February 21, 2007 | General

Financing Wood-Fired Generating Facilities

BioCycle February 2007, Vol. 48, No. 2, p. 36
In some New England states, wood-fired biomass plants are tapping into Renewable Energy Credits – a component of states’ Renewable Portfolio Standards – for project financing.
Diane Greer

IN GREENVILLE, Maine, New Energy Capital recently completed a $12 million project to refurbish a 16 MW wood-fired electricity generating facility fueled by forestry debris and mill wastes. The upgrades -advanced combustion technology and emission controls – permitted the plant to qualify as a renewable generation unit under the Massachusetts Renewable Portfolio Standard (RPS). The RPS specifies a minimum percentage of electricity supplied by retail entities be produced from renewable energy.
By qualifying under the Massachusetts RPS, the Greenville plant earns one Renewable Energy Certificate (REC) for every megawatt of power generated. Retail electricity suppliers can purchase the RECs, either separately or in conjunction with the power, to comply with state RPS requirements.
In essence, RECs are a creation of the marketplace seeking to ascribe some value to renewable energy by separating the “environmental attributes” of renewable power from the underlying electricity. By unbundling the RECs from the physical commodity, renewable energy developers effectively earn two revenue streams, one for the sale of electricity and the other for the sale of the RECs. The additional cash flow generated by REC sales facilitates financing of renewable power projects.
“The additional revenue stream helps a facility become economically feasible where it might not be without the stream,” says Andrew Kolchins, Director of Renewable Energy Markets at Evolution Markets, LLC based in White Plains, New York. Adds Scott Brown, CEO of New Energy Capital in Hanover, New Hampshire, the Greenville plant “would not have been viable without RECs.”
Broadly speaking, REC markets are divided into two types, compliance and voluntary. Compliance markets are employed by renewable electricity generators to sell RECs to retail electricity suppliers who need them to comply with RPS mandates. Currently, 21 states have enacted RPS requirements and three others have set renewable portfolio goals (see sidebar). Most permit RECs to be used for compliance.
“The biggest thing to understand about the compliance markets is that they differ considerably from state to state,” says Kolchins. Each state mandates the percentage of electricity that must be produced from renewable sources, defines how producers qualify as renewable sources and where they can be located, and sets alternative compliance payments if suppliers do not meet the mandate. These factors determine how a market for RECs develops.
Mandates for the portion of electricity supplied by renewable sources are usually designed to start small and grow. For example, the California RPS, effective in 2003, requires retail sellers of electricity to increase renewable energy sources by at least two percent per year to reach a minimum of 20 percent by the end of 2010 and 33 percent by the end of 2020.
Resource eligibility rules define sources qualifying as renewable under the RPS. Maine, for example, adopted a very broad definition of what is considered renewable, according to Robert Cleaves of Cleaves and Company in Portland, Maine. The wide availability of RECs has held down prices. “There is way too much supply and the REC price is next to nothing,” says Cleaves.
In contrast, Massachusetts enacted very strict definitions of renewable sources. In the case of wood-fired biomass, only plants considered advanced combustion and low emissions qualify, according to Cleaves. Meanwhile, the availability of other renewable sources, such as wind and solar, are limited, leading to a tight market and high REC prices. RECs in Massachusetts trade around $54/MWh, compared to Maine prices below $.30/MWh, according to Kolchins.
Connecticut’s RPS program includes biomass gasification plants utilizing land clearing debris, tree stumps and other biomass cultivated and harvested in a sustainable manner. Recent rule changes prohibit the use of construction and demolition (C&D) debris. Plants must also meet low emission guidelines.
Geographic eligibility rules govern the importing of RECs from outside a state. Many states permit REC imports if accompanied by the delivery of electricity to the local power pool, according to Ed Holt with Ed Holt and Associates in Harpswell, Maine. For example, Massachusetts, Connecticut, Maine and Rhode Island allow renewable projects delivering power to the New England Power Pool (NEPOOL) to qualify for RECs under their respective RPSs.
