A First for Thermal
For the past several years, advocates of renewable heat in the Northeast have worked tirelessly to make the case to legislators that technology parity is essential in crafting sound energy policy. Like states outside of the region, thermal applications have taken a backseat to electricity as the core focus of renewable energy programs, and until now there has been a lack of education and understanding on the benefits renewable heat can offer.
New Hampshire, however, is beginning to understand the benefits of renewable heat and has pulled ahead of other states that are working to reach, modify, revamp or strengthen their renewable portfolio standards (RPS). This summer, it became the first state to grant full credit to renewable thermal under its RPS, a first step toward equality with electricity. The establishment of renewable heat as an application deserving of a full credit didn’t happen overnight, over the course of several months or even a few years time. The work put towards educating decision makers in New Hampshire will not only benefit the state, it will provide a blueprint for other states and renewable heat advocates.
The original goal to bring renewable heat on par with electricity was strategically set into motion when New Hampshire’s RPS was crafted and passed in 2007.
At that time, Charlie Niebling and his company, New England Wood Pellet, argued vigorously that a renewable-based program that incentivized biomass-based electricity would only create unfair market advantages and distortions, especially for biomass-based feedstock. “We weren’t successful [in winning the argument]at the time,” he says, “but we were able to set into motion a number of commitments from the legislature and regulators that would open the door to the whole question.”
Niebling, who is general manager of NEWP and chairman of the four-year-old Biomass Thermal Energy Council, explains that New Hampshire’s RPS, as well as many other states’ programs, have a provision that requires a utility to pay a price if they do not have enough renewable energy credits (RECs) to meet obligations. In New Hampshire they are called Alternative Compliance Payments, and these monies go into a fund administered by the New Hampshire Public Utilities Commission to support renewable energy incentives. “One of the things we achieved back in 2007 was a commitment to use that money for both electrical efficiency and renewable thermal,” he says. “These funds created by the ACPs were fuel and technology neutral, so that was a positive step.”
Over the past several years, many renewable thermal projects across the state were funded with ACP dollars, and that was a way to familiarize the PUC with the technology. “Another thing we did in 2007 was add a component to the law which required the PUC to review the RPS in 2011 to determine how well it had functioned and how well it had met its objectives,” Niebling says.
Part of that evaluation was answering the question of whether a thermal component should be added to the RPS. When the report was finished, it indicated that adding thermal was justified, but the PUC was not sure how to implement the application. “They are utility regulators and not policymakers, and they’re careful about not crossing that line, so they only offered an opinion on the technical potential to include thermal in the RPS,” Neibling says. Unfortunately, the PUC stopped short of recommending the legislature to move forward and do it.
During that same time period, the state energy office was working on what would turn out to be the final piece of the puzzle—conducting a study focused solely on renewable thermal in the state. It made many policy recommendations, including equal treatment of renewable heat with electric energy in the RPS. “It concluded that technology neutrality is something we should strive toward, and it makes sense in New Hampshire particularly because we use a lot of heat and are very dependent on heating oil; we’re number two to Maine for imports,” Niebling says. “So for all of those reasons, they decided to look at the issue very seriously, and that set the stage for legislation this year.”
Figuring it Out
Because the groups pushing for thermal incentives knew the RPS review would be released in 2011 and the legislature would then take a run at reforming the RPS, last year they worked, successfully, to introduce a bill that tackled the issue of awarding RECs to thermal output from biomass combined heat and power (CHP). “It wasn’t the full, comprehensive provision in the law now; it was just a small, bite-sized and incremental piece that made a lot of sense to a lot of people—if you are going to give RECs for electrical output, why wouldn’t you for the thermal output?,” Niebling says. “Nobody could figure out how or why to oppose that. If you don’t incentivize the heat but you do the electric, there is no reason for a developer to consider using CHP; there’s no direct economic advantage, especially when you consider the much higher capital cost.”
The point of that legislation wasn’t necessarily linked to passage, but rather to introduce the idea to the legislature before the more comprehensive plan would debut in 2012. For Niebling, it was “sort of a tactical measure.”
During the fall of 2011, he and biomass thermal stakeholders met with the governor and key members of the House and Senate energy committees to begin their pitch on adding thermal to the RPS. They succeeded. Jeff Bradley, a former member of Congress, the state senate majority leader and a member of the state energy committee, sponsored the bill. But, before Bradley would push the bill, he required bill proponents to create a way to lower ratepayer costs.
By simply adding thermal to an electric RPS, ratepayers would be forced to foot the bill, Niebling admits, so it had to be approached in a way that would lower overall utility compliance costs. “When the RPS enacted in 2007, it established a certain utility mandate that they had to meet—25 percent of total electric load by 2025—and it ratchets up over time. There are four different classes of qualifying technologies, each having a different sub-mandate associated with it and different ceiling prices on RECs.”
Class I of New Hampshire’s RPS is new renewable energy development; Class II is solar photovoltaic; Class III is existing biomass and wind projects; Class IV is existing hydro. “What we did was take a piece of the Class I mandate away from electricity and gave it to thermal, and then we gave a lower REC value to thermal projects than electric projects,” Niebling explains.
That might not seem fair at first, but he points out that thermal applications are generally a more efficient way to utilize energy—one can achieve the same objective at a lower incentive cost per unit of energy produced—and that’s especially true for biomass. “[With biomass] you do so with roughly 80 to 90 percent efficiency with the right technology, and with conventional steam generation you lose 25 to 30 percent of that. It’s just the nature of steam generation; there is a lot of waste heat generated by the process.”
