With both a comparable price and the ability to be handled just like coal, as well as resistance to weather-related degradation, paper pellet biomass fuel was the only choice for Manitowoc Public Utilities, a small Wisconsin electricity provider.
 The ratepayer-owned utility is located in the small city of Manitowoc on the eastern border Wisconsin shares with Lake Michigan. MPU serves about 16,000 customers and cofires around 15 percent paper biomass pellets with petroleum coke and coal in the circulating fluidized bed boilers employed at its main power plant on Columbus Street, according to MPU&rsquo;s Power Production Manager Red Jones.&nbsp;
 &ldquo;The paper pellets have been great for us because they help us handle wet fuel,&rdquo; he says. &ldquo;When our petroleum coke gets wet, one of the things that makes it a lot easier for us is to put quite a bit of paper pellets in at that time. Not only does it tend to suck up some of the moisture, but it literally makes the product flow better so we have a lot less bridging and blockages.&rdquo;
 Because of a Wisconsin incineration rule, MPU is not allowed to use more than 30 percent biomass in its fuel mixture. Still, cofiring paper pellets almost completely meets the utility&rsquo;s obligations under the Midwest Renewable Energy Trading System. &ldquo;We end up satisfying our renewable energy quotas using this and other sources as well, most of that being purchased,&rdquo; Jones says, adding that the percentage of biomass burned depends completely on the supply.
 Fortunately, MPU is in Wisconsin, where a once-booming paper product industry set the stage for an industrial paper waste biomass sector.
 Paper Pushers
 &ldquo;We&rsquo;re in what&rsquo;s called the &lsquo;paper valley&rsquo; here,&rdquo; says Lee Robbert, founder and owner of Pellet America, an Appleton, Wis.-based paper pellet manufacturer. Well, technically Appleton is in Fox Valley, categorized by its position along the Fox River, but the region used to be packed with paper companies, now only boasting about half what it once did, according to Robbert. In fact, Pellet America says Wisconsin fostered the start of the paper pellet industry, beginning with a paper company looking for a way to successfully burn its waste paper for fuel.
 The use of the fuel has spread since its invention and other paper pellet manufacturers do exist in the U.S., but Robbert says making a profit and finding customers can be a challenge. Still, Pellet America thrives, producing up to 1,000 tons of paper pellets per week from 1,000 tons of industrial scrap material. That includes waste from paper companies, printing companies, converting companies and label makers, among others.
 And it&rsquo;s not the only paper pellet manufacturer in the state. Greenwood Fuels LLC in Green Bay produces 200 tons of pellets per day and is in the process of ramping up to 400 tons per day, according to Ted Hansen, director of operations for Greenwood. The mill just started up in January but business is going so well that the company is looking to build another mill in Ohio, where it is currently sending some pellets for testing, Hansen says. &ldquo;We&rsquo;re very eager to expand.&rdquo;
 Feedstock for Greenwood&rsquo;s pellets is comprised of about one-third each of paper, label material and poly-coated flexible film waste. &ldquo;We&rsquo;re open to anything that&rsquo;s classified as an industrial waste,&rdquo; Hansen says. The company uses no post-consumer waste, allowing the fuel to qualify as a renewable fuel in the state of Wisconsin. &ldquo;Anyone who burns our pellets is not considered to be an incinerator,&rdquo; he says.
 All the feedstock Greenwood uses is nonrecyclable and would otherwise end up in a landfill. It consists of cellulose, plastics, adhesives and a few other trace clean-burning materials, Hansen says, but mostly polypropylene, polyethylene, polyester, nylon, paper and adhesives from items such as labels. &ldquo;The U.S. is obsessed with labels,&rdquo; he laughs. All the materials coming in are currently dry, but Greenwood is experimenting with a drying process to expand feedstock capabilities. &ldquo;Similar to woody biomass, we&rsquo;ll have a drying operation to allow us to take more of those wet materials,&rdquo; Hansen says.
In fact, the process for pelletizing paper is much the same as that for pelletizing wood, both Hansen and Robbert say. &ldquo;It&rsquo;s fairly simple,&rdquo; Hansen adds, explaining how it begins with sorting of the materials. &ldquo;We tend to sort them by fiber content, plastic content, moisture content and adhesive content,&rdquo; Hansen says. Then, the sorted material is mixed and chopped, mixed and chopped again, and then pelletized in a mill identical to that of a wood pellet plant. The fresh pellets are then put through a cooler and shaker to get rid of fines, and then stored in silos, he explains.
 The fundamental difference between wood and paper pelletization, as can be deduced from an explanation of the process, is the fact that wood pellets generally are made with a more homogenous feedstock selection. &ldquo;Whereas we&rsquo;re dealing with a lot of material that has extreme swings in density,&rdquo; Hansen explains. That wide array of feedstocks makes the mixing and sorting a fundamental aspect of the manufacturing process.
 Both Greenwood Fuels and Pellet America provide paper pellets for companies cofiring with either coal or other forms of biomass, and mostly in Wisconsin. Their customer base includes paper mills and the state of Wisconsin, which cofires the pellets at universities and a prison. They both also provide pellets to MPU.