Rules permitting regional REC trading increase market liquidity and provide flexibility to renewable energy developers. One example is Laidlaw Energy, whose project development was hampered by the recent hiatus in New York’s REC market, caused by the revamping of the state’s REC auction model. The company is converting a natural gas cogeneration facility in Ellicottsville, New York to wood wastes as the fuel source and planned on selling RECs generated by the facility in the New York market, according to Michael B. Bartoszek, Laidlaw’s CEO. “We looked at our options and decided to pursue certification in Massachusetts,” he says. The facility recently qualified under the Massachusetts RPS and is now positioned to sell RECs in both markets. “This gives us a larger marketplace for our RECs and more certainty with regard to the cash flow,” adds Bartoszek.
Other factors influencing compliance markets include rules covering the age or vintage of plants qualifying under the various RPS programs (essentially disqualifying older plants), the noncompliance penalty that effectively sets an upper bound on the REC price and the ability to bank or save RECs for use in future years.
Voluntary REC markets have formed to sell RECs to an increasing number of consumers, businesses and institutions who are under no mandates but wish to purchase renewable power. By purchasing voluntary RECs, either directly or as a part of a green power product, these consumers support the development of renewable power projects.
Like compliance markets, voluntary markets set rules determining qualifying sources. But unlike compliance markets, where buyers are indifferent to the type of renewable resource creating the RECs, voluntary market prices can vary greatly based on location and specific type of technology, according to Kolchins.
REC prices for biomass resources in voluntary markets are typically less than wind or solar. Kolchins believes REC prices for biomass power will rise as consumers of green energy products develop a better understanding of the technology. “There is a growing demand in the national voluntary market for Green-e certifiable biomass,” says Kolchins. “Long-term deals for 100,000 MWh are getting done.”
For developers of wood-fired biomass projects, prices on the voluntary market are still too low. “The voluntary markets are not priced sufficiently high to provide an incentive,” says Brown of New Energy Capital. Bill Carlson of Carlson Small Power Consultants, who works with renewable energy developers in the western United States, agrees. “On the voluntary markets the pricing is typically puny,” says Carlson. “You get quoted around $3/MWh. It really takes a mandatory market to drive the REC value, similar to what you see in Massachusetts.”
High prices for RECs in selected New England compliance markets are spurring wood-fired biomass development projects. “Right now New England, with two or three states [Massachusetts, Connecticut and Rhode Island] that are worth talking about, has the best and highest valued REC market in the country,” says Cleaves. “The number one reason virtually every facility in New England is now operating is because most of these plants qualify for RECs.”
Recent projects in New England include the refurbished 25.8 MW Worcester Energy plant in Deblois, Maine that reopened after receiving a vintage waiver from the Massachusetts RPS program. The plant, erected in 1988, was built with fluidized bed combustion technology that satisfied Massachusetts’ RPS advanced combustion requirements. Forestry debris, mill waste and an in-house fuel sources provide feedstock for the plant. “The viability of the economic model was based on a certain stream of REC revenues,” says Gregory Blair, President of National Public Energy, the company tasked with running the plant.
Also qualifying under the Massachusetts RPS is the Northern Wood Power Project in New Hampshire, which replaced an existing 50 MW coal-fired generation unit with a 50MW wood-fired boiler. Public Service of New Hampshire (PSNH) spent $75 million to upgrade the plant. “One of our key priorities was to make sure that this project qualified to receive REC approvals from Massachusetts,” says Bill Smagula, PSNH Director of Generation. “The REC revenue stream is sufficient to generally offset the capital costs to our customers.” The facility now purchases 400,000 tons of wood wastes instead of 130,000 tons of coal and meets the new requirements of the New Hampshire Clean Air Act.
Meanwhile the Laidlaw facility will generate 7 MW of power, selling 6 MW to the grid and using the remainder to power a colocated lumber business. Excess heat and steam from the generators will be used to kiln dry hardwood lumber. Without the cash flow from the RECs, the plant would be breakeven at best, according to Bartoszek: “RECs are really an imperative and necessary part of making these types of projects viable going forward.”
Beyond New England, REC prices are usually too low to play a critical role in project financing decisions. REC prices need to be closer to $10/MWh before they become a factor in financing decision, according to Carlson. In the meantime, “they really become your upside on the project,” he explains. In addition to RECs, the tax benefits provided by federal production and investment tax credits, along with a variety of state incentives, facilitate project finance of many wood-fired facilities.
