July 21, 2009 | General

Feed-In Tariffs Strengthen Markets For Biogas Power

BioCycle July 2009, Vol. 50, No. 7, p. 53
Ontario and Vermont adopt policies that provide long-term contracts with guaranteed fixed-prices to renewable energy producers.
Diane Greer

IN MAY, Ontario and Vermont passed landmark legislation to jump-start renewable energy development. Key provisions of Ontario’s Green Energy and Green Economy Act (GEA) and the Vermont Energy Act of 2009 call for the development of Feed-in Tariffs (FITs), which significantly change how electric utilities procure and price power from renewable sources.
FITs, also known as Advanced Renewable Tariffs, are not a new concept. European countries, most notably Germany and Spain, are successfully employing the policies to spur renewable energy projects. (See March 2008, “Renewable Gas and California’s New Feed-in Tariffs.”) Effective European FIT policies provide long-term contracts with guaranteed fixed-prices to renewable energy producers supplying power to the grid. Prices paid under the programs differ based on the type of renewable technology, the size of the project and its location. Rates are calculated to provide a reasonable rate of return on investment given capital, operating and maintenance costs over the life of the investment.
Several studies reviewing FIT implementations in Europe are finding that properly implemented FITs may be a less expensive means of developing renewable sources than renewable portfolio policies (RPS) that require utilities to purchase a specified amount of power from renewable sources. In the U.S., Gainesville, Florida, California and several electric utilities have implemented policies that borrow design elements from European FITs. Numerous states have or are currently considering FIT legislation (see sidebar.)
But the Ontario and Vermont policies represent the first time that full European style FITs will be implemented in North America, explains Paul Gipe, an advisor to the Ontario Sustainable Energy Association and wind power expert. “It’s revolutionary.”
The GEA requires the Ontario Power Authority (OPA) to develop a procurement program that provides for standard rules and fixed-price contracts for solar, wind, hydropower, biomass and biogas projects. Pricing for each renewable source is further subdivided by project size and technology. Higher prices are paid for smaller projects, which have higher initial capital and ongoing operation and maintenance costs. The pricing policy serves to spur smaller projects with regional economic benefits such as job creation.
FIT rates for 20-year contracts proposed by the OPA range from $0.16 CAD/kWh (Canadian dollars) for biogas projects less than 500 kW to $0.104 CAD/kWh for projects over 10 MW. Solar projects will receive $0.443-0.802 CAD/kWh depending on the project size and technology. OPA’s full FIT pricing schedule is shown in Table 1.
Vermont’s program, which Gipe calls a “pilot” due to a low program cap of 50 MW, has all “the essential elements” of the successful European FITs. “It is a serious commitment for a state the size of Vermont,” he says. Vermont tariffs are based on the cost of generation plus a profit, as defined by a reasonable rate of return, and are differentiated by type and size of the resource. Contract terms are for 20 years. Under both the Vermont and the Ontario program, rates will be reset based on regular program reviews.
Initial program rates in Vermont are $0.12/kWh for landfill and biogas projects and $0.30/kWh for solar. The Vermont Public Service Board will start regulatory examination of the rates in September and set new rates based on costs plus profit no later than January 2010.

Obtaining project financing is one of the biggest challenges facing renewable energy projects. FITs facilitate project financing by providing a predictable revenue stream at levels offering reasonable rates of return to investors. “FITs provide a guarantee of payment that project developers and their investors can count on since it is tied back to the ratepayer,” explains Karlynn Cory, senior energy and finance analyst with the National Renewable Energy Laboratory (NREL). “It provides a project developer and their investors with the certainty of having a revenue stream for any project meeting eligibility requirements.”
Pricing electrical generation at levels required to raise capital is hardly a new concept, Gipe says. “This is the way electricity was priced for generations. Prior to the deregulation craze in the 1990s, we had regulatory authorities in every state and province who would price electricity based on the cost of generation plus a reasonable profit.”
Toronto-based StormFisher Biogas sees Ontario’s FIT as vital in securing financing for its renewable energy projects currently under development in the province. This summer the company will break ground on a $15 million anaerobic digestion plant in London, Ontario. The system will codigest 140,000 tons/year manure and food processing wastes to produce 210,000 MMbtu of biogas to generate 2.85 MW of power.
Investors view long term fixed price contracts as an essential element of project financing, explains Ryan Little, StormFisher’s Vice President of Business Development. “They see it as the starting point. If you do not have that you have bigger problems.”
Guaranteed fixed-price contracts also remove a large piece of the risks inherent in any privately owned and operated (merchant plant) biogas project, adds Little. “You are not going to get 100 percent of your feedstock under a 20-year contract.” Nor is the project likely to obtain long term contracts to sell the nutrient by-products from the digester. “Having one piece [of the revenue stream] that is locked down removes merchant risk from a big piece of the pie.”