 Paper Pellet Properties
 MPU has cofired paper pellets in its boilers since before Jones was employed there 12 years ago. &ldquo;We have been offered wood pellets in the past, but they really haven&rsquo;t been price competitive,&rdquo; he says. Robbert insists the price of paper pellets is one direct benefit and a main lure for customers. &ldquo;You have to fit in the niche of cheaper than coal to get anybody&rsquo;s interest,&rdquo; he says. He adds that Pellet America&rsquo;s product has little sulfur. &ldquo;That makes them a little more attractive,&rdquo; he says. Coal has a fair amount of sulfur and since paper doesn&rsquo;t, boiler operators can blend the cheap, low-sulfur paper pellets to offset the coal&rsquo;s sulfur emissions, he says. With new technologies, though, sulfur is less of an issue than it was when Pellet America got its start in the early &rsquo;90s. Hansen would add that the paper pellets bring a reduction in nitrogen oxide, as well, and sometimes even in hydrogen chloride. As with all power-producing feedstocks, Btu value is always a crucial factor. Hansen says in its mixing process, Greenwood Fuels aims for 11,000 Btu per pound, comparable to most coal products.
 And of course, a determining factor when choosing a feedstock to cofire is its ability to handle and store similar to its fellow fuel. It sounds like there are no problems in that arena, either. The densified paper fuel handles almost identically to coal in most moving grate boilers, Hansen says, adding that he has no customers consistently burning in a pulverized coal boiler. But it would be possible, he believes, to cofire a 5 to 10 percent mixture in a pulverized boiler. &ldquo;Can pulverized coal burn paper?&rdquo; Jones offers. &ldquo;Certainly, there is a way to make it happen, but you&rsquo;re going to have to overcome a couple hurdles with that I think.&rdquo; Other boilers can handle up to 30 percent blends with no equipment tailoring. &ldquo;Basically, the whole process is to try to make a pellet that handles the same as coal,&rdquo; Robbert says.
 MPU stores its paper pellets outdoors and while a small amount of degradation does occur from the elements, Jones says it&rsquo;s not significant. &ldquo;Even with really heavy rain, the paper pellets usually hold up pretty well.&rdquo;
 And an added benefit is the fact that paper doesn&rsquo;t emit any foul odors. &ldquo;We are right below a high school, and so they could literally hit us with an orange juice carton, and often do,&rdquo; Jones says, adding that the school has had no odor complaints. &ldquo;The paper pellets don&rsquo;t smell.&rdquo;
 The size of the paper pellets MPU accepts varies, but only slightly. Pellet America provides a three-quarter-inch pellet, which blends well with Greenwood Fuels&rsquo; one-half-inch pellet, Jones explains. MPU has a special blending pit for the paper pellets, but has run them through the normal coal-processing stream as well. The size requirement for MPU is three-quarter-inch minus, putting the utility in what Jones calls &ldquo;the sweet spot&rdquo; with regard to paper pellets.
 Endless Possibilities 
 With so many benefits, it can be a little difficult to come up with explanations why more utilities, paper mills and universities aren&rsquo;t cofiring biomass, whether it&rsquo;s made from paper waste or wood. Jones offers proximity to suppliers as a possible reason, but leans on pricing as the biggest hurdle. &ldquo;The only other thing I could see is if you&rsquo;ve got a pulverized coal unit, [paper pellets] are not going to grind like coal,&rdquo; he says. &ldquo;It tends to be more flexible and it&rsquo;s not really going to break up like that.&rdquo; The paper pellets are better suited for stoker or circulating fluidized bed boilers, he suggests, where fuel sizing is much more coarse.
 &ldquo;When we first started in &rsquo;92, we thought we had the next best thing to sliced bread,&rdquo; Robbert says. But to even test burn a biomass product in a fossil fuel-fired boiler, a modification to the existing permit is required and can be a nightmare. &ldquo;Nobody wants to deal with that,&rdquo; he says. In addition, confusion arises over what the difference is between burning a manufactured industrial paper waste pellet and burning garbage. &ldquo;And the difference, of course, is the fact that we&rsquo;re monitoring everything that goes in, whereas they couldn&rsquo;t do that with garbage,&rdquo; Robbert explains.
 The paper pellets manufactured at mills like Greenwood and Pellet America offer a way to get power plants &ldquo;off the starting blocks,&rdquo; Hansen says, particularly if they want to reduce technical or economic risks in their cofiring endeavors. &ldquo;I look at us as a bridge technology,&rdquo; he says. &ldquo;In many cases, we&rsquo;re the first step that a customer takes to start moving away from burning coal.&rdquo; The paper fuel also is a good option for boilers burning wet biomass, as the pellets make igniting easier, thereby improving boiler operation.
 &ldquo;We don&rsquo;t really look at our materials as being better or worse than others,&rdquo; Hansen concludes. &ldquo;It&rsquo;s just another technology that sometimes bridges the gap between the customer being able to start moving away from coal, or burning wet biomass.&rdquo; Author: Lisa Gibson Associate Editor, Biomass Power &amp; Thermal (701) 738-4952 <a href="mailto:lgibson@bbiinternational.com">lgibson@bbiinternational.com</a>