Nascent REC markets are experiencing growing pains. Market uncertainty and price volatility are creating reluctance on the part of both REC purchasers and developers to enter into long-term contracts. This reluctance, in turn, presents challenges to developers wishing to incorporate RECs into project financing decisions.
Investors want to see long-term contracts for REC purchases before factoring the revenues from their sale into financing decisions. But REC purchasers have been unwilling to enter into long-term contracts at prices developers deemed reasonable to support project development. “The problem is no one knows where the REC market is going to be 10 years from now,” says Cleaves. “It is highly unlikely that anyone is going to give you a 10-year REC deal anywhere near attractive enough for you to want to do [the project].”
Until last year, REC markets in the West were either new, with sufficient supplies of renewable sources to meet the initial RPS requirements, or voluntary, according to Carlson. “So people had gotten use to $3/MWh REC markets.” But now both California and Nevada are starting to fall behind their RPS goals as the mandated percentage rises. “All of a sudden, SMUD [the Sacramento Municipal Utility District] is buying $10/MWh RECs,” says Carlson. “So the REC value is beginning to ratchet up pretty quickly as you would expect it to do over time.”
Regulatory uncertainty also plays a role. “REC revenue streams are always subject to change since it is a legislative or regulatory process,” says Smagula of Public Service of New Hampshire. Recent events in Connecticut illustrate how regulatory changes can cause volatility. In 2003, the Connecticut legislature increased state RPS requirements and tightened eligibility rules. As a result, REC prices rose from $1/MWh to $40 to $50/MWh.
One of the rule changes, however, permitted biomass facilities constructed prior to July 1, 1998 to qualify as renewable resources if they upgraded their facilities to conform to strict emission control requirements. “A number of biomass facilities retooled their boilers to qualify for the definition and the market crashed,” says Cleaves. The crash again prompted rule changes. This time the legislature banned the use of C&D waste and required the use of sustainable biomass. In response, prices rose and are now in the $20 to $40/MWh range.
New Hampshire also has placed a moratorium on the combustion of C&D wastes to fuel energy projects. The changes have resulted in the cancellation of a wood-fired facility under development in Barnstead, New Hampshire. Forestry debris sells for $20 to $30/ton or higher versus C&D wood wastes at $10/ton, according to Cleaves. “It is purely a function of economics. I have not given up, but without a high REC price, the Barnstead project does not work.”
In addition to long-term REC contracts, investors like to see long-term power purchase agreements (PPA). Renewable power is still not price competitive with fossil fuel sources, making renewable development projects risky propositions. Long-term power contracts allay some of the risks. In the past, the Public Utility Regulatory Policies Act of 1978 (known as PURPA) encouraged renewable energy development by requiring utilities to purchase power from independent power plants (known as “qualified facilities”) under long-term contracts at the utility’s avoided costs, i.e., the cost the utility would have paid to generate the power.
But in today’s deregulated power markets, it is neither typical nor even realistic to negotiate long-term contracts, according to Bartoszek. “If you go out and ask for and get a [long-term] contract, you are going to be heavily penalized on the price. Or you are going to accept a short-term contract and ask your investors to take the risk.” He has been able to fund Laidlaw’s New York biomass project with internal capital and the capital from the company’s partners, who he describes as “experienced power project developers willing to accept certain risks.” The environment is much more challenging for developers who seek bank financing to fund significant portions of their projects, he adds.
Another stumbling block in developing biomass projects has been procuring long-term biomass fuel contracts, according to Kolchins. “Fuel supply is a big project financing issue,” agrees Bartoszek. “When you talk to investors, particularly long-term lenders, they want to know where that fuel is coming from and they want to get certainty.” Adds Cleaves: “Frankly, long-term contracts for fuel are virtually impossible in the biomass world unless you have a captured source for fuel or you grow your own.” To get around the problem, developers conduct regional fuel supply studies and look at historic pricing trends to provide investors with a level of comfort on fuel supplies.
A few states are addressing REC pricing uncertainty and long-term contract issues. The Massachusetts Technology Collaborative (MTC) has established a program called Massachusetts Green Power Purchasing (MGPP). The program aids developers unable to attain long-term REC contracts from credit worthy entities, according to Nils Bolgen, MTC Program Manager.
