent changes in RPS regulation now allow out-of-state on-site generators like DITP to sell credits in Connecticut. However, the Connecticut RPS market has been flooded and REC prices have crashed from over $30/MWh to $2/MWh. Therefore, although DITP could position itself to sell RECs in either Massachusetts or Connecticut, Connecticut’s REC market prices give it little incentive to do so.
The Essex Junction Wastewater Treatment Facility, which is far smaller than Deer Island, processes 1.9 million gallons of wastewater per day in the suburbs of Burlington, Vermont. Prior to 2003, the Essex Junction plant had flared 45 percent of its anaerobic digester methane and burned the rest to provide heat for the digestion process. In 2003, however, Essex Junction hired Northern Power Systems to install two 30 kilowatt Capstone microturbines on-site that convert the methane output of the plant into electricity. The microturbines generate approximately 400,000 kilowatt-hours of electricity, or 41 percent of the plant’s annual demand. They are configured to produce power at peak times when electricity is most expensive.
To finance the project, Essex Junction relied on a mix of state incentives and the voluntary green power market. Efficiency Vermont, the state energy-efficiency utility, provided an incentive of $40,000 to move the project forward. Essex Junction also signed a contract to sell RECs to NativeEnergy, a marketing firm that sells green power-based products to public and private sector customers. NativeEnergy blended RECs from Essex Junction with RECs from the Rosebud Indian Reservation wind energy project in South Dakota to create its CoolHomesm green power product.
Unlike many green power products, NativeEnergy markets CoolHome as a greenhouse gas reduction product. Rather than purchasing RECs as a way to be “green powered,” customers sign up to offset six tons of carbon dioxide (CO2) emissions each year. According to NativeEnergy, six tons is the average annual CO2 emissions of a Vermont residence. NativeEnergy purchased the 15-year REC output of the Essex Junction digester upfront. This arrangement lowered the payback of the digester to a period acceptable to Essex Junction, allowed the project to move forward, and gave CoolHome customers an opportunity to help build a new renewable generator.
The experience of the Deer Island Treatment Plant demonstrates both the advantages and disadvantages of the RPS markets. On the one hand, DITP has been able to earn a steadily rising stream of nonrate revenue from its participation in the Massachusetts RPS program. On the other hand, the crash of the Connecticut REC market highlights the vulnerability of RPS markets to policy change. Because of REC price uncertainty, it frequently is difficult to secure financing for projects based on the promise of REC sales in the future.
The case of Essex Junction is an example of how the voluntary green power market can be used to help finance energy recovery systems, even at relatively small WWTPs, if the contracts are structured correctly. Moreover, Essex Junction demonstrates how WWTPs can turn to the voluntary market if they are unable to advantageously participate in RPS markets.
The bottom line is that WWTPs in many states have a rapidly expanding menu of green power options available to them. For facilities that already have electricity-generating digesters, the green power markets provide a way to gain extra revenue streams and public recognition for their contribution to energy independence and the environment. For facilities that do not combust their digester gas for electricity, or facilities without digesters at all, the green power markets may provide an avenue for financing digester installations or upgrades.
Wilson Rickerson is a renewable energy policy analyst at the Center for Sustainable Energy at Bronx Community College in New York.

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