ROLLS OF RAW MATERIAL: Greenwood's pellets are made from paper, label material and poly-coated flexible film waste.


2011/08/13141131579316.jpg

FEEDING THE FIRE: Greenwood sells its product for use in cofiring with coal and other biomass. 

2011/08/13141132099924.jpg

A MOVING EXPERIENCE: The production of paper pellets is much the same as that of wood pellets, including the conveyance systems. 

2011/08/13141134418694.jpg

PELLET PRODUCTION: Greenwood is increasing production from 200 to 400 tons of pellets per day. 

2011/08/13141134678365.jpg

IDENTICAL EQUIPMENT: The mixing and sorting processes are the only fundamental differences between production of pellets from wood and from paper. 

2011/08/1314113507704.jpg

PAPER POWER: Greenwood sells its paper pellets to utilities, universities and paper mills. 

2011/08/13141135440063.jpg

Despite a decline in its paper product sector, Wisconsin holds 
the reins to an industry that shows enormous potential for cofiring with 
fossil fuels: pellets made from industrial paper waste. 

Paper Pellets 

Over the past few years, many small torrefaction technology companies have popped up across the U.S. While some have made progress, others have disappeared as quickly as they started.
While the science behind torrefaction is not in question, it seems there are two major roadblocks for most companies trying to economically produce a product that will serve as a cofired or stand-alone fuel&mdash;overcoming the confusion surrounding the economics of torrefaction, and coming up with the cash to prove their process on a meaningful scale.
 In Europe, where coal/biomass cofiring is common and carbon reduction incentives are enticing, large-scale torrefaction plants are being built. That&rsquo;s a different scenario than in the U.S., where small start-up companies are mostly working on pilot- and demonstration-scale units.
 Dutch clean tech company Topell Energy recently completed what it believes is the largest torrefaction plant in the world, a 60,000-ton facility now operating in the Netherlands. While Topell has plenty of European customers, the company believes there is great potential outside of the country, particularly in North America. But, as Robin Post van der Burg, director of business development at Topell, points out, considerable confusion still surrounds the mass and energy balance of torrefaction.
 &ldquo;People looking at torrefaction will find that there isn&rsquo;t a lot of credible information out there,&rdquo; he says. When evaluating mass and energy balances, there are three things that need to be looked at, according to van der Burg. The first is the thermal balance, or how much thermal energy comes out of a forest versus what comes out of the torrefaction process. &ldquo;There&rsquo;s a general understanding that you lose 20 percent of the bone-dry biomass, and that you also lose 20 percent of the thermal value, but that isn&rsquo;t the case,&rdquo; he says. &ldquo;You have a 95 percent-plus thermal efficiency, and this is due to the nonlinear relationship between the moisture value and the heating value when you dry off the water. Beginning with 50 percent moisture, 5,000 Btu per pound, you would expect that it would go to 9,000 Btu at 0 percent moisture, but you actually get 10,000 Btu. There&rsquo;s a bonus from driving off moisture, and that&rsquo;s why the thermal efficiency of this process is so high.&rdquo;
 Hiroshi Morihara, CEO of Oregon-based torrefaction technology developer HM3 Energy Inc., says what makes up for lost energy, depends on how one looks at it&mdash;whether the energy content is reduced or increased.&nbsp; &ldquo;When you torrefy, 10 percent of the wood energy will vaporize,&rdquo; he explains. That 10 percent of energy has 30 percent of the mass of the wood, but the heat is used to dry the incoming feedstock that is normally 40 to 50 percent moisture, so that helps with the cost of the process. Though you lose 30 percent of the mass and 10 percent of the energy, the product we produce is about 20 percent more energy intense than regular wood pellets, and compared to Western coal, the heating value is very similar, about 10,000 Btu per pound.&rdquo;
 He adds that coal typically has about 25 percent moisture, which must be vaporized and requires energy. &ldquo;That&rsquo;s not the case with our product, so we have 20 percent more net energy on a per pound basis.&rdquo;
 The second thing to consider in torrefaction economics is the power balance, or how much energy is needed to convert biomass into biocoal. &ldquo;This is a function of your reactor technology,&rdquo; van der Burg explains. &ldquo;In our case, it&rsquo;s only 2 to 2.5 percent of the total energy output. In other words, if 1 ton of product has 6 megawatts (MW) of thermal output capacity, we use only about 150 kilowatts to produce that, or even less. Only 2 to 2.5 percent is lost in power needed for the process.&rdquo;
 The third important factor is the life-cycle analysis, or the total amount of CO2 emitted in the whole production process, including the diesel used in the chipping process, trucks that bring the biomass to the plant, power consumed in the plant and fuel when shipped. &ldquo;If you take that into account, it&rsquo;s in the same league as wind and solar,&rdquo; van der Burg says. &ldquo;We meet the same sustainability standards, but it&rsquo;s a way cheaper solution and it&rsquo;s baseload. That&rsquo;s why in the EU, more and more companies are starting to understand that in the next decade biomass will be the major contributor in&nbsp; building up sustainable energy, and not so much wind and solar.&rdquo;
 Outside of the mass and energy balances, power producers that utilize coal look at torrefied biomass for its attractive physical properties. These include power utilities, but also smaller institutions such as universities.
 Coal&rsquo;s Match &hellip; MIA?&nbsp; 
