Across Europe, sustainable energy policies have been driving massive demand for a new energy commodity.&nbsp; Europe has found this new commodity in the manufacture and production of wood pellets. Wood pellets are created from those portions of trees that have been traditionally discarded as waste. In the manufacturing process, chips, bark, branches, and stems are compacted into small pellets, anywhere from one-fourth to one-third inch in diameter and one to one and a half inches in length. Generally, these pellets will then be burned as fuel for massive municipal boilers across Europe and the United Kingdom thereby replacing coal and similar fossil fuels as a primary means of electricity. Over 75 percent&nbsp; of wood pellet production capacity is located in the southeastern U.S. with Georgia, Florida, Alabama and Virginia producing the vast majority of American pellets. Approximately 98 percent of wood pellet exports ship from southeastern U.S. ports. In 2014, the U.S. exported 73 percent of its wood pellets to the U.K., according to U.S. EIA data, which indicates that, after the U.K., the three largest importers of American wood pellets in 2013 were Belgium (12 percent) and the Netherlands (7 percent). Given that the U.S. is exporting a vast majority of wood pellets manufactured in the country, concerns arise as to whether the production and manufacturing process meets the statutory or regulatory requirements of those foreign markets. Concerns for Exporting to EU Wood pellets are a popular form of sustainable energy within the European Union because they are regarded as having a smaller carbon footprint than traditional fossil fuels and coal. With the introduction of the EU&rsquo;s Renewable Energy Directive in 2009, demand for wood pellets has increased exponentially. With RED, the EU created 20/20/20 targets for the year 2020 which has objectives to: reduce greenhouse gas emissions by 20 percent compared to emission levels in the year 1990, increase renewable energy use to 20 percent, and improve energy efficiency by 20 percent. Each EU country will have its own individualized target.&nbsp; While many countries have their own certification schemes, the EU has been developing a multinational certification standard for wood pellets known as ENplus. The ENplus system creates three categories of pellets: EN-B pellets for industrial buyers and ENplus-A1 and ENplus-A2 for residential buyers. A break-down of important requirements for each type of pellet can be seen in Table 1. The certification process involves close inspection of all elements of the wood pellets&rsquo; production chain. According to the European Pellet Council Handbook for the Certification of Wood Pellets for Heating Purposes, for the certification of wood pellets, EN-B pellets can only come from forest, plantation, and other virgin wood and cannot be chemically treated. The relevant inspectors will also analyze the production plant and that plant&rsquo;s internal quality testing methods. In addition to production inspections, there is a certification scheme for pellet traders that confirms that all entities between the supplier and the consumer blends and stores wood pellets in accordance with disclosed standards. The handbook demonstrates how carefully each step of the production process is scrutinized before wood pellets obtain ENplus certification. In addition to developing ENplus in order to regulate the quality of wood pellets, the EU and major European utility companies are developing certification schemes to ensure the sustainability of wood pellets. In 2013, the EU promulgated the EU Timber Regulation to prohibit illegal timber from entering the EU markets. That same year, many of the major European utility companies formed the Sustainable Biomass Partnership to harmonize national sustainability standards and develop one universal standard. In furtherance of that goal, SBP has released six standards, each governing a different element of the supply chain. Standard 1 harmonizes various EU forestry and timber production regulations for producers of wood pellets, those that oversee the production of woody feedstock into wood pellets. Standard 2 similarly provides producers with additional requirements for ensuring the sustainability of feedstock. Standard 3 offers guidance to certification bodies, third parties that investigate wood pellets and verify their sustainability, and provides a consistent certification procedure. Standard 4 explains that chain-of-custody requirements so that entities throughout the supply chain, including traders and processors, can ensure the sustainability of wood pellets as they move down the supply chain. Standard 5 details the requirements for collecting the data that accompanies the sustainable wood pellets as they move through the supply chain. Standard 6 provides the generator with the requirements for calculating energy and carbon balances. UK Exporting Concerns The largest concern for American wood pellet producers exporting to the U.K. is the U.K.&rsquo;s certification requirements. Regulations require business receiving government incentives under the Renewables Obligation, Contract for Difference, or Renewable Heat Incentive scheme (which includes consumers of American exports), to obtain at least 70 percent of their wood pellets from suppliers that comply with the UK. definition of &ldquo;legal and sustainable.&rdquo;&nbsp; Suppliers can demonstrate legal and sustainable status with two types of evidence: category A certification or category B bespoke certification. Whereas category A evidence demonstrates that wood pellets have been certified as complying with relevant at every point of the production chain by an approved third party, the category B checklist shows what claims or materials suppliers must produce to demonstrate that there is a low risk that their wood pellets do not comply with the relevant laws. With category B bespoke evidence, the supplier verifies the sustainability of its wood pellets by following The Risk-Based Regional Assessment: A Checklist Approach.The checklist presents many of the U.K.&rsquo;s major timber laws and provides examples of evidence that can satisfy those specific requirements. The checklist is organized into three parts, each of which examines a different aspect of the production process. For example, the checklist analyzes the systems and practices put in place by forest management to minimize harmful consequences to the source forest. The checklist also inquires as to the labor practices employed at each level of production. Companies seeking to enter the U.K. market for wood pellets will need to be well-versed in both the Woodfuel Advice Note and the Risk Based Regional Assessment: A Checklist Approach, both published by the U.K. DECC and available online. Opportunity Ahead Europe&rsquo;s demand for wood pellets keeps increasing. According to U.K. DECC data, in 2013, the EU imported nearly 3.2 million metric tons of wood pellets, and in&nbsp; 2014, the U.S. exported 4.4 million metric tons to Europe accounting for nearly $500 million. These figures demonstrate that suppliers can expect continued and exponential growth in demand for American wood pellets in the years to come. To capitalize on this demand, American wood pellet suppliers need to ensure compliance with the import country&rsquo;s wood pellet certification guidelines, which may include consulting those parties with experience in analyzing and adhering to such guidelines. Authors: Mark Aspinall Partner, Sutherland Asbill &amp; Brennan LLP msa@arbis-sutherland.com +44 (0)20 7553 8000 Virgina E. Worthy Associate, Sutherland Asbill &amp; Brennan LLP Jenny.worthy@sutherland.com (404) 853-8011

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Given that the U.S. is exporting a vast majority of wood pellets manufactured in the country, concerns arise as to whether the production
and manufacturing process meets the statutory or regulatory requirements of those foreign markets.

Regulation of Europe-Bound  US Wood Pellets

In 2011, we noticed a glaring omission in an annual U.S. government publication.&nbsp; The annual Winter Fuel Report failed to mention wood and pellets, one of the most common heating fuels in America. Members of Congress were also appalled. The next year, the report began covering wood and pellet heat, not just fossil fuel heat. Now we find the same parent agency, the U.S. DOE, omitting any mention of wood and pellet heating in a major, consumer-oriented publication and inserting the word solar where wood and pellets should be. The publication, Energy Saver: Tips on Saving Money &amp; Energy at Home, is one of the DOE&rsquo;s main consumer-oriented energy efficiency&nbsp;&nbsp;&nbsp;&nbsp; publications. The glossy, 41-page booklet is distributed free of charge and contains scores of excellent suggestions on how to save on your utility bills. The section on renewable energy tells consumers they have many options for using renewable energy at home, including solar and small wind turbines. The booklet also discusses geothermal and solar thermal.&nbsp; It states: &ldquo;Solar panels are the most popular form of renewable energy today.&rdquo; There are not even half a million homes with solar panels and about 10 million homes with wood or pellet stoves. On an annual basis, wood and pellet stoves still outsell solar panels. By 2020, there still be less than one million homes with solar. Even if the high estimates are correct, the number of homes using solar is still less than half the number of those with installed stoves. So why does the DOE say solar panels are the most popular form of residential energy, and why does it not even mention wood or pellet stoves in the renewable energy section? It&rsquo;s understandable that wood stoves aren&rsquo;t being endorsed as an energy pathway that should rapidly expand (particularly in western states where inversions often trap particulates). But pellet stoves and boilers provide an excellent option for homeowners in most of the country to reduce fossil fuels and affordably heat their homes without producing excessive emissions.&nbsp; About 10 states offer rebates or tax incentives to install pellet stoves or boilers. There are liberal leading states that are trying to expand residential renewable energy deployment, such as Maryland, Massachusetts, New York, Oregon and Vermont. Then there are more conservative states, like Idaho, Maine, Montana and New Hampshire, which also see the benefits of helping households use a local renewable resource to affordably heat their homes. Why is the DOE so out of touch with what is happening around the country? As the Obama administration and much of the country is increasingly focused on reducing fossil fuel use, the main federal agency in charge does not even see fit to mention a powerful HVAC device that drastically reduces or eliminates fossil heating fuels in more than 10 million U.S. homes.&nbsp; A $2,000 or $3,000 dollar pellet stove can easily provide 40 to 100 percent of most homes&rsquo; space heating needs.&nbsp; A typical 5-kW array of solar panels can provide about the same amount of energy in a year as a pellet stove can provide in four to five months.&nbsp; The DOE should initiate more programmatic work on wood heat.&nbsp; Short of that, it should at least acknowledge the existence of wood and pellets in booklets like this and help educate homeowners about how they can best use them.&nbsp; For instance, this booklet could urge homeowners to upgrade from an old, uncertified wood stove to a cleaner, more efficient pellet stove.&nbsp; It could also explain how modern, automated pellet boilers, like the ones that are so popular now in Europe, can provide both space and water heating and are a great complement to solar panels. Accuracy and honesty are above all important, and ignoring the efforts of more than 10 million homes does not advance our common efforts to reduce fossil fuel use. The DOE should be striving to reach diverse constituencies, not just the urban, affluent people who can afford more expensive energy upgrades like solar panels or wind turbines.&nbsp; The booklet even suggests small wind turbines are good to charge a sailboat battery.&nbsp; A sailboat battery?&nbsp; What audience is DOE trying to reach?&nbsp; The demographic who could install small wind turbines is relatively small, and those who would use them to charge a sailboat battery is miniscule, but the demographic that could benefit from pellet stoves is huge. It would help if there were an Energy Star label for wood and pellet stoves, so that federal and state agencies could better guide the deployment of these technologies as they do for all other major HVAC appliances. However, the development of such a label may be years away. For now, simply acknowledging the existence of wood and pellet stoves as a popular renewable energy option and educating the public about how and where to best use them is a good start. Author: John Ackerly President, Alliance For Green Heat jackerly@forgreenheat.org www.forgreenheat.org