The MGPP provides a level of certainty for REC revenue streams by offering either long-term REC purchasing agreements or put/collar options for RECs, which place a lower limit on REC prices while limiting MTC’s exposure, according to Bolgen. Contract terms may extend up to 10 years and do not need to start during the first year of the project’s operation. The program is funded through a system benefit charge (a surcharge on retail customers’ electricity bills). Developers apply to the program via an RFP process.
PSNH was the first biomass developer to receive a MGPP REC contract award. “They [MTC] have the opportunity to purchase 10 percent of our REC output for the next four years,” says Smagula. While obtaining financing was not an issue for the utility, PSNH was concerned that the REC concept was new and not well understood in New Hampshire. “PSNH needed a market signal that they could take to their regulators to get approval to do the project,” says Bolgen. Notes Smagula: “The award provided an illustration to our regulators and other interested parties that there was in fact a market for RECs.”
Greenville Steam Company received a MGPP REC contract under the second round of awards. MTC will enter into a contract for approximately 85 percent of the projects RECs earned during years four to seven. “That was enough to get their financing for the retrofit,” says Bolgen.
Connecticut has initiated an incentive program as well. Project 100, a program offered by the Connecticut Clean Energy Fund (CCEF), also is funded by a system benefits charge. The state’s two electric utilities are required to enter into 10-year contracts for a minimum of 100 MW of renewable power by the end of 2008, according to Dale Hedman, CCEF Director of Project Development. The contracts essentially bundle the purchase of the power and the RECs under one long-term contract.
Decker Energy has submitted an RFP to Project 100 for its 40 MW wood-fired electricity generation facility under development in Plainfield, Connecticut, according to Marvin Burchfield, Vice President of Decker Energy. The plant is being designed to qualify as a renewable source under Connecticut’s RPS. “Utilities are obligated to provide you with a significant term contract which is financeable,” says Burchfield. “Without that lengthy term, you can’t put the financing together.”
Many believe more efforts are needed to address long-term financing issues. Bartoszek suggests that either states or the Federal government should consider legislation similar to the PURPA rules to provide incentives to small renewable power projects.
Requiring long-term contracts as part of RPS compliance is a topic currently under debate in New Hampshire, which is considering a RPS bill, according to Holt. “There is a lot of discussion about how you get long-term contracts in place as part of these RPS programs,” says Holt. “They would like to have most of the output, or at least a huge chunk of it, contracted for a period of time that allows them to secure financing.”
While there is a general recognition that long-term contracts are desirable, there is also a concern about creating stranded assets, as was the case with many of the PURPA contracts, adds Holt. (Stranded assets are investments where changes in the market make it impossible for a company to earn an economic return on a previously sunk investment.) “From a political standpoint, this tends to be the stronger argument,” he says. “Long-term contracts are a solution, but politically it is not an easy solution.”
Many still feel the solution to spurring renewable energy development projects lies in a strong REC market. “If states really want to see the renewable energy markets develop then public policy needs to focus around a robust REC market,” says Brown. “It is the only way to provide a market-based incentive.”
Diane Greer is a free-lance writer and researcher based in New York, specializing in sustainable business, green building and alternative energy. She can be reached at
IREC, the Interstate Renewable Energy Council, tracks Renewable Portfolio Standards (RPS) activity around the country. State RPS programs specify a minimum percentage of electricity supplied by retail entities be produced from renewable energy. IREC, housed at the North Carolina Solar Center (at NC State University) provides ready access to the latest RPS information via its website,
According to a map on the IREC site, 21 states have RPS programs. Minimum percentages (by specific dates) vary from four percent in Massachusetts (by 2009, with a one percent increase/year) to a high of 24 percent in New York (by 2013). Instead of a minimum percentage, Texas and Iowa set specific megawatt goals – 6880 MW in Texas by 2015 and 105 MW in Iowa. The other states with RPS programs include Arizona, California, Colorado, Connecticut, Delaware, the District of Columbia, Hawaii, Maine, Maryland, Montana, Nevada, New Jersey, New Mexico, Pennsylvania, Rhode Island, Washington and Wisconsin.

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