 The University of North Carolina has a goal of phasing out coal by 2020 and for the past couple of years has been searching for the cleanest, most cost-effective replacement. While wood pellet test burns have been conducted&mdash;results of which are still pending&mdash;UNC has also considered torrefied pellets. &ldquo;The attractions are a high heat density&mdash;similar to that of coal&mdash;and the physical property of being hydrophobic so it can be shipped in open containers and stored outside,&rdquo; says Ray DuBose, UNC director of energy services. &ldquo;We&rsquo;re looking for something that will flow through our existing systems.&rdquo; The energy plant at UNC was built in 1991, so it&rsquo;s relatively young for a coal-fired plant. &ldquo;There&rsquo;s a lot of life left in the existing equipment, and torrefied biomass would allow us to avoid retrofit costs,&rdquo; DuBose says.
 The initial problem associated with torrefied biomass experimentation has been securing a supply. &ldquo;We&rsquo;ve bid it twice now, and we&rsquo;re still reviewing bids from the second round, but it doesn&rsquo;t appear that anyone [in the U.S.] is producing torrefied wood on a regular basis,&rdquo; DuBose says. &ldquo;We&rsquo;ve been contacted by a number of companies, but we can&rsquo;t find anyone who has a regular supply.&rdquo;
 The Tennessee Valley Authority&mdash;a government-owned power utility&mdash;has been conducting biomass/coal cofiring tests for the past several decades, and also has an interest in torrefied pellets. Unfortunately, it has run into the same problem as UNC. &ldquo;There doesn&rsquo;t seem to be enough material, or supply,&rdquo; says Daryl Williams, head of renewable energy at TVA. &ldquo;We needed a couple thousand tons for test burns at our plant in north Alabama, and we had a few vendors promising that, but when it came down to it they couldn&rsquo;t provide it.&rdquo;
 While TVA has put biomass testing on hold until regulatory uncertainties become clear, Williams says he expects that torrefied wood pellets would require no real changes to existing materials handling and storage when comilled with coal. &ldquo;We have received samples of a number of different products, done some lab-scale analysis and compared it to green biomass, and it does have advantages,&rdquo; he says. &ldquo;It looks and feels like coal as far as the pulverizer is concerned, and it&rsquo;s hydrophobic, so we&rsquo;ll have no problems with insects or rot when it&rsquo;s stored. One concern we have is cost, but like any new technology, the more advanced it becomes the lower the cost. We&rsquo;re really curious to see how it will handle and combust at a cofired plant.&rdquo;
 Morihara says the reason for the lack of production in the U.S. is that the technology only found its way to the country a few years ago. &ldquo;It&rsquo;s a very new concept here, and those working here in the U.S. are small companies.&nbsp; As a result, they&rsquo;re having a difficult time getting enough money to build commercial plants, whereas in Europe, there are companies that are fairly large and have money to build commercial plants, so they&rsquo;re already doing it.&rdquo;&nbsp;
 HM3 appears to be farther along in development than other U.S. torrefaction companies. It is building a demonstration facility in Troutdale, Ore., has plans for a commercial-scale plant in Prineville, Ore., and has obtained multiple federal grants to help.
 Moving beyond coal, Morihara points out that torrefied biomass is capable of things that traditional wood pellets aren&rsquo;t&mdash;including being pulverized and blown into the furnaces of coal-fired power plants.
 Why Not Wood? 
 &ldquo;If you have a 500-MW plant, to retrofit it to also use wood pellets would cost about $300 million,&rdquo; Morihara says. &ldquo;If you use torrefied biomass, there is no retrofitting cost. For its Btu content, torrefied biomass may cost 20 percent more, but it has 20 percent more energy so the cost is actually very similar.&rdquo;&nbsp;
 Van der Burg agrees there isn&rsquo;t much difference between wood pellets and torrefied biomass. &ldquo;Torrefied pellets come cheaper per metric ton, but you get paid for wood pellets and torrefied wood pellets per gigajoule, so considering the 25 to 30 percent higher energy density a torrefied wood pellet has over a regular wood pellet, you see the cost comparison.&rdquo;
 &nbsp;In a typical case in the Southeast U.S., considering the whole integrated value chain of the product, van der Burg says wood baskets/assets/fiber baskets that were previously considered idle because they were difficult to get at will become economical because of the enormous reduction in transport costs and substantial increase in energy density. &ldquo;Transport costs will become much lower than they are for wood pellets, and incomparable for untreated biomass,&rdquo; he says. &ldquo;Torrefied wood pellets can be handled with coal infrastructure, in the same coal pile at the same coal mill. To get it there you can transport in open rail cars, to a port where there&rsquo;s an outside terminal, no warehouses needed, and then load it into a ship and off to Europe, again no need for closed storage. All of this is needed for wood pellets.&rdquo;
 Topell and investor RWE Innogy participated in a study that aimed to calculate fuel costs for coal, conventional wood pellets and torrefied pellets at the gate of an ordinary coal plant in Western Europe. In comparing electricity production costs of cofiring (torrefied) pellets with solely coal combustion at the same coal plant, it was found that, in all cases, cofiring torrefied pellets is more cost-effective than cofiring conventional wood pellets.
 The majority of that cost advantage comes from avoided additional capital costs.&nbsp; Regarding electricity production costs, coal still has a major cost advantage over torrefied pellets, the study finds, but differences can be bridged, and it is likely torrefied pellets will start to compete with coal eventually. &ldquo;Utilities like RWE are looking at black pellets to replace any wood pellet they can, in the near future,&rdquo; van der Burg says. &ldquo;There isn&rsquo;t serious production of torrefied wood pellets right now, but it&rsquo;s going to happen.&nbsp; Wood pellets are the best solution at this moment, but there are enormous efficiency improvements to be made in the next few years.&rdquo;
 More people are becoming aware of the correct economics of torrefaction and what the improvements are, van der Burg adds. &ldquo;They are a lot bigger than people originally thought.&rdquo; Author: Anna Austin&nbsp; Associate Editor, Biomass Power &amp; Thermal (701) 738-4968 <a href="mailto:aaustin@bbiinternational.com">aaustin@bbiinternational.com</a>