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Alliance For Green Heat President John Ackerly discusses a major oversight of the U.S. DOE—omitting mention of wood and pellet heat in its recent Energy Saver guide.

Omission of Wood Heat  Goes Too Far

Climate change has evoked carbon emission reduction strategies worldwide. In the U.S., seven of the top 10 warmest years on record have occurred since 1998, with carbon pollution deemed its biggest driver. Recognizing that, President Obama&rsquo;s Climate Action Plan directed the EPA to work closely with states, industry and other stakeholders to establish carbon pollution standards for both new and existing power plants, which currently account for roughly one-third of all domestic greenhouse gas emissions (GHG). On June 2, 2014, the U.S. EPA proposed the Clean Power Plan to help reduce carbon emissions by 30 percent from 2005 emission levels by 2030. The federal initiative began making headway in 2010, and although biomass could serve as one of numerous methods to help achieve this aim&mdash;and its landing in the mandate looks favorable&mdash;nothing is certain until touchdown. The current status of the mandate is best understood by stepping through the preceding chain of events. In 2010, the EPA issued its GHG Tailoring Rule, which aimed to tailor default emissions levels contained in the Clean Air Act to make them applicable to GHG emissions. However, the rule did not distinguish biogenic emissions from fossil fuels, and did not exclude biogenic carbon dioxide (CO2) from applicability under prevention of significant deterioration (PSD) and Title V permitting thresholds. &ldquo;That created great concern for the forest products industry&mdash;land owners, biomass power, all of the people in the larger value chain,&rdquo; says Paul Noe, vice president of public policy with American Forest and Paper Association. &ldquo;We went to the EPA and voiced those concerns and they agreed to step back and do a more detailed science review of this issue.&rdquo; The agency responded by issuing a three-year deferral of biogenic CO2 regulations in July 2011. A few months later, the EPA drafted the Accounting Framework for Biogenic CO2 Emissions from Stationary Sources, which was reviewed by the EPA&rsquo;s Science Advisory Board, a panel of scientists and experts representing several areas of forestry and agriculture. The SAB panel was tasked&nbsp; with reviewing the EPA&rsquo;s overall approach and accounting practices, as well as suggesting improvements to the original framework accounting model. Last November, EPA issued a revised framework, informed by the SAB&rsquo;s report and public comments, for a second round of targeted peer review with the SAB. This round of analysis is ongoing and could be for a while. Current review is focusing on charge questions pertaining to specific areas of the framework that were not addressed in the prior revised report, and where the EPA would like further guidance. Specifically, the EPA requests the panel examine and offer recommendations on future anticipated baseline specification issues in assessing the extent to which the production, processing and use of forest and agriculture-derived biogenic material at stationary sources for energy production results in a net atmospheric contribution of biogenic CO2 emissions. This framework presents an equation called the biogenic assessment factor (BAF) equation, which includes terms representing different aspects of the biological carbon-cycle dynamics associated with biogenic feedstock growth, harvest, processing and use at stationary sources. The second draft of the framework was also accompanied by a memorandum issued by Janet McCabe, acting assistant administrator for the Office of Air and Radiation, to the EPA&rsquo;s Regional Air Division directors describing the agency&rsquo;s current thinking regarding biogenic CO2 emissions in the context of the CPP and the PSD Program. It is these two documents the biomass industry has looked to as a means of gauging what role biomass will play in upcoming policy. Overall Optimism &nbsp;&nbsp;&nbsp; Bob Cleaves, CEO of the Biomass Power Association, believes the revised framework and accompanying memo support a clear, science-based approach that provides regulatory certainty while deferring important policy implementation to the states. &ldquo;It&rsquo;s hugely positive what the EPA did in November, because it essentially gave the industry a kind of carbon stamp of approval,&rdquo; Cleaves says. &ldquo;We&rsquo;re starting to put a price on carbon, recognizing the environmental benefits of the industry and providing the industry with the same kind of benefits that solar, wind and other renewable technologies receive.&rdquo; Noe says the AF&amp;PA also finds the documents favorable. &ldquo;We&rsquo;re pleased that while it has been a long path, EPA has recognized the carbon neutrality of biomass derived from certain forest products manufacturing residuals, and we think that it&rsquo;s clear when you look at the McCabe memorandum and the revised framework.&rdquo; All in all, players in the biomass industry are taking the news from the EPA as a good sign. Even so, the industry seeks certainty in regulatory text. The memorandum clarifies what biomass energy qualifies as carbon neutral in some respects, but doesn&rsquo;t definitively answer the question across the board. In the documents, EPA makes a preliminary finding that the use of certain forest-derived industrial byproducts and waste-derived feedstocks for energy are carbon neutral, and shows specific analysis that use of spent pulping liquor for energy is carbon neutral. The agency intends to apply these findings in future Clean Air Act regulations. However, AF&amp;PA hopes for certainty on the carbon neutrality of energy derived from certain forest products manufacturing residuals, and how EPA will determine whether trees that may be used for energy are sustainably derived. One of BPA&rsquo;s requests is for the EPA to broaden its definition of waste-derived materials by including nonforestry cellulosic materials&mdash;like urban wood, wood-derived construction and demolition debris and railroad ties&mdash;since these are organic materials that do not cause land use changes and do not deplete carbon stocks. The association also encourages the EPA to state that biomass power plants that use the feedstocks covered by the McCabe Memorandum be exempt from regulation under the CPP.&nbsp; In the testimony BPA submitted to the SAB panel, it argues that the use of fuel is a function of price, rather than carbon accounting. In the words of the association, if the EPA were to conclude that all biomass is carbon neutral, the fear that biomass electricity would undertake major harvests and compete with the value of pulp and sawlogs is fantasy. &ldquo;It&rsquo;s virtually inconceivable that power prices would reach the point where it would make economic sense to harvest natural forests,&rdquo; Cleaves says. In order for the industry to use merchantable fiber, Cleaves estimates power prices would have to reach somewhere between 15 to 20 cents a kilowatt hour (kWh).&nbsp; &ldquo;The idea that by the EPA somehow giving us the green light to harvest natural forests is going to&mdash;with a wave of a magic regulatory wand&mdash;allow us to go out and use any type of biomass is just patently absurd on the economics.&rdquo; Chance to Cofire Besides fear of overharvesting, some may question whether U.S. coal plants will rapidly convert to biomass with supportive policy. William Strauss, founder and president of FutureMetrics, recently published white papers making the case that the CPP is not a war on coal, and that a gradual transition to cofiring at coal plants can be made without the assumed negative impacts. Strauss states in his paper, &ldquo;If the coal industry and the power stations that use coal follow a strategy that is proven successful in Europe and South Korea, coal plants will not close and coal producers may see their margins improve.&rdquo; Strauss says the generation company that cofires wood pellets with coal to achieve a 10 percent reduction in CO2 will increase its cost of production by less than one penny per kWh, significantly less than the current cost of wind or solar power for achieving the same reduction. He uses the example of a 325-MW power plant cofiring at 89 percent coal and 11 percent pellets for a 10 percent CO2 reduction. Strauss refers to this as a rational and pragmatic off-ramp to a decarbonized future, or a gradual transition to a less carbon-intensive power generation sector. &ldquo;It&rsquo;s a low-cost, decarbonizaiton pathway, but it&rsquo;s still about a penny per kWh more than just plain old coal, so unless the utility is going to get either approval from the ratepayer or get support from policy, they are just going to burn coal,&rdquo; Strauss says. &ldquo;They&rsquo;ll take the cheapest generation path forward if there is no incentive for them to change from business as usual.&rdquo; Strauss affirms there will still be the need for other carbon mitigation solutions. &ldquo;You couldn&rsquo;t cofire in all plants, there are not enough sustainable feedstocks to produce that quantity of pellets,&rdquo; he says. &ldquo;Right now the market is overseas. There are underutilized wood baskets further inland that are either underutilized because they&rsquo;ve lost their traditional customers in the pulp and paper business or they never had those customers to begin with.&rdquo; Strauss adds that coal producers can benefit from the Clean Power Plan if they engage with pellet manufacturers. &ldquo;It is a strategy that unites the states with the power plants, the coal producers and the pellet producers.&rdquo; Slow and Deliberate Because price defines biomass feedstock options, the BPA submitted comments advising the SAB and EPA to focus on the low-value feedstock currently in use when finalizing the current framework. Greg Morris of the Green Power Institute testified at the latest SAB meeting, calling for clarity on how the fuels the existing industry uses&mdash;residues and byproducts&mdash;are going to be treated in respect to carbon accounting. A section of Morris&rsquo;s prepared comments reads, &ldquo;In the opinion of the GPI, the SAB has a real opportunity to provide a valuable service to the biomass industry and the renewable energy industries in general by expeditiously memorializing its consensus that biomass fuels derived from residue and byproduct forms of biomass should be assigned a BAF value of zero.&rdquo; The latest SAB teleconference was held May 29, where four other registered public speakers joined Morris, followed by a discussion of general conclusions about the framework and ending with a debate on the specific charge questions. Three more teleconferences have been slated to discuss the charge questions this summer. Still, there is no timeline set for when SAB&rsquo;s conclusive advice on the charge questions must be offered to the EPA. Holly Stallworth, designated federal officer with the SAB, says, &ldquo;We&rsquo;re going slower and in a more deliberate fashion.&rdquo; She commented that the revised framework is more of an academic exercise and that it has been declared by the EPA as policy neutral. &ldquo;They are saying that they do not plan to channel it into policy and not into the CPP at this time,&rdquo; Stallworth says.&nbsp; The framework released in November maintains the policy agnostic approach from the first version and does not provide a detailed discussion of specific policy and implementation options. The language in the framework reads, &ldquo;EPA has not yet determined how the framework might be applied in any particular regulatory or policy contexts or taken the steps needed for such implementation.&rdquo; The framework does explain particular elements of the framework equation where policy-relevant choices would need to be made for application to a specific policy or program, but ultimately it&rsquo;s a technical document that does not set regulatory policy. SAB members are split on the issue. Some on the panel agree the accounting framework should be policy neutral, while others believe it can only be useful or contextual if it is specifically designed to address the policy issues for which its use is intended to provide reliable input. Madhu Khanna, chair of the biogenic carbon emissions panel, noted during a March 25 meeting that the panel&rsquo;s responses to the charge questions could be better answered if policy context that affects scale, targets and mix of feedstocks were provided, because answers would differ depending on the policy.&nbsp; During the May meeting, Khanna stated that the framework doesn&rsquo;t explicitly state a policy context. However, &ldquo;You could implicitly get from this that the policy context is regulation of CO2 emissions from stationary sources under the Clean Air Act,&rdquo; she says. &ldquo;We really need to focus on this narrow question of whether more details about the policy context, other than this implied one of the Clean Air Act, are needed in order to determine the BAF that is defined in this framework.&rdquo; Cleaves&rsquo; stance is that &ldquo;by keeping the process completely separate from policy considerations, the panel may be keeping biomass power in a policy limbo at a time we can&rsquo;t afford uncertainty,&rdquo; he says. &ldquo;We need a clear understanding of how biomass will count under the CPP.&rdquo; Besides policy context and implementation, the more comprehensive discussion and analysis the SAB is conducting as it prepares its report for the EPA includes detailed technical appendices on the following topics: baseline approaches, spatial- and temporal-scale decisions and implications, inclusion of alternative fate analysis for certain feedstocks and methane, leakage and illustrative regional feedstock-specific calculations using existing data sources and models, and resulting regional biogenic assessment factor values.&nbsp; During its last meeting, the SAB panel was only able to begin discussing the first charge question regarding temporal scale, essentially considering over what time horizon the impact of using biogenic sources should be measured. The meeting concluded with plans to begin discussion there at the next meeting in July. It is clear, deliberation over the framework is a difficult and timely process. If the EPA does not make a definitive decision on biomass in its CPP and defers to the SAB&rsquo;s judgement, which could be years down the road, Cleaves and others believe it could have an adverse impact on the biomass industry. If not included at all, which most deem unlikely, Cleaves believes the effects could be negative or even catastrophic. &ldquo;The negative effects would be that states aren&rsquo;t encouraged to include biomass and that would not be helpful in terms of continuing to recognize biomass in state renewable portfolio standard programs. The catastrophic effect would be, if we aren&rsquo;t included, then almost by definition we&rsquo;re part of the problem, and we would be regulated like a coal plant, required to purchase offsets or install pollution control technology.&rdquo; If regulated like a coal plant, Cleaves says, biomass plants would have no way to pass on those costs to ratepayers, as they are independent power producers. &ldquo;We would close down, material would get landfilled, forest fires would proliferate, methane emissions would increase&mdash;the climate would be worse off.&rdquo; Noe says that it&rsquo;s also important that whatever policy comes about in this context and others that it doesn&rsquo;t cause market distortions. &ldquo;If you think about how the forest products industry uses manufacturing residuals for energy, every bit of the tree that can be used for higher value products like pulp paper packaging and wood products are used for that purpose,&rdquo; he says. &ldquo;It&rsquo;s just these residuals that don&rsquo;t have a higher value use and would otherwise go to waste if not used for energy that wind up being used. We think the market is the best way to ensure that biomass is being used for its best and highest use.&rdquo; The biomass industry calls for certainty this summer with the release of EPA&rsquo;s CPP. &ldquo;We have a good story,&rdquo; Cleaves says. &ldquo;It&rsquo;s backed by science and I think we are kind of creeping towards a resolution that is going to be favorable to the industry, as it should be. I think what we see this summer in the CPP is going to be really important.&rdquo; Author: Katie Fletcher Associate Editor, Biomass Magazine 701-738-4920 kfletcher@bbiinternational.com