It was expected that the strategy may not be acceptable to other Class I renewable sectors such as the region’s bustling wind industry, as the effect is lower-valued RECs with a supply that stays the same, but Niebling says there wasn’t any opposition. “I think that’s because wind RECs in New Hampshire are being sold mostly in Massachusetts where the values are much higher,” he says. “[With that modification] whether you are a ratepayer ultimately financing those RECs, or you’re a utility paying an ACP because there aren’t enough RECs in the market, it will cost less compared to the previous RPS.”
That was the key breakthrough in terms of structure of the thermal provision, and it passed the Senate 23-0, the House 79-52. “It came down to people understanding heat is a big issue in New Hampshire, our historical dependence on oil and propane and their high cost, as well as our limited natural gas access. They realized they needed to do something.”
Capitalizing on Heat
As the bill stands, there is no limit on the size of a project that can qualify for RECs generation, but it does require metering, meaning a qualified project will have to install a metering technology to prove and verify its heat output. Niebling says it’s a standard technology used in all kinds of applications, but the cost likely means that larger projects will be inclined to take advantage of the incentive.
Using the metering technology also means there will be an administrative burden associated with the process of submitting information to the PUC every quarter. Additionally, a project will likely need to work through a broker or intermediary to sell RECs to utilities. “That’s the nature of REC markets; it’s very complex and there is a lot of administrative burden,” Niebling says. “Utilities are used to working with bigger projects, not homeowners with pellet boilers, but there is language in the bill that gives the PUC the ability to establish some creative approaches to aggregating smaller projects, potentially without metering requirements, but that will all get flushed out when the rules are written.”
A hospital with a 12-month thermal load—heat in the winter and domestic hot water year-round—will be a prime candidate for benefitting from thermal RECs, as well as municipal office buildings, food processing companies, apartment complexes or shopping malls. “If you’re in New Hampshire and you don’t have access to natural gas, you are heating with oil or propane and paying close to four dollars per gallon for oil, and three dollars per gallon for propane,” Niebling says. “For these kinds of businesses, institutions and complexes getting killed by their heating bills, this could be a godsend.”
Qualifiers will be able to sell RECs to utilities obligated to purchase them, at a negotiated price, and that’s a guaranteed revenue stream for the life of the project, or as long as the RPS is in place. Niebling points out that that could dramatically reduce operating costs, or can be used to help attract capital. “What would have been a seven- to 10-year simple payback on a modern pellet or chip boiler with bulk storage could now become two- to four-year payback because of that steady stream of revenue that comes from the sale of RECs. The challenge of all renewables is high capital costs, but once in place you save money; pellets have a 50 percent discount to heating oil.”
Outside of new project development, the legislation might affect the pellet supply and equipment market in the region. Niebling believes, that in fact, it will, but not right away. The new rules go into effect in January, but he says it will be a couple of years before projects—particularly large ones—get up and running, due to long sales cycles and the time it takes for projects to materialize. “But absolutely in time, you’ll see a balanced shift away from electrical generation and more toward thermal, because the policy platform is equitable for both. Not just toward pellets, but solar and geothermal as well.”
Setting an Example
The example set by New Hampshire has already rippled through the region. New Hampshire’s neighbor Massachusetts, which just shut the door on stand-alone biomass electric applications, is one state that is reevaluating the promise of renewable thermal incentives. Dwayne Breger, director of renewable and alternative energy development at the Massachusetts Department of Energy Resources says the state is seriously considering the best available means to support renewable thermal energy, including biomass and pellet heating. The state’s dependency on heating oil is not much different than that of New Hampshire, and Breger notes that the DOER, along with the Massachusetts Clean Energy Center, recently commissioned the study “Massachusetts Renewable Heating and Cooling: Opportunities and Impacts Study,” to further investigate the possibilities of incentivizing renewable heat. “DOER has also allocated $6 million of RPS ACP funds to launch a Renewable Thermal Pilot Program, which will be managed by our Massachusetts Clean Energy Center,” he says. “This program will specifically support residential- and commercial-scale pellet heating systems, along with small district energy applications.”
As required of the state’s 2012 energy bill, the DOER will study whether alternative energy that generates useful thermal energy should be added to the eligible technologies for the state’s Alternative Energy Portfolio Standard, which Breger explains operates just like the RPS but is for alternative energy and is currently predominately supplied by CHP. “This study will include biomass thermal along with other technologies, and is due to our legislature by Jan. 1,” he says.
Besides New Hampshire and Massachusetts, there are several other states eyeing thermal policy, such as Vermont, Maine, Maryland, Alaska and Oregon, through RPS revisions or other mechanisms. “In general, thermal is getting more attention around the country, and I think states that have focused their policy on electricity are realizing that they’ve placed artificial barriers on the marketplaces,” Niebling says.
While he considers New Hampshire’s RPS thermal component to be a modest provision—it will end up consisting of a maximum of 2.6 percent of the amount of megawatt hours that can be incentivized by 2025— Niebling deems it a very good start to parity with renewable electricity. “When you put forth an unorthodox idea, you have to accept small, incremental gains, and then hopefully show people that it works well and it’s achieving worthy goals,” he adds. “Then, you go back and ask for more.”
Author: Anna Simet
Contributions Editor, Pellet Mill Magazine