TORREFIED TECHNOLOGY: HM3 is building a torrefied biomass demonstration facility in Troutdale, Ore., and has plans to build a commercial-scale plant in Prineville, Ore. 

2011/08/13141137368075.jpg

COST COMPARISON: The total cost savings of the torrefied pellet (TP) value chain over the wood pellet (WP) value chain 

2011/08/13141137655138.jpg

Cofiring torrefied biomass with coal seems like a great way to reduce emissions, but is it economical? 

Glorified, Torrefied & Cofired

When Minnesota Power began cofiring coal and biomass at its power plants in Duluth and Grand Rapids, Minn., more than 20 years ago, they started out combusting 75-25 coal to waste wood ratios. Back then, biomass was plentiful and cheap and it was common to get it for free, says Mike Polzin, renewable fuels coordinator for Minnesota Power. &ldquo;We started burning wood in Duluth only because a new paper mill had bark they had to get rid of and they didn&rsquo;t know what to do with it,&rdquo; he says.
 That has changed significantly as the years have gone by, as biomass has become a hot commodity. Competition for material has become stiff and in many cases can be pricey. Still, certain incentives that have come into play during that time&mdash;such as state renewable energy credits&mdash;make it enticing for power utilities such as Minnesota Power to use more biomass.
 And, that&rsquo;s precisely what the utility has done and continues to do. Today, the facility in Grand Rapids produces about 25 megawatts (MW) of electricity from a 15-85 coal to biomass ratio, and the Duluth facility typically generates about 50 MW from a 10-90 coal to biomass ratio. Using that much biomass at facilities that were meant for coal hasn&rsquo;t come without its challenges, Polzin says, the biggest of which are related to materials handling and storage.
 While it won&rsquo;t be the case at every facility, so far, there have been ways around these challenges.
 Storage Situation&nbsp; 
 Biomass can be bulky and requires a lot of space, but storing it isn&rsquo;t as simple as just finding more space&mdash;it must be kept dry, hence requiring some type of covered storage system. &ldquo;The biggest challenge has been on-site storage,&rdquo; Polzin says. &ldquo;We just don&rsquo;t have enough of it&mdash;we&rsquo;re at 90 percent biomass at Duluth, but site storage is much too small.&rdquo;
 That necessitates deliveries of biomass seven days a week, a process which Polzin is charged with facilitating. &ldquo;We have about 900 tons of on-site storage, but we burn over 1,000 tons of biomass each day,&rdquo; he explains. &ldquo;So it&rsquo;s there only for a number of hours. We dump it into a large building then pull it back out to be used; all the wood that comes in and gets stored is gone in 24 hours or less.&rdquo; Getting the appropriate amount of deliveries each day is where the challenge lies, as the weather can create havoc on timber harvesting. &ldquo;Significant snow or rain handicaps loggers from getting into the woods and bringing materials to us, and spring road restrictions can also create problems,&rdquo; Polzin says. When there isn&rsquo;t enough stored fuel, it could mean a shortage.
 To mitigate that problem, Minnesota Power has 50 possible suppliers, and requires only two to three truckloads per day from a given supplier. &ldquo;They have the potential to put out five or six [truckloads], but if we can get two or three from several suppliers, we make sure we can always get enough to satisfy our appetite for wood,&rdquo; Polzin says. &ldquo;We suggest that our suppliers have more than one market to deliver to, because inevitably we will have to go off-line due to plant outages, equipment failures and things like that. That way, they can reroute deliveries to another market. If those other markets have outages, they can deliver more to us.&rdquo;
 However, if a situation does arise where they can't secure&nbsp; enough wood&mdash;and it does happen&mdash;it&rsquo;s just a matter of calling for more coal. &ldquo;[Using more coal] doesn&rsquo;t create any problems with our infrastructure,&rdquo; Polzin says. &ldquo;There are large coal suppliers close to both facilities, so we can get more coal within two hours, to keep us online.&rdquo;
 Bruce Browers, senior engineer at Barr Engineering, agrees that storage is one of the biggest challenges in cofiring. Last summer, Barr completed biomass cube test burns at Wyandotte Municipal Services in Wyandotte, Mich., and says if the company were to cofire biomass for the long-term, the current storage system would have to be significantly modified. &ldquo;[Biomass] doesn&rsquo;t stand up to moisture,&rdquo; says Browers, who, coincidentally, was a project manager at Minnesota Power when its plants were built in the mid-1980s. &ldquo;Pulp and paper guys who burn waste biomass fuel have different fuel handling systems and somewhat different boilers so it can sit out in the snow and rain in those situations, but when you&rsquo;re dealing with a processed biomass fuel, it has to be stored.&rdquo;
 Adding a new biomass storage system to an existing coal plant can be costly. &ldquo;We&rsquo;ve seen fuel handling yards as cheap as $12 million, to all the way up to $50 million,&rdquo; Browers says. &ldquo;It&rsquo;s a very expensive part of burning biomass; using biomass as you get it doesn&rsquo;t work everywhere, and there isn&rsquo;t always an active forest products residuals industry. The whole volume of storage becomes a critical driver. It&rsquo;s a huge issue.&rdquo;
 Since the biomass is used so quickly at Minnesota Power, potential storage issues such as molding aren&rsquo;t relevant. At other large-scale cofiring operations, which are common in the U.K., molding and caking are potential problems when the biomass and coal are mixed and stored together.
 Minimizing Mold and Dust&nbsp; 
 &ldquo;When you have a mix of biomass and coal, the water transferred from the coal to the biomass often causes it to go moldy,&rdquo; says Mike Bradley, director and professor of bulk and particulate technology at the Wolfson Centre for Bulk Solids Handling Technology on the Medway campus of the University of Greenwich in the U.K. The mold growth gives strength to the material, which is referred to as caking. &ldquo;You tend to get hard cakes in nonmoving areas of bunkers and silos, and this prevents flow,&rdquo; Bradley says.
 Likewise, water ingress into the storage area can cause mold growth and caking. &ldquo;The best way to prevent this is to ensure that the bunker or other storage vessel discharges in a &lsquo;first-in, first-out&rsquo; pattern, so the oldest material is used first and any discharge of material disturbs everything above it,&rdquo; Bradley says. &ldquo;We call this mass flow, which means good stock rotation. It prevents areas of long-term static residence.&rdquo;
 Many biomass materials that have high moisture content will mold and ferment by themselves in storage, so they must be used in strict rotation to prevent self-ignition, much like a wet haystack can do, Bradley adds. The same is true for coal.