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Biomass's role in the federal Clean Power Plan is up in the air, 
but the industry hopes for a smooth touchdown. 

Readying for a Regulatory  Landing

Depending on market conditions, biomass power can sometimes be a tough proposition. Government support is crucial in many areas, and also warranted, when considering the environmental and economic benefits from biomass alongside the often high cost of fuel. In California, the biomass industry is facing some severe challenges. In recent years, many facilities have shut down as Public Utility Regulatory Policies Act of 1978 contracts expired and natural gas became a cheaper and available option. Several newspaper articles from around the state have documented the decline of biomass and the markets that would be affected if local facilities were to shut down. A good portion of the 565 MW of biomass power are in jeopardy, and with them, many farmers who rely on their local facilities to purchase residues from orchards and other agricultural waste. A recent article in the Hanford Sentinel, &ldquo;Decline of Valley biomass plants a threat to ag,&rdquo; covered the biomass crisis. It reads in part: &ldquo;Growers are asking: If you can&rsquo;t burn orchard trees that have been removed, and you&rsquo;ve got no biomass plant to send them to, where does it all go? &lsquo;They just pile up,&rsquo; said Dino Giacomazzi, Kings County Farm Bureau president. &lsquo;Currently, biomass plants are about the only way we have to dispose of orchard removal.&rsquo;&rdquo; &nbsp;The dilemma was further explored in another story in California&rsquo;s Woodland Daily Democrat, &ldquo;Biomass power plants running out of steam.&rdquo; It reads in part: &ldquo;Tulare County farmer Chris Lange has about 80 acres of uprooted citrus and olive trees that he needs to have cleared and chipped. Lange said he is waiting on a chipping company, which has not yet received approval from biomass plants to bring the orchard waste in to be processed into electricity. &lsquo;We have been waiting for the chipper to come and it is just not happening,&rsquo;&nbsp; Lange said. &lsquo;I understand that the contracts for the chippers by the cogeneration plants are not being renewed. We (in the San Joaquin Valley) have more permanent crops being pushed out than ever, and this leaves everybody hanging.&rsquo;&rdquo; The Woodland Daily Democrat went on to quote Steve Brink, California Forestry Association vice president of public resources, who said that electricity produced from natural gas costs 2 to 6 cents per kilowatt, whereas biomass power costs about 10 cents per kilowatt. &ldquo;With no direction from state government to pay the known environmental benefit, what would you expect the utility to do?,&rdquo; the Democrat quoted Brink. &ldquo;The state has not provided any direction of where this (biomass) needs to go. There&rsquo;s 1 million, bone-dry tons just in the Northern California forests on both public and private lands that is piled up and burned, now that there&rsquo;s no place to take it.&rdquo; With orchard growers pulling out and replacing older trees with young trees in an effort to conserve water during the drought, and with fewer biomass plants operating, &ldquo;the problem is now amplified,&rdquo; Brink said. Luckily, there is some good news. The California state legislature is considering a bill that would help shore up the industry by recognizing its environmental benefits. Led by the California Biomass Energy Alliance, the bill will direct $50 million to a Biomass State Cost Share Account within the Greenhouse Gas Reduction Fund. The Assembly overwhelmingly voiced its support for the biomass industry by passing Assembly Bill 590,&rdquo; said Julee Malinowski-Ball, executive director of the California Biomass Energy Alliance, in the association&rsquo;s press release. &ldquo;This bill will provide needed funding for biomass plants by allocating Greenhouse Gas Reduction Funds to the facilities for its environmental benefits.&rdquo; Malinowki-Ball continued, &ldquo;For more than a quarter century, biomass plants have been providing reliable, renewable, utility-scale power in California. Despite our numerous benefits, biomass is often overlooked.&nbsp; This funding will ensure that biomass plants will be compensated for its environmental benefits.&rdquo; The bill unanimously passed assembly floor and will now head to the California Senate. This is good news, and not just for the California biomass plants facing closure. As the U.S. EPA&rsquo;s final Clean Power Plan is released later this summer, California&rsquo;s support for biomass sets a precedent for other states designing their own carbon reduction plans. Author: Bob Cleaves President and CEO, Biomass Power Association www.biomasspowerassociation.com bob@biomasspowerassociation.com

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Biomass Power Association Bob Cleaves discusses challenges currently being faced by the California biomass power industry.