Grid capacity and access are other hurdles faced by renewable developers. GEA mandates that electricity transmission and distribution systems connect renewable generation facilities to the grid as long as the projects meet the technical, economic and regulatory criteria. System operators are also required to plan and invest in system upgrades and expansion to accommodate renewable generators.
“A guarantee of interconnection to the grid is not typically provided in the U.S. right now,” Cory says. “It is something that has to be negotiated on a project by project basis, which can be challenging for smaller projects.”
Little has run into grid limitations in Listowel, Ontario, where StormFisher is developing a second anaerobic digestion facility. “The agricultural heartland lines up pretty closely with the major grid constraints,” he explains. But expanding grid capacity will not happen overnight. “Adding new transmission capacity can take anywhere from 5 to 10 years from start to finish,” Cory notes.
In the interim, project developers are looking for innovative solutions. “In our Listowel facility we are aiming to clean up the gas to pipeline grade natural gas and then wheel it to another location where the grid is not constrained to create electricity,” Little says. “It is more expensive because of the gas clean up and the wheeling but some government groups have expressed interest in the approach as a pilot project to solve existing distribution issues.”

California created a state-wide feed-in tariff in 2006, targeted at water and wastewater plants. The program was expanded to a wider range of renewable sources in 2007. Under the policy, sellers of renewable power receive fixed rate contracts ranging from 10 to 25 years based on the utilities avoided costs as defined by the current Market Price Referent (MPR). The MPR price is based on the average cost of producing electricity for a combined-cycle natural gas fired generation facility.
To date, less than 10 MW of generation capacity has been added to the grid, with the majority of contracts for hydropower and landfill gas. “It is an ineffective program,” Gipe says.
Gegg Morris, director of the Oakland-based Green Power Institute, refers to the program as an “underwhelming success, with virtually no response from project developers.” By keeping the tariff rates at the MPR, they are trying to keep the program cost free, Morris explains. “It really comes down to the simple question of are we willing to pay for renewables and accept the fact that they are not the cheapest options on the grid but they provide important benefits.”
The California Public Utility Commission (CPUC) is proposing changes to the program. CPUC staff recommendations call for expanding the program to projects between 1.5 MW and 10 MW. The current program applies to projects up to 1.5MW. Price would remain the same, pegged to the MPR.
Renewable power generators would also be required to sell all the power generated to the grid, as opposed to just excess power. “It makes sense if you are a utility company and you want all the RECs [renewable energy certificates],” Morris says. But it does not make sense for projects, like farm-based anaerobic digestion systems, that would be better off economically to use some of the power onsite to offset retail rates.
The California Energy Commission (CEC) is also recommending changes to the program, which include the development of cost-based feed-in tariffs differentiated by technology for generators of 20 MW and below, explains Wilson Rickerson, executive vice president at Meister Consultants Group in Boston. The CPUC and CEC proceedings are moving forward on parallel tracks. “It remains uncertain as to how they will be reconciled,” he says.