 &ldquo;With direct cofiring the coal is pretty hands off,&rdquo; Polzin says. &ldquo;The only problem with coal is that if we get wet coal and leave it in the storage bins for too long, it&rsquo;ll self-combust. We have to make sure that if we&rsquo;re having an outage we don&rsquo;t put too much in the storage silos. Managing your coal inventory is critical.&rdquo;
 Usually, mold growth that leads to caking takes about two days to become significant, but it depends on the temperature, according to Bradley. &ldquo;Warm, moist conditions accelerate it; cold conditions retard it. It also depends very muchon the particular biomass&mdash;some do not cake readily, others cake very easily and quickly.&rdquo;
 In contrast to moist conditions creating mold, dust is also a potential issue at cofiring operations.&nbsp; &ldquo;Dust is an issue because biomass has a much greater capacity to suck up water than coal,&rdquo; Bradley explains. &ldquo;When you mix coal&mdash;typically wet on the surface at 6 to 10 percent moisture&mdash;with biomass, which is often 10 percent water, the biomass sucks in all the water and that leaves the coal dry and dusty. Hence, you get much more coal dust emissions when you cohandle.&rdquo;&nbsp;
&nbsp; In addition, biomass has its own dust content, so even materials that have low dust tend to break down in handling and produce dust, Bradley says. &ldquo;Both coal and biomass dusts are a serious explosion hazard. With the dust on cohandled coal and biomass being more mobile than on coal alone, it can easily create [hazardous] conditions in a plant.&rdquo;&nbsp;
 These types of explosions occur when a mix of combustible dust and air are ignited by a hot surface or spark. &ldquo;Usually this happens locally at first, typically due to an overheating bearing, a static discharge or someone doing some grinding or welding,&rdquo; Bradley explains. &ldquo;The draught from that small initial explosion whips accumulated dust up off the floor and other flat surfaces, creating an explosive mix of dust and air&mdash;then a fireball sweeps through the whole building in seconds, devastating all before it.&rdquo;
 Polzin agrees that dust can create a hazardous situation. At Minnesota Power&rsquo;s Duluth facility, all of the conveyors are covered with metal, horseshoe-shaped hoods so dust cannot be blown off the conveyors. &ldquo;The storage facility is completely closed, so we don&rsquo;t get a lot of fugitive dust blowing around,&rdquo; he says. &ldquo;We have a large truck dump where, when a surge of wood is dumped from the truck into the bin or receiving hopper, it creates a dust plume, so we have some vacuums to help mitigate or minimize that.&rdquo;
 Additionally, the company&rsquo;s operating permit requires dust minimization in the entire area of the plant, so parking lots and roads are paved, and a street sweeper is used to sweep up loose dust and wood chips. The situation is similar at the Grand Rapids plant. &ldquo;We&rsquo;re sensitive to dust blowing around; we don&rsquo;t like a lot of fines,&rdquo; Polzin says. &ldquo;The reason we have a hog fuel grinder at each facility is because we&rsquo;d rather have material come to us at a larger size initially, so it doesn&rsquo;t blow around.&rdquo;&nbsp;
 Once biomass is ready to enter the plant, another slew of potential problems can surface, including fuel feed system issues.
 Other Potential Issues
 Biomass won&rsquo;t always flow smoothly through a feeding system meant for coal for a number of reasons, one of which is winter weather conditions. &ldquo;On the biomass side, [frozen] wood going through our chutes and storage system is a big problem because it tends to bridge and plug up the system because in the winter it often comes in frozen chunks,&rdquo; Polzin says.
 Plant attendants usually realize that not enough wood is getting into the boiler when the heat rate can&rsquo;t be sustained, or bin indicators sound an alarm. &ldquo;We simply have to go out there and ram the wood through,&rdquo; he says. &ldquo;We have customized some hatch doors that we open, and then we poke and prod the wood with long rods until it is muscled through.&rdquo;
 At Wyandotte in Michigan, which has a 25-MW circulating fluidized bed (CFB) system designed to burn coal and tire-derived fuel (TDF), Browers says the plan going into the test burns was to do 30 and 60 percent biomass ratios. Due to the limestone feeder capabilities, however, the tests had to be modified to 15 percent. &ldquo;[Running the biomass through the limestone feeder] wasn&rsquo;t the best way we could do the test burns, but it was about the only way,&rdquo; Browers says. Since there was no way to get the desired blend out in the coal yard, the only way get it was to let the fuel feeders take the coal and TDF, and put the biomass fuel in the limestone feeders. &ldquo;The measuring device coming out of the feeders allows us to control the blend.&rdquo;
 A 60 percent blend would have worked fine in the boiler, he adds, but it wasn&rsquo;t feasible because of the delivery issues with the limestone system.&nbsp;
 Another issue Browers says that needs attention are potential sparklers. &ldquo;Sparklers are what happen when you burn biomass in a CFB or stoker,&rdquo; he explains. &ldquo;There are a lot of particles to it, and they don&rsquo;t always combust where they are supposed to. They can carry over from the bed into the convection pass, and you don&rsquo;t want combustion in there.&rdquo;
 Attendants must physically open the boiler door to check for sparklers. When they do occur, it indicates a couple of problems&mdash;inefficient combustion, and carry-over of carbon particles. &ldquo;Then you have to worry about fires,&rdquo; Browers says. &ldquo;There isn&rsquo;t enough to explode, but as it falls out in your duct work or gets removed in your particulate removal device, you&rsquo;ve got carbon particles in there and they&rsquo;re susceptible to fires.&rdquo;
 Overall, Browers says that cofiring isn&rsquo;t all that simple. &ldquo;People who think it&rsquo;s easy to chip raw biomass and run it through their coal system may want to rethink that assumption,&rdquo; he says.
 In fact, it can take a long time to work out the kinks. Even at Minnesota Power, which has been cofiring for decades, the company is working to optimize its cofiring operations, according to Polzin. In an upcoming project that will take place over the next couple of years, the company will put in new feeders, more robust material handling systems and more storage, though biomass deliveries will have to be more coordinated than ever with the near doubling of biomass consumed at each plant.
 Unlike the U.K., cofiring biomass with coal in the U.S. is still largely in the testing phases, and many utilities that have been interested in cofiring in the past have slowed down plans due to regulatory uncertainties surrounding biomass. &ldquo;More incentives are needed,&rdquo; Browers adds. &ldquo;There is a lot of talk here about cofiring, but if you look at who has actually done it, there aren&rsquo;t many.&rdquo; Author: Anna Austin Associate Editor, Biomass Power &amp; Thermal (701) 738-4968 <a href="mailto:aaustin@bbiinternational.com">aaustin@bbiinternational.com</a>