California Biomass Support Sets Good Example

Algae.Tec announces collaboration Algae.Tec Ltd. has announced the execution of a collaboration agreement for the commercialization of its algae production technology with Dominic Republic-based Larimar Energy SRL. The companies are collaborating on the development of algae production projects in the Dominican Republic and Caribbean region. Latvia pellet plant planned Sia Broceni Pellets, a subsidiary of AS Graanul Invest, has acquired 16 hectares of land in Latvia to construct a 150,000-ton-per-year pellet plant. The facility is expected to begin operations early next year. It will be the eighth pellet plant developed by Graanul Invest. Solenis opens world headquarters Solenis LLC celebrated the grand opening of its new world headquarters April 27. Located in Wilmington, Delaware, the headquarters will currently accommodate approximately 120 employees supporting a variety of corporate functions for the specialty chemicals company, which was previously known as Ashland Water Technologies. Space for additional expansion has been allocated. The opening of the world headquarters follows the opening of the company&rsquo;s European headquarters in Schaffhausen, Switzerland, last year. Cirque Energy appoints CEO Cirque Energy Inc. has named Rodger Silverthorn chairman, president and CEO. Silverthorn, who previously served as the company&rsquo;s executive vice president for business businesses development and secretary, replaces former CEO, President and Chairman Joseph DuRant, who died. Silverthorn will continue to serve as director of the company, and the remainder of Cirque Energy&rsquo;s leadership team will continue with their present responsibilities. Cirque Energy also recently appointed Patrick Rogers to its board of directors. He currently serves as CEO of the Laguna Group Inc. Vecoplan adds team member Michael Wilhoit has rejoined Vecoplan LLC as a project engineer. Wilhoit&rsquo;s new position includes coordinating the design and development of turnkey shredding systems for the recycling sector. In order to ensure continuous quality control, he will also oversee the manufacture and implementation of his projects once the engineering phase has been completed. Prior to rejoining Vecoplan, Wilhoit was managing partner at AREco Industrial Services. Bioplastics organization founded Holland Bioplastics has been founded in the Netherlands to share relevant knowledge about bioplastics and connect relevant parties. Founding partners of the organization include Corbion, NatureWorks, Bio4Pack and Braskem. Participation is open to those involved directly or indirectly in the production, manufacture, research, or marketing of bioplastics. Capstone supplies microturbine to Lithuanian biogas project&nbsp; Capstone Turbine Corp. has received an order for a C800 microturbine to upgrade a facility operated by a pork producer in Lithuania. The C800 microturbine will be fueled by biogas produced on site. It will be installed in a combined-heat-and-power application along with an anaerobic digestion, fuel compressor and heat exchanger. ADBA appoints board members The Anaerobic Digestion and Bioresource Association has added three new board members. They are Julian O&rsquo;Neill, chief executive of Biogen; William Heller, chief executive of Tamar Energy; and David Greenfield, advisor to the Local Authority Waste Network Coordinators and managing director of Social, Environmental and Economic Solutions Ltd. Terex Materials acquires CBI Terex Materials Processing, a business segment of Terex Corp., and Continental Biomass Industries Inc. have announced the acquisition of the assets of CBI by Terex, marking an expansion of the Terex Environmental Equipment product line. TEE, part of Terex Materials Processing, has been serving the wood, biomass and recycling industries since 2011. The acquisition of CBI&rsquo;s business, in operation since 1988, significantly advances the product line while adding dimensions to the TEE business that would otherwise have taken years to develop. The acquisition also adds customization and specialty product capabilities that enable TEE to serve even the most demanding requirements of customers worldwide. Alstom, NG Metal&uacute;rgica sign steam turbine agreement Alstom and NG Metal&uacute;rgica have signed a cooperation agreement to jointly approach the Brazilian marketplace for high-performance small and midsized steam turbines. Under the agreement, NG Metal&uacute;rgica will sell Alstom&rsquo;s geared reaction steam turbines high-speed reaction type steam turbines in Brazil. Alstom will share all necessary technology with its partner while contributing certain engineering services and components to the turbines sold by the Brazilian company.

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Business Briefs

The renewable fuel standard (RFS) is the greatest piece of renewable energy policy the world has ever seen, according to Brooke Coleman, executive director of the Advanced Ethanol Council. Coleman would likely agree that, consequently, the RFS has also generated the largest policy backlash and opposition the world will ever see. The RFS, originally passed as part of the Energy Policy Act of 2005, was expanded and extended in the Energy Independence and Security Act of 2007. It gave rise to a corn ethanol industry with annual production values of over 14 billion gallons, or right around 10 percent of the annual U.S. gasoline consumption. As successful as the RFS has been, those who have dedicated their livelihoods to fulfilling the mandate are now fighting to defend it. This is illustrated in Managing Editor Anna Simet's page-36 department, "Crunching the Numbers," a summary of Coleman's and other biofuel stakeholders' comments at the 2015 International Fuel Ethanol Workshop &amp; Expo. While this may seem counterintuitive to the general public, renewable energy advocates are likely to react with a knowing and affirmative shrug of the shoulders. Ours is an industry looking to take market share, often in declining markets, from well-entrenched incumbents who can only be expected to rabidly defend their enviable market position. In nearly every category, industry groups are drafting, working to generate support for, expanding or defending existing renewable energy policies that are so vital to the greater biomass industry. This issue of Biomass Magazine examines the ridiculously complex, overwhelming, challenging and mind-numbingly bureaucratic battleground that we are all combatants upon, whether we like it or not. Coleman&rsquo;s assertion is supported throughout the issue. In Simet&rsquo;s page-26 department, &ldquo;Thermal Reinforcement,&rdquo; her sources succinctly establish that the kind of federal mandate enjoyed by the biofuels sector is hardly even worth talking about, and likely makes more sense to tackle at the state level, owing to the different ways thermal energy needs are met across the country. In fact, Charlie Niebling, one of the preeminent thermal biomass advocates in the country, suggests a comprehensive, federal renewable energy standard is a &ldquo;utopian notion.&rdquo; Recognizing that, Niebling and others have set their sights on state-level policy victories and are making real progress in the Northeast. I&rsquo;ll warn you now that the stories in this issue of Biomass Magazine will likely cause frustration. Policy is vital to our industry&rsquo;s growth, but it is not a guarantee, and just as soon as our industry enjoys a policy victory that starts to bear real fruit, the hard work of defending our position begins.
Author: Tim Portz Vice President of Content&nbsp; &amp; Executive Editor tportz@bbiinternational.com

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Biomass Magazine Executive Editor Tim Portz reflects on the July issue and the battles faced by the entire biomass energy industry.