In the U.S., California’s policy of pegging renewable pricing to avoided costs is fairly standard. Current regulations seek to foster a competitive environment to produce electricity at the least cost for ratepayers. Purchasing electricity at rates above avoided costs would produce higher electricity rates.
Many states seek to encourage renewable development within the competitive framework created by renewable portfolio standards (RPS) that specify a minimum percentage of electricity supplied from retail entities be produced from renewable energy. To comply with the policy, retail entities can either build renewable generation capacity themselves or purchase power from renewable energy developers.
“Typically, utilities are using competitive bidding processes to meet their RPS standards,” Cory says. “Utilities issue a request for proposals and select the projects that offer the most promising package of siting, operational expertise and cost.”
Europe’s experience with FITs is starting to show that properly designed FITs may be more cost-effective than RPS’s that employ competitive solicitations, Cory explains. Although these results may seem counter-intuitive, research studies and analysis are starting to provide some explanations.
Two studies, one by Dexia, a large European bank, and the other by the International Energy Agency entitled, “Policy Instrument Design to Reduce Financing Costs in Renewable Energy Technology Projects,” found one of the most important elements of FIT schemes is the removal of market risks for the project over fixed periods. “The longer the period of guaranteed prices, the lower the cost of capital.”
Several European studies found the average purchase prices per kWh for onshore wind in Germany and Spain, which operate under FITs, to be less expensive than in the United Kingdom and Italy, which operate under RPS regimes with tradable energy certificates.
John Farrell, research associate at the Institute for Local Self Reliance’s Minnesota office, found countries with FITs, like Germany, Denmark and Spain, may have lower electricity prices due to the “merit order effect.” “Utilities must buy and feed-in renewable power to the grid first,” he explains.
This “merit order effect” replaces expensive fossil fuel-fired “peaking plants,” which generally run only when demand is high, with renewable sources. In many cases renewable electricity under a FIT is less expensive than electricity generated by the peaking plants, which lowers overall electricity costs.
“In Germany, the merit order savings from renewables exceeds the premium price paid under the feed-in tariff,” Farrell explains. It is estimated that Denmark and Spain recoup over 80 percent of the higher tariff costs. He also cites the relative volatility of REC pricing under RPS schemes. In the case of wind power, for example, uncertainty associated with REC pricing and revenues increases financing costs, which in turn increases the cost of wind power for ratepayers, Farrell explains.
European experience is also showing that FITs result in more installed renewable capacity. Wind power deployment in European countries with wind FITs is over seven times higher than countries with alternative policy support. The total number of local jobs created is also substantially higher.
Evidence also suggests that competitive bidding processes under RPS schemes may contribute to lower installed capacity. “There have been assertions that with a competitive bidding process, sometimes projects try to win at all costs,” Cory explains. Developers seek to win bidding competitions by pricing projects at unrealistic levels compared to actual costs. “This creates a queue of what could be considered paper projects that tie up the queue for renewable developments.”
However Cory is quick to point out that FITs can work effectively with RPS mandates. FITs can be used as an alternative procurement mechanism, in place of a competitive bidding process, to supply renewable power to meet RPS goals, she explains.
Diane Greer is a Contributing Editor to BioCycle.

Sidebar, page 56

BEYOND Vermont and California, feed-in tariff legislation and regulations are making inroads in several states and municipalities. For example, Gainesville, Florida and Washington State offer solar feed-in tariff programs. Gainesville is providing 20-year contracts at $0.32/kWh with program caps of 4 MW in 2009 and 2010. In February 2009, the Gainesville Regional Utilities announced it had already received sufficient applications to fulfill the 2009 cap.
Washington’s solar feed-in tariffs are less generous, paying only $0.15/kWh for 10-year contracts. Payments increase to $0.54/kWh if the panels are manufactured in state. The Washington State legislature is considering a full system of feed-in tariffs covering solar, wind, wave, tidal, biomass, biogas, geothermal and hydropower projects.
In Wisconsin, the Public Service Commission approved solar feed-in tariffs ranging from $0.30/kWh to $0.061/kWh, based on the utility. The Commission also opened an investigation into a broader system of Advanced Renewable Tariffs in January 2009. Meanwhile, several legislators have expressed in interest in sponsoring legislation, but are waiting for the summary and recommendations from the commission, says Larry Krom, program manager for biogas at Wisconsin Focus on Energy. “I think our next step is to find funding to do a better rate impact study.”
Feed-in tariff legislation in Minnesota is “dead for this year, but was held over by the committee chair for consideration next year,” says John Farrell, research associate at the Institute for Local Self Reliance in St. Paul. The current version of the bill is more of a pilot project for community-owned energy projects that would apply to about 20 percent of the state’s RPS standards.
In Hawaii, the Public Utilities Commission held hearings to consider feed-in tariffs in April 2009. Feed-in tariff legislation is also under consideration in a number of state legislatures including Maine, Indiana and Michigan.

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