2011/08/13141140510996.jpg

Biomass Power & Thermal investigates potential technical and safety issues involved in storing and handling biomass at cofired power plants.

Biomass and Coal: A Powerful Combination

With so few U.S. coal utilities cofiring woody biomass, the practice must be fraught with combustion-related problems, right? Not so. Fortunately, the co-combustion aspect itself, for most boilers, is surprisingly free of any detrimental issues that can&rsquo;t be mitigated through proper material sizing and feedstock blending. That, however, requires a timely and often expensive trial-and-error process.
 &ldquo;Everyone wants to [cofire], but nobody wants to spend a lot of money,&rdquo; says Bill Stirgwolt, manager of biomass engineering for boiler designer and manufacturer The Babcock &amp; Wilcox Power Generation Group Inc.&nbsp; Paper mills have for years, and in some cases decades, successfully fired bark with pulverized coal, he adds. &ldquo;To do that, the boiler is designed with a grate and the course fuel is fed into the lower part of the furnace and burnt on a grate, and above it would be pulverized coal burners.&rdquo; But paper mills aren&rsquo;t necessarily as concerned with efficiency as much as they are with generating steam for internal plant consumption. &ldquo;The challenge is when you try to make it look like, or fire like, a pulverized coal,&rdquo; he says. &ldquo;Those folks are asking, &lsquo;How can I get as much energy without compromising the combustion process or taking a hit on efficiency?&rsquo;&rdquo;
 Cofiring is a simple-enough process, but Stirgwolt cautions, &ldquo;If you want to cofire biomass, you can&rsquo;t put blinders on.&rdquo;&nbsp;
 Size and Blend Solution
 &ldquo;You have to get the fuel sized properly, and that&rsquo;s not easy to do,&rdquo; Stirgwolt says. &ldquo;If you can make the particle size small, the biomass burns readily. If it&rsquo;s not small, then you&rsquo;re going to have combustion issues.&rdquo;
 The main problem with a biomass fuel that&rsquo;s too big is the unburned carbon. The residence time for a pulverized coal furnace is short and does not provide for ample burning of larger biomass, Stirgwolt says. Under ideal circumstances, biomass devolatilizes and the fixed carbon burns out. &ldquo;If you don&rsquo;t have enough time for the fixed carbon to burn out, it will carry over to the convection pass, the air heaters or particulate capture device.&rdquo; When hot, unburned carbon or char from oversized fuel enters an air heater precipitator or baghouse, it leaves disconcertingly high probabilities of fire, needing only a small leak that provides a source of air, Stirgwolt cautions. &ldquo;If you want to fire biomass in a burner, it all comes down to size reduction.&rdquo;
 Perhaps just as important as fuel particle sizing is fuel blending. Without uniform size and quality, biomass material can cause bridging and plugging in the combustion process, specifically ground woody biomass, according to Gregg Coffin, superintendent of the University of Missouri in Columbia power plant. Such materials tend to create flow blockages, he adds.&nbsp;
 The university has four coal-fired stoker boilers that cofire up to a 15 percent blend of woody biomass. Coffin says problems have arisen mainly in biomass fuel procurement and blending, with little difficulty on the combustion end. &ldquo;A good, clean wood chip product was sized very well to blend with our coal,&rdquo; he says. &ldquo;They burn well. We didn&rsquo;t have any combustion issues, environmental issues or operational issues.&rdquo;
 The process for settling into the proper fuel size and blend for a specific boiler is, unfortunately, trial and error, both Coffin and Stirgwolt agree. One of the first problems the University of Missouri encountered was the lower density of woody biomass in comparison with coal. The plant uses a batch-style scale to measure the fuel&mdash;both coal and biomass&mdash;going into the furnace, he explains. &ldquo;It is designed to know when it&rsquo;s full by weight. So as soon as you start introducing a significant amount of wood chips at a much lower density and larger volume, they would overfill.&rdquo; All that was required to fix the problem, however, was an adjustment to the scales and fuel feed.
 So far, the best results for the university have come with a feedstock of mill residue from wood products manufacturing facilities, delivered in well-sized and uniform quality chips. The 66-megawatt combined-heat-and-power plant produces about 60 percent of the campus&rsquo;s electricity needs and 100 percent of its steam requirements. With more than 14 million square feet of facilities including a research hospital, a Department of Veterans Affairs hospital and a veterinary hospital, that&rsquo;s no small feat.
 The school is replacing the plant&rsquo;s aging fuel handling system, as well as a coal-fired boiler, and is taking that opportunity to install a 100 percent biomass boiler and associated fuel system, Coffin says. The bubbling fluidized bed boiler will burn primarily wood chips, initially about 90 percent coming from mill residue and 10 percent from tree tops and branches. The system will also use agricultural residues such as corncobs and some energy crops including switchgrass and miscanthus.
 &ldquo;With the new coal system and new biomass system, we&rsquo;ll have a much better way to meter-blend the wood chips with coal for cofiring in the existing plant, as well as a nice conveyor system for the new boiler,&rdquo; Coffin says.
 &nbsp;Coffin&rsquo;s advice for conquering that trial-and-error headache is to first identify the fuel source and size for the furnace, and then start slowly with small blends, incrementally increasing until the first challenges arise. &ldquo;Then you either correct those challenges or you back off to where you find where the appropriate blend ratio is for your plant.&rdquo;
 Moisture and Ash
 The proper fuel blend can also mitigate issues related to moisture content in the combustion process. Too much moisture in the wood can cause clumping, especially in pulverized coal burners, according to Tom Kimmerer, senior scientist at Moore Ventures LLC. To avoid that, he explains, pulverized coal boiler operators have three options: mixing wood and coal before pulverization, which is generally not a good idea; mixing after pulverization; or injecting the wood into a separate burner from the coal, which could be the best option. &ldquo;These boilers have more than one burner,&rdquo; Kimmerer says. &ldquo;You can open up a port when you do the retrofitting that allows you to feed wood in separately from the coal and that appears to be the most effective way in a pulverized coal boiler.&rdquo; The best long-term solution, he adds, is using torrefied wood, as it becomes coal-like and hydrophobic, but the material still comes at a high price and finding a large enough supply to conduct adequate testing could present a challenge.