The Inevitable Battle

Summer is a difficult time to discuss thermal policy. Homeowners are thinking about summer vacations and spreading mulch, while businesses are executing midyear performance reviews. The inevitable return of the heating season is low on most people&rsquo;s priority list, but naturally, it&rsquo;s at the top of the Biomass Thermal Energy Council's agenda, and we&rsquo;re making it a priority for Congress, too. There are three legislative options before the Senate and House of Representatives that could break open the market for biomass thermal technologies and fuels. All three vehicles would use the Business Investment Tax Credit to incentivize thermal projects, but achieve market growth using substantially different strategies and constituencies. The first bill would have the strongest direct economic effect on the biomass heating industry. The Biomass Thermal Utilization Act or BTU Act packages a 30 percent residential renewable energy tax credit with a 30 percent business ITC for commercial and industrial high-efficiency biomass thermal technologies. It would avoid 1.3 million tons of carbon dioxide production, create approximately 35,000 jobs, and increase renewable energy by nearly a gigawatt hour by 2017. More importantly, the BTU act is revenue-positive for the U.S. Treasury (creating more economic activity from the credit than it costs), and its cost pales in comparison to that of other energy ITCs and residential credits. Interest in combined-heat-and-power (CHP) industrial energy efficiency currently commands a larger, though complex, base of political and industry support. CHP currently enjoys a 10 percent ITC for commercial and industrial applications through 2016. ICF International has estimated that 698 biomass-fueled CHP sites comprise 3,837 MW of electrical generation capacity (4.6 percent of total U.S. capacity), with another 630 MW under development. The POWER Act, S.1516 and H.R.2657, would boost the existing CHP ITC from 10 to 30 percent of installed costs and extend the credit through 2018. On its face, this bill would appear to support broader deployment of biomass thermal systems that also generate electricity. However, the new CHP bill maintains a subrequirement that qualifying systems must also have a minimum electrical efficiency of 20 percent. Athough biomass thermal-led CHP systems can surpass the 60 percent minimum overall efficiency requirement for this ITC, even the best-designed thermal-led systems find it difficult to meet the 20 percent electrical efficiency target when using backpressure steam turbines and organic Rankine cycles (among other technologies). BTEC's position, which may appear counterintuitive, is that reducing the minor electrical efficiency criterion to 5 or 10 percent would yield a greater number of more efficient projects. Waste heat to power (WHP) is the newest entry in the congressional energy tax policy, and it benefits from broad general support among industrial efficiency champions. S.913 would provide a 30 percent ITC for WHP equipment. WHP technologies capture exhaust heat, gas pressure drops, rejected system heat, and mechanical heat, and converts them to electricity. ICF International estimates U.S. potential for WHP installations to be 14.6 GW, with approximately 7 percent from the forest products and pulp and paper industries. Wasted heat appears to be a significant opportunity to avoid greenhouse gas emissions and encourage more efficient commercial and industrial operations, however, we often encounter misunderstandings about the differences between WHP, CHP and biomass thermal systems amongst think tank experts, congressional staffers and others. According to the U.S. DOE, a WHP system is also considered a CHP system when energy is recovered from an industrial process (a CHP bottoming cycle). In fact, we have seen this in operation at Integrated Biomass Resources in Wallowa, Oregon, where excess biomass heat from a lumber kiln generates power through twin ElectraTherm Organic Rankine Cycles. From our perspective, the WHP bill improves upon the CHP ITC by removing the arbitrary minimum electrical efficiency level, while recognizing the importance of thermal energy from a broad range of fuels. Certainly, S.913 is no panacea for biomass thermal systems, but it may prove beneficial to thermal-led CHP systems. With these three irons in the fire during the waning legislative days of 2015, what are biomass advocates to do? First, we must continue supporting the most beneficial bill to our industry, the BTU Act. We still feel the adverse effects of our industry's past lack of coordination when thermal technologies like geothermal and solar entered the tax code in 2008 and biomass did not. We should also be aware of our technology and fuels' eligibility in other energy tax proposals, like the new CHP and WHP tax credits, and offer our support&mdash;or at least lack of opposition&mdash;when key votes come. Thermal energy is at last receiving recognition in tax policy, and we ought to link arms with other industries to propel these legislative efforts across the finish line. We can't do much about summer temperatures, but together we can change the conversation this congressional season. Authors: Joseph Seymour Executive Director, Biomass Thermal Energy Council Ben Bell-Walker, Technical Affairs Manager, BTEC info@biomassthermal.org

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The Biomass Thermal Energy Council weighs in on policy pieces the biomass thermal industry should keep an eye on this summer.

Thermal Incentives Heat Up

If Renewable Fuels Association President Bob Dinneen didn&rsquo;t light a fire under the ethanol industry at the International Fuel Ethanol Workshop in Minneapolis in early June, then it may be an impossible feat. Dinneen, whose career in the ethanol industry has spanned nearly a quarter of a century, delivered a rousing and passionate speech during the general session of the conference, where leaders of both the first- and second-generation sectors offered candid takes on the proposed U.S. EPA renewable volume obligation (RVO) numbers, reported on existing and future production, and provided insight on industry trends, challenges and competition. Dineen referred to the RVO numbers as being &ldquo;strangely familiar,&rdquo; and said that the EPA believes it is attempting to break the blend wall, but characterized it as &ldquo;scratching it&mdash;an incomprehensible step backward.&rdquo; He said it appears EPA learned &ldquo;absolutely nothing&rdquo; from the massive number of comments received during the RVO comment period, and that the agency has consistently made the wrong decision on any number of issues. He implored audience members to attend the public hearing to be held in Kansas City on June 25. Brooke Coleman, executive director of the advanced ethanol coalition, brought things in a slightly more positive direction, declaring the RVO as being far from ideal, but said there is room for optimism, one reason being that the numbers are not yet final. &ldquo;We could find ourselves in a profoundly different place&hellip;until then&hellip;we can&rsquo;t be disappointed.&rdquo; Coleman also commented that the D3 renewable identification number (RIN) marketplace is being mismanaged, a point that Dan Cummings, president of Poet-DSM Advanced Biofuels, reiterated. Cummings described the current system as being &ldquo;One of the more disappointing things for the new cellulosic ethanol producers&hellip;the EPA&rsquo;s allowance for obligated parties to buy waiver credits instead of actual physical gallons. They&rsquo;re undermining the D3 system,&rdquo; he said. Chris Standlee, executive vice president of Abengoa Bioenergy, discussed how the EPA&rsquo;s rulemaking delays have hampered advanced biofuels in the U.S. &ldquo;I can speak from experience that it has impacted investment&hellip;&rdquo; he said, adding that it doesn&rsquo;t mean that Abengoa has discounted the U.S. as a location for future facilities, as the company is actively pursuing a project using municipal solid waste as feedstock. However, Abengoa is largely focused on locations outside of the country, according to Standlee, including a second-generation facility in Brazil, colocated with the company&rsquo;s ethanol plant there, as well as a second-generation facility in France, colocated with Abengoa&rsquo;s existing starch facility. Standlee reported that commissioning is ongoing at Abengoa&rsquo;s cellulosic ethanol facility in Hugoton, Kansas, saying &ldquo;Starting up a new technology plant is not for the faint of heart. We are producing, but not at full, annualized rates by any means.&rdquo; Cummings added that in the chemical processing industry, it generally takes about 20 years from when a process is isolated, to full-scale commercial production, and that Poet-DSM is currently working through some challenges in the pretreatment step of its process. The company brought online its first commercial-scale facility in Emmetsburg, Iowa, last fall. When asked if the companies feel pressure from the EPA to meet RVO numbers &mdash;as the country&rsquo;s first commercial-scale cellulosic ethanol plants&mdash;Cummings and Standlee said that most of the D3 category numbers will be fulfilled by biogas-based fuel over the next couple of years, but that the EPA polls advanced fuel companies to get an idea of what they project production will be. Standlee added that while there is healthy competition when it comes to selling licenses for a respective cellulosic ethanol technology, all producers currently in the game want to see each other succeed. The session ended with panelists urging audience members to send their comments to the EPA, and to attend the upcoming hearing in Kansas City, in order to achieve the best possible outcome in the final rule, due to be released in late fall. &ldquo;There will be huge ramifications from what happens in November for the advanced ethanol market,&rdquo; Coleman said. Author: Anna Simet Managing Editor, Biomass Magazine asimet@bbiinternational.com 701-738-4961

Mike Jerke, CEO, Guardian Energy Management; Jan Koninckx, global business director for advanced biofuels, DuPont Industrial Biosciences; and Chris Standlee, executive vice president, Abengoa Bioenergy, discuss first- and second-generation ethanol pr

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Brooke Coleman, executive director of the Advanced Ethanol Coalition, said that while the recently released renewable fuel standard renewable volume obligation numbers are far from perfect, they are not final and could change with the final RVO rulem

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First- and second-generation ethanol leaders discussed challenges, priorities and successes at the International Fuel Ethanol Workshop in Minneapolis.