 Moisture content is simpler to deal with in fluidized bed boilers than pulverized coal boilers, as fluidized bed boilers are not as susceptible to problems caused by clumping. Still, Stirgwolt says moisture is only an issue when cofiring large amounts of biomass.
 &ldquo;Moisture content can be a problem, but it really has to do with the fact that a lot of biomass material has more moisture than coal,&rdquo; says Michael Goerndt, postdoctoral fellow in the University of Missouri&rsquo;s Department of Forestry. The extent of the disruption moisture content causes depends heavily on, of course, how the material is stored, but also the type of material. Pellets, he says, have lower moisture content than chips, although it is harder to break pellets down smaller than their individual constituents.
 But even with the use of wood chips, Coffin says the university hasn&rsquo;t experienced the moisture problems it had anticipated, although the chips&rsquo; lower Btu value in comparison with coal&rsquo;s, warranted some system adjustments. &ldquo;You have to recognize that and adjust your air flow as well as understand the impact to your steam capacity,&rdquo; he says.
 Ash content in cofiring also proved to be a nonissue for the school, but it has a tendency to wreak havoc on heat transfer surface maintenance and cleaning, in some instances. &ldquo;There are certain types of biomass that may want to slag, so it would create a drippy fouling in the furnace itself that can be difficult to clean,&rdquo; Stirgwolt says, adding that additional cleaning devices in the furnace might be needed. In cooler regions of the boiler, dry ash could also deposit on the heat transfer surface requiring additional soot-blowing equipment or an increase in blowing frequency. No large difference exists between ash content of wood and that of coal, and, in fact, coal probably has more, Stirgwolt says. The trick is the nature of the ash once it&rsquo;s fired. &ldquo;Does it make a more difficult-to-clean combustion product?&rdquo;&nbsp;
 Pondering Potential
 Despite the easily mitigated boiler issues that may arise with the co-combustion of wood and coal, the potential for cofiring is enormous and hinges on several significant factors, Goerndt says. Infrastructure for biomass transportation is crucial and is one factor working in the University of Missouri&rsquo;s favor. Goerndt also lists coal availability and price, as well as woody biomass resource availability. Electricity demand makes the list too, but is only marginally significant.
 Not surprisingly, the implementation of state renewable portfolio standards is a major factor Goerndt and his colleagues are studying. The university&rsquo;s School of Natural Resources has conducted a cofiring potential study for 20 states in the Northern region of the U.S., finding that 19 of those 20 had renewable standards as of 2010, giving them higher potential for cofiring. &ldquo;It was a significant enough variable that we made a pretty fine point about it in our report,&rdquo; he said, adding that the report is not yet released. &ldquo;It means renewable portfolio standards are having a significant correlation with cofiring.&rdquo;
 Despite all the clear potential, woody biomass and coal cofiring remain primarily relegated to testing, and Stirgwolt attributes that to a lack of mandates and renewable energy credits. &ldquo;Over the past two to three years, we&rsquo;ve had a tremendous amount of inquiries about &lsquo;How can I fire biomass in my existing pulverized coal-fired utility boiler?&rsquo;&rdquo; Stirgwolt says. &ldquo;The key here is that a lot of people are investigating biomass cofiring with the thought that they were going to have to do something for renewable energy credits, but they&rsquo;ve never moved forward with any of the studies.&rdquo;
 Goerndt and Coffin attribute the lack of a solid U.S. cofiring sector to cost, while Coffin also adds availability. &ldquo;In our case, we were able to secure our biomass at a comparable price to coal,&rdquo; Coffin says.
 While Goerndt&rsquo;s reasoning specifies biomass transportation costs, the university sees an advantage in no longer transporting coal from out of state. &ldquo;Being a state-supported public university, it&rsquo;s always in our best interest when we can spend our funds within the state,&rdquo; Coffin emphasizes. &ldquo;By using biomass in lieu of coal, we transferred a portion of our fuel budget from out-of-state coal expense to in-state biomass expense. That&rsquo;s regional economic development.&rdquo; As the university expands its use of biomass over the next few years, it will make a significant impact on the number of jobs in the region and reinvestment of those dollars back into Missouri.
 Whatever the reason for minimal biomass/coal cofiring action in the U.S., it doesn&rsquo;t seem to stem from boiler issues in the combustion process, as they can be easily tackled. &ldquo;I&rsquo;ve talked to a lot of people who are interested in cofiring and the first thing I tell them is after you identify your source and try to determine your sizing, your challenge is to figure out how best to get it blended [to avoid conveyance and boiler problems],&rdquo; Coffin says. &nbsp; Author: Lisa Gibson Associate Editor Biomass Power &amp; Thermal (701) 738-4952 <a href="mailto:lgibson@bbiinternational.com">lgibson@bbiinternational.com</a>

COFIRING COMBO: The University of Missouri in Columbia cofires up to 15 percent wood chips with coal. 

2011/08/13141144107234.jpg

COFIRING IN COLUMBIA: After conducting years of cofiring tests, the University of Missouri in Columbia is installing a 100 percent biomass boiler, while continuing to cofire in its coal boilers. 

2011/08/13141144556904.jpg

BRAND NEW BOILER: The installation of a 100 percent biomass boiler and fuel system on the university's Columbia campus will also allow for better meter blending of wood chips with coal for cofiring in the existing boilers. 

2011/08/13141144951646.jpg

While cofiring woody biomass with coal is more common on a testing scale than commercial, most issues related to co-combustion within the boiler can be alleviated with proper fuel sizing and blending. 

Conquering Co-Combustion

From tax credits to stable regulation, public sector support is widely accepted as critical