Crunching the Numbers

On May 29, the U.S. EPA released its long-awaited renewable fuel standard (RFS) renewable volume obligation (RVO) proposal for 2014, 2015 and 2016.&nbsp; The newly proposed rule represents a significant improvement for the advanced and cellulosic biofuels industry relative to the original 2014 proposed rule.&nbsp; Unfortunately, there is still a long road ahead for the EPA to finalize this rule, which could be exacerbated by various legal challenges at the end of the rulemaking process. Covering three years, the proposal has been perceived as a mixed bag by many organizations. Some see it as an improvement over the previously introduced rule, while others see it as a step backward.&nbsp; For the next-generation biofuels industry, this proposed rule represents a solid improvement, especially for those in the advanced and biomass-based diesel pool, as well as those in the cellulosic pool seeking a concrete signal of the path forward for all advanced biofuels.&nbsp; The proposal utilizes actual production numbers&mdash;a pragmatic solution that the Advanced Biofuels Association has been advocating for the past 18 months&mdash;from 2014 and most of 2015 to set targets and proposes an advanced pool of 2.68 billion ethanol equivalent renewable identification numbers (RINs) for 2014, 2.9 billion for 2015 and 3.4 billion for 2016.&nbsp; These are significant increases over the 2.1 billion in 2014 rule. Moreover, the proposed RVO numbers send a strong signal of support from the administration for the continued development of the advanced and cellulosic fuels that deliver the highest greenhouse gas reductions under the statute.&nbsp; Specifically, for cellulosic, it accounts for the 33 million gallons produced in 2014, and proposes 106 billion and 206 billion in 2015 and 2016, respectively.&nbsp; And, the biomass-based diesel pool is afforded 1.63 billion gallons in 2014, 1.7 billion in 2015, 1.8 billion in 2016 and 1.9 billion in 2017. As for those who seem to be disappointed, the corn ethanol industry saw the EPA propose 13.25 billion gallons for 2014, 13.4 billion for 2015 and 14 billion for 2016.&nbsp; This is 1 billion gallons below the statutory number for corn ethanol as part of the overall program.&nbsp; Not to be outdone, voices from the oil industry associations are also unhappy, particularly with the 2016 proposal of 14 billion gallons of corn ethanol, given what they claim is a growing number of unblended gasoline gallons and the lack of demand for E-85 and E-15 in the marketplace.&nbsp; Both parties, either publically or in private, have started calling for lawsuits.&nbsp; In addition, some have doubled down their efforts to repeal or reform the program. Legislatively, it is still too early to know what the response from Congress will be. However, given a few weeks to review the rule and hear from various stakeholder groups, I expect to have a better view of the congressional path forward by the beginning of July.&nbsp; Already, several key members of Congress have voiced their frustration with the law and its implementation, and have called for overall legislative reform of the RFS.&nbsp; Others continue to strongly advocate for complete repeal, which would be a devastating blow for all renewable fuels.&nbsp;&nbsp; For those of you standing on the sidelines and wishing to weigh in on the topic, now is the time to write your members and draft your comments to respond to the proposed rule.&nbsp; EPA will hold a public hearing in Kansas on June 25 and has set the deadline for comments on this rule on July 27. It is important to note that the EPA has requested that comments focus on this new proposed rule only. Although this proposal is truly an improvement to the original proposed rule for the advanced biofuels community, the position of Advanced Biofuels Association remains unchanged.&nbsp; Statutory changes are required if we are ever to recognize what was envisioned by the original authors of the RFS2 in terms of building a next-generation biofuels industry of significance.&nbsp; Stay engaged. Author: Michael McAdams President, Advanced Biofuels Association michael.mcadams@hklaw.com www.advancedbiofuelsassociation.com

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Advanced Biofuel Association President Michael McAdams discusses the U.S. EPA's renewable fuel standard renewable volume obligation proposal.

A Look at EPA's RVO Proposal

California is by far the No. 1 dairy state in the U.S. with roughly 1.8 million head, concentrated mostly in the Central Valley. According to the California Milk Advisory Board, about one in every five U.S. dairy cows resides in California on some 1,500 to 1,600 farms. On average, each dairy cow produces about 27 to 29 tons of manure a year, meaning annual manure generation from California&rsquo;s dairy industry reaches an astounding 52.2 million tons annually. And with this much cow manure comes voluminous methane emissions, a potent greenhouse gas (GHG). Michael Boccadoro, executive director of the organization Dairy Cares, says 48 percent of California&rsquo;s methane emissions come directly from the dairy industry. Not only does California lead the nation in dairy production, but it is also a trailblazer in GHG reduction legislation with programs such as cap-and-trade and the low carbon fuel standard (LCFS), both fostered under the California Global Warming Solutions Act of 2006 (AB 32). The state also has one of the most ambitious renewable portfolio standards (RPS) in the country. With all of these legislative tools in place, and with more than 100 billion pounds of manure a year responsible for half of the state&rsquo;s methane GHGs, why are there fewer than two dozen dairy digesters established in California?
 &ldquo;That&rsquo;s the great question,&rdquo; says Neil Black, president of California Bioenergy LLC (CalBio). &ldquo;Because of those issues, we established CalBio. We have the largest dairy industry, the most sophisticated renewable energy environment and leaders on addressing climate change. I&rsquo;d say that the focus on the renewable energy side has historically been on solar and wind in California.&rdquo; Black says California is playing a major role in developing world-leading climate change initiatives, &ldquo;but those programs are just now getting put into place, and that is leading regulators to look at how to develop specific programs to develop dairy digesters.&rdquo; Black says there are ongoing discussions with California Air Resources Board to create a program to take dairy digestion to the much-needed next level. Boccadoro says the dairy industry is pushing ARB to tap into funds from the GHG Reduction Fund&mdash;proceeds from the cap-and-trade program&mdash;to develop 100 to 200 new dairy digester projects by 2022. &ldquo;The GHG Reduction Fund sits at about $2.3 billion so far this year alone,&rdquo; Boccadoro says. &ldquo;We&rsquo;ve asked for $100 million a year for five years. That&rsquo;s the impetus needed to get this industry off the ground. ARB recognizes something needs to be done, and we argue dairy digestion has the most bang for the buck in GHG reduction.&rdquo; Boccadoro says development of a robust dairy digester industry in California has little to do with permitting obstacles and boils down to availability of incentive funding and long-term contracts with utilities. He says when federal 1603 Recovery Act funding was available in 2013, procurement contracts were signed and five new projects got built, but in 2014 funding ceased and no contracts got signed and therefore no projects were built. He says there is still $10 million available in this year&rsquo;s state budget for dairy digesters allocated to the state food and agriculture department, and the next budget cycle looks even more promising. &ldquo;The governor wants $25 million and the legislature has requested $30 to $50 million,&rdquo; he says. In June 2013, Boccadoro and several other experts drafted a report for USDA titled &ldquo;Economic Feasibility of Dairy Digester Clusters in California: A Case Study,&rdquo; in which the authors lay out the regulatory and permitting environment in California. The report lists several legislative tools on the books that can be leveraged, or that were specifically designed, to promote dairy digesters, including the cap-and-trade program, the RPS, the LCFS, AB 1900, AB 2196 and SB 1122.&nbsp; The report notes AB 1900 was passed in 2012 to clarify and facilitate requirements for injection of biomethane into California&rsquo;s vast natural gas pipeline system. State law previously prohibited landfill gas from being injected into the pipelines and utilities imposed strict quality and testing requirements on other sources of biogas, such as dairy biogas, making pipeline injection difficult. AB 1900 requires the California Public Utilities Commission, in consultation with the Office of Environmental Health Hazard Assessment and ARB, to develop standards for constituents in biogas to protect human health and pipeline integrity and safety. AB 1900 was expected to facilitate and streamline biomethane injection and promote in-state production and distribution of renewable natural gas. In May, the CPUC issued a proposed decision on regulatory implementation of AB 1900 that imposed the cost of testing on biomethane producers and announced development of an incentive program to offset interconnection costs. Patrick Serfass, executive director of the American Biogas Council, says the proposed rule is &ldquo;a nice gesture and very well intentioned, but there are some problems in execution.&rdquo; &ldquo;Bearing the cost of testing the gas species listed in the &lsquo;constituents of concern,&rsquo; especially to the extremely low levels required, is generally not viewed as fair, especially since nonrenewable natural gas suppliers do not have to pay to test for potentially hazardous trace components present in nonrenewable natural gas, which are not present in renewable natural gas (RNG),&rdquo; says Sean Mezei, principal with Dekany Consulting Inc. and co-chair of ABC&rsquo;s RNG working group. &ldquo;The ABC also appreciates the CPUC&rsquo;s proposal to offset some of these [interconnection] costs, but the limit of $1.5 million per connection, and the uncertainty of this offset being available when the pipeline connection is constructed, has our membership generally expecting this offset program to be insufficient to change the fact that zero RNG-to-pipeline projects have been installed since AB 1900 was implemented in California.&rdquo;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; Matt Schmitt, business development director for Colony Energy Partners Tulare LLC, says pipeline injection is a better route for his biogas project than electrical generation. Phase one of Colony Energy Partner&rsquo;s multifeedstock hybrid project entails procuring 500 MMBtu per day of gas from the Tulare wastewater treatment facility and producing 500 MMBtu of biogas from 200 to 300 tons a day of dairy manure and other agriculture and food processing wastes. The gases will be conditioned on-site and then injected into the pipeline grid. The project received $5 million from the California Energy Commission renewable transportation fuel funds, $3 million from the solid waste authority and $500,000 from the air district. &ldquo;The key with getting these grants is that your project must support GHG reductions, and you must have your permits before applying,&rdquo; Schmitt says, adding that permitting takes time and money. &ldquo;It&rsquo;s been rather simple for us, we haven&rsquo;t made it complicated by putting a digester on dairy with all of the regulations on water discharge&mdash;we avoided that nightmare. We&rsquo;re just going into sewer so there are no issues with regard to the water quality board.&rdquo; Black says California requires double-lined lagoons, a much higher standard than elsewhere, and that adds to the costs. Schmitt says with all of the grid interconnection regulations in the electricity market, his project would be &ldquo;bogged down for years.&rdquo; SoCal gas interconnection, CEQA conditional use, air and solid waste permits were all &ldquo;straight forward,&rdquo; Schmitt adds. For dairy projects intending to produce electricity for the grid, SB 1122 requires California&rsquo;s three investor-owned utilities (IOUs) to purchase 250 MW of bioenergy-based electricity from 3-MW or smaller distributed energy projects, with 90 MW set aside (in category two) for agriculture and dairy biomass and biogas projects. Projects classified as &ldquo;dairy&rdquo; must be 100 percent dairy manure, while ag waste biogas projects may have up to 20 percent waste from other categories (i.e., urban or forest wastes). The regulations developed to implement SB 1122 are complicated and imperfect. The ABC and the Bioenergy Association of California held a joint webinar May 14 titled &ldquo;California&rsquo;s New Bioenergy Program Set to Launch This Summer.&rdquo; Christa Darlington, special counsel with the Placer County Air Pollution Control District, presented and identified key requirements to participate in the program. &ldquo;There are a few things CPUC asks you to show,&rdquo; she said. &ldquo;One is whether interconnection is possible for your facility.&rdquo; Darlington said projects are required to have a system impact study and be strategically located, and transmission-level upgrade costs must be below $300,000. &ldquo;If upgrade costs are above that, the project will have to pay it down,&rdquo; she said. &ldquo;So it&rsquo;s not a project development barrier, it&rsquo;s just a pay-down requirement.&rdquo; The project must also show that its team has experience, &ldquo;a low bar to prove,&rdquo; Darlington said. The project must also demonstrate the facility can comply with requirements, such as having 100 percent site control and an effective capacity of no more than 3-MW electricity production. The facility must be certified as RPS-eligible, qualify under the Federal Energy Regulatory Commission, have commenced operations on or after June 1, 2013, and be online within 30 months of an execution of a power purchase agreement (PPA). The pricing mechanism is &ldquo;one of the more complicated pieces of the program,&rdquo; Darlington said. The first auction is expected this fall, and every six days there&rsquo;s a potential for new auction and, at that time, a review of what happened at the previous auction will be performed to determine a new price. The price starts at $127.72 per megawatt hour and may go up as high as the $197 cap. The price moves at increments of $4, then $8, and then $12 thereafter. The minimum number of bidders in a specific category is initially three, then after the first bidder strikes at a price there must be at least five projects in the queue before the price will start to move again for that category. The price will rise if less than 20 percent of the MW available per category is allocated. Then the price remains static for the next auction, and then the prices will rise at the following auction. Black says the concern is that it&rsquo;s expensive to get into the queue, and a higher price is needed to attract projects, but the price doesn&rsquo;t go up until a sufficient number of projects are involved. &ldquo;That&rsquo;s an example of the complexity,&rdquo; Black says, adding that, while this may work well for solar, it may be problematic for biogas. The IOUs had input in drafting the regulations for SB 1122, and they intentionally made the process &ldquo;as cumbersome as possible,&rdquo; Boccadoro says. &ldquo;They are using it as an obstacle to getting these projects built.&rdquo; Peter Brown, president of FFA Fuels, a company selling biodiesel processors and biogas digesters in cooperation with Polygen, says &ldquo;Petroleum companies and the utilities are very powerful here,&rdquo; and says that it&rsquo;s no surprise that SB 1122 regulations are this burdensome, complex and discouraging for biogas projects. &ldquo;I think SB 1122 is about people trying to make believe they&rsquo;re moving on something that they haven&rsquo;t budged on in 50 years,&rdquo; Brown says. &ldquo;It&rsquo;s an unholy combination of regulators banking on businesses banking on individuals from keeping this from happening.&rdquo; The utilities &ldquo;don&rsquo;t love this program,&rdquo; Black says. &ldquo;It&rsquo;s a small program for them that takes a lot of time, and these projects take a lot of money.&rdquo; He says the bioenergy community is waiting to hear how PUC implements these regulations, particularly on important issues such as inflation adjustment. &ldquo;The way this is structured, it could take a very long time to get to the price that&rsquo;s needed,&rdquo; Black says. &ldquo;That&rsquo;s why the grant side is so important when they&rsquo;re taking a price at the low end of SB 1122.&rdquo; Brandon Moffatt, Harvest Energy Inc.'s senior vice president of energy,&nbsp;presented on the ABC-BAC webinar and said a core issue in implementation of SB 1122 is what to do with attributes from fuel diversion. He said the utilities have proposed a definition that could be interpreted in favor of them taking fuel diversion as well as electricity generation credits. &ldquo;We reject this,&rdquo; he said. &ldquo;BAC and others objected that this approach is inconsistent with prior CPUC and legislative intent. The green attributes issue is complex and needs updating from prior commission rulings.&rdquo; He said a CPUC workshop to clarify this is likely. Despite a complicated regulatory environment that simultaneously promotes and discourages bioenergy production in California, two dairy digester projects under control of the American Biogas Energy Co., which is part of CalBio, are moving forward and have recently received grant funding: Lakeview Farms Dairy, Bakersfield and West Star North Dairies, Buttonwillow. Lakeview Farms Dairy received $4 million to install and demonstrate a covered lagoon digester that converts dairy manure into biogas to generate renewable electricity and to prepare a 1-MW generator platform capable of being expanded by using biogas from neighboring dairies. This would be the state&rsquo;s first genuine dairy cluster, what many believe is a long time coming. Another project in that cluster is Carlos Echeverria &amp; Sons as well as CalBio&rsquo;s existing 2 -W Old River project. &ldquo;What&rsquo;s unique and important about Lakeview is that we&rsquo;re planning to build a 1-MW dairy digester, but the platform for that will be designed to add a second or third MW from neighboring dairies if and when we build dairy digesters in those,&rdquo; Black says. &ldquo;We&rsquo;re trying to develop economies of scale both in capital expenses and in ongoing operations and management expenses. We&rsquo;re delighted to have the large Old River project up and running, and to have received funding for two new projects in this cluster.&rdquo; Regulations in California are tougher than in other states because of its unique issues: nonattainment zones from dense human populations and associated vehicle and power plant emissions along the coastal regions, juxtaposed with nonattainment zones from multiple sources, including the dense dairy population in the Central Valley. Black says all-in-all, the regulatory environment is improving for dairy digester development in California. &ldquo;I think the regulatory community is filled with very smart, hard-working public servants trying to address two important issues,&rdquo; he says. &ldquo;That&rsquo;s how to develop projects that protect the environment, and help this industry get created. And those are the right two things to be doing. We are hopeful the CPUC helps adjust SB 1122 since a successful program is a very important next step. Ideally the utilities, which helped on our independent projects, will come onboard, too.&rdquo; Author: Ron Kotrba Senior Editor, Biomass Magazine 218-745-8347 rkotrba@bbiinternational.com

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THE FEW, THE PROUD: CalBio's Old River dairy lagoon digester project is part of the state's first burgeoning cluster that will supply biogas to a centralized location for conditioning and electricity generation. 

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The Golden State has borderline personality disorder regarding promotion and discouragement of dairy biogas projects. 

Udder Confusion: Dairy Digester Development in California

In May, the number of states in the U.S. with mandatory renewable portfolio standards (RPSs) jumped to 30, plus Washington, D.C., finally surpassing the stagnant 29 that had gone unchanged for years. It didn&rsquo;t last long, however, as the signing of a new bill in Kansas in late May switched its program from law to voluntary. Perhaps more this year than any other, state legislation has proposed to kill, weaken or freeze state RPS programs. Though most bills haven&rsquo;t and likely won&rsquo;t make much progress, arguments from RPS supporters and adversaries are in stark contrast, often leaving the general public confused about the mission and effect of their state&rsquo;s RPS&ndash;&ndash;in particular, the costs passed on to ratepayers. The truth is that the real impact of an RPS is difficult to determine, according to Warren Leon, executive director of the Clean Energy States Alliance. &ldquo;It&rsquo;s not so easy to identify the costs and benefits of an RPS because of its indirect effect on the electricity system and electricity prices,&rdquo; he says. &ldquo;It&rsquo;s hard to track all of the economic impacts, and unless you do a thorough study, you don&rsquo;t know for sure.&rdquo; &nbsp;The best studies that have been done suggest that, in most places, the cost of RPSs have been quite modest, Leon says. &ldquo;There are some places where the RPS has led to lower electricity costs; most have led to slightly higher. But the question is whether some of the other benefits that have come with that&mdash;such as local jobs, building and maintaining renewable energy facilities&mdash;counter the balance of slightly higher electricity costs, which have actually been quite small.&rdquo; While some states are juggling legislation that would negatively impact their RPSs, others have realized positive implications and are going in the opposite direction by increasing goals and broadening qualifying technologies. Renewable thermal, in particular. &ldquo;Beyond trends of strengthening or weakening [RPSs], adding thermal does seem to be real. It&rsquo;s happened in New Hampshire and Massachusetts, and other states such as Maryland are considering it,&rdquo; Leon says. Leon references a paper released by CESA in late April, which reports that a handful of states have granted credit to various renewable thermal technologies under their RPS programs. Seven provide at least partial credit to all kinds or specific renewable heat technologies, but only New Hampshire and Massachusetts offer full credit, and New Hampshire is the only state that requires a portion of its RPS to be derived from thermal energy. New Hampshire Model &ldquo;New Hampshire was the first to do it, and do it properly,&rdquo; says Adam Sherman, executive director of the Biomass Energy Resource Center.&nbsp; Massachusetts followed by passing a thermal inclusion bill in the 2014 legislative session, he adds, and Vermont&mdash;where BERC is located&mdash;just retooled an energy bill titled RESET that creates a three-tied RPS with a thermal component, and includes biomass heat technologies. &ldquo;It [adding thermal] is interesting because, on one hand, it&rsquo;s a great way to take an unregulated portion of the energy market and create incentives and market mechanisms that catalyze market adoption of these technologies,&rdquo; Sherman says. &ldquo;But, on the other hand, it&rsquo;s oftentimes taking electric generation revenue or policy mechanisms, or applying regulations in the electric sector, to try to incentivize the thermal sector.&rdquo; Sherman notes that many people support inclusion of thermal in the RPS, but there are some who see it as a &ldquo;robbing Peter to pay Paul approach. In theory, the way to do prothermal policy would be to apply it somehow to heating fuels, but there is not a lot of political support for taxing fossil fuels&mdash; especially heating fuels&mdash;because they see it as a regressive tax, and no one wants to make it even harder for Mrs. Smith, who is struggling to stay warm in the winter, by driving up the cost of heating fuels to fund weatherization, thermal efficiency and renewables.&rdquo; Sherman points out that in some cases, the generation of a thermal renewable energy credit (REC) can be done at a lower cost per credit than an electrical-derived one. &ldquo;Thermal energy is 300 percent more efficient than burning wood to produce a megawatt-hour of electric energy,&rdquo; he says. &ldquo;Because of that efficiency factor, it could generate a REC to be purchased by a utility for a lower price per MWh. That&rsquo;s really what got the New Hampshire utilities behind the initiative [to add thermal to the RPS], because it gave them flexibility and more options to cost-effectively acquire those RECs needed to meet RPS requirements.&rdquo; Adding thermal smartly is no simple task. After New Hampshire passed its bill in 2012, it took over two years to write the rules and implement it, according to Charlie Niebling of Innovative Natural Resource Solutions, who played a significant role in getting heat included. &ldquo;They began allowing projects to qualify at the beginning of 2014. There were a few who took advantage of it&mdash;it applies to any projects that meet the technical requirements and came online after Jan. 1 2013. We&rsquo;re really just only now starting to see projects coming forward and being developed with the full intent of utilizing and taking advantage of the incentives.&rdquo; Niebling admits that enthusiasm has been tempered somewhat by the dramatic decline in oil and propane pricing. &ldquo;The business of advanced modern wood heating is really a function of what alternative fossil fuel heating oil prices are doing, and they&rsquo;ve come down dramatically. The pace of project development has slowed, but it would be much worse without the existence of the thermal incentive.&rdquo; That&rsquo;s soon to change in New Hampshire, he points out, as the U.S. Endowment for Forestry and Communities has committed a chunk of money to the state, which it will use to help finance biomass thermal projects specifically. Dubbed &ldquo;T-RECs,&rdquo; Niebling explains that since RPS programs provide a performance incentive, one doesn&rsquo;t generate a revenue stream until he is operating. &ldquo;You can&rsquo;t take the fact that you might get RECs in the future to a bank. It&rsquo;s all a function of the market, and there is a lot of risk associated with RPS markets and policy.&rdquo; Under T-RECs, once a REC purchase price is negotiated, the project is awarded a one-time, upfront lump sum payment&mdash;15 to 20 percent of its capital cost. Once the RECs are generated, ownership is transferred to the endowment. &ldquo;The beauty of this is it takes a performance incentive and turns into a source of capital that can be used by a project to get built,&rdquo; Niebling says, adding that the hope is the program could be launched in other states when thermal provisions are added. Following New Hampshire&rsquo;s lead, Massachusetts passed SB 1970 in summer of 2014, and its Department of Energy and Natural Resources immediately went to work drafting the rules. Massachusetts and More &ldquo;It [implementing the program] will likely be much quicker than in New Hampshire,&rdquo; Niebling says. The estimated value of the incentive, which was added to the states Alternative Compliance Standard, is a remarkable $800 million over the next 15 to 20 years. &ldquo;It&rsquo;s a huge play, and it&rsquo;s getting a lot of attention. The rules are expected to be completed this summer, so we may see a draft out very soon.&rdquo; The program in Massachusetts has a few more strings attached than in New Hampshire, Niebling points out, including a sustainable biomass component to it that has to be met by any project that takes advantage of the credits. And similar to what the endowment has done in New Hampshire, the state will assist smaller projects in getting built. &ldquo;They will estimate what the heat output for a project will be over 10 years,&rdquo; says Niebling. &ldquo;Then, in lieu of selling credits as your system is operating, they will pay you a that sum upfront to use help finance the installation.&rdquo; The provision is applicable only for smaller projects under 100 kilowatts, or 340,000 Btu. &ldquo;So basically, home homeowners and small commercial projects will be able to take advantage of this very novel approach,&rdquo; Niebling says. &ldquo;It&rsquo;s unique in terms of the way RPS programs are implemented around the country, and it&rsquo;s worthy of some note. The administrative costs of enrolling, complying in these programs&mdash;and the paperwork and recordkeeping, it&rsquo;s too heavy a lift for a little guy. For a bigger guy with in-house expertise, like a big school system installation or hospital, they have the capacity, and revenue generation is sufficient to justify the cost to participate&mdash;and there are costs.&rdquo; The major cost is a meter, which runs anywhere from $4,000 to $7,000 for a typical hot water installation, and more for steam. &nbsp;Besides New Hampshire, Vermont and Massachusetts, several other states, including Maine, New York, and Maryland, have dabbled in adding renewable thermal technologies to their state energy plans. Regardless of the route a state chooses, Leon notes that an important point is that every RPS is different, and there is no one-size-fits-all. &ldquo;RECs vary widely from one state to another, as do the ways utilities meet the mandate, the array of technologies, and the [program] priorities,&nbsp; so you just have to adapt this concept to each state individually,&rdquo; he says. &ldquo;You can&rsquo;t just put out a model legislation and expect every state to run with it, it doesn&rsquo;t work that way.&rdquo; And while it may be difficult to determine the overall impact of an RPS, spending a little more each year on renewable energy could prove to be a wise investment. &ldquo;Ratepayers have faced an increasingly volatile economy,&rdquo; Sherman says. &ldquo;Paying a little bit more now is probably a wise hedge against 20 years down the line.&rdquo; While the number of states with an RPS is very likely to sit at or very near 29 for the long term, legislation for a federal RPS has recently been introduced, but it certainly isn&rsquo;t the first time. The idea of a nationwide mandate may sound good, but could be extremely difficult to implement. &ldquo;I think it&rsquo;s unrealistic,&rdquo; Niebling says. &ldquo;Setting aside the politics of who runs Congress, the energy markets and electric energy policy in this country vary so widely from one part of the country to another, a comprehensive RES seems like a utopian notion.&rdquo; Leon agrees. &ldquo;Theoretically, it would be desirable to have both a federal RPS and state RPS&mdash;the federal [standard] could create some national standards and keep the whole country moving toward renewables,&rdquo; he says. &ldquo;But the virtue of the state RPSs, is that different states have different needs and interests. Some technologies make sense in one state but don&rsquo;t make sense in another, and one of the virtues of a state RPS is that the state can tailor it to its needs. We see a lot of variety among states, and that&rsquo;s been a good thing, because it allows them to implement policies that serve their own purposes. You wouldn&rsquo;t want to replace state policies with a national one, they would have to work hand in hand.&rdquo; It all boils down to the state and how the RPS is created, Niebling adds. &ldquo;I long for the day that our government stops incentivizing or subsidizing any kind of energy, and everything can compete on a level playing field, but the fact is we compete in a marketplace that is heavily influenced and dominated by fossil fuel subsidy. It takes multiple shapes and forms, and that&rsquo;s a reality that is not going away any time soon. The oil, gas, coal lobby is extremely powerful. We&rsquo;re right to ask for some equivalent measure of treatment in what we do.&rdquo; Author: Anna Simet Managing Editor, Biomass Magazine asimet@bbiinternational.com 701-738-4961

While 29 states and Washington, D.C., have mandatory renewable portfolio standards, only two provide full credit to renewable thermal. However, more states are evaluating adding heat to their qualifying technologies and at least providing partial cre

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While some states are juggling attempts to freeze, lower or dismantle state renewable portfolio standards, others are strengthening and fine-tuning them.

July 2015

Business Briefs

Business Briefs

Columns

Omission of Wood Heat Goes Too Far

California Biomass Support Sets Good Example

The Inevitable Battle

Thermal Incentives Heat Up

A Look at EPA's RVO Proposal

Featured

Readying for a Regulatory Landing

Udder Confusion: Dairy Digester Development in California

Contributions

Regulation of Europe-Bound US Wood Pellets

Departments

Crunching the Numbers

Thermal Reinforcement

July 2015.css-7jxktu{position:absolute;bottom:0px;left:0px;right:0px;height:3px;border-radius:3px;background-color:var(--chakra-colors-brandBlack);}

Business Briefs

Business Briefs

Columns

Omission of Wood Heat Goes Too Far

California Biomass Support Sets Good Example

The Inevitable Battle

Thermal Incentives Heat Up

A Look at EPA's RVO Proposal

Featured

Readying for a Regulatory Landing

Udder Confusion: Dairy Digester Development in California

Contributions

Regulation of Europe-Bound US Wood Pellets

Departments

Crunching the Numbers

Thermal Reinforcement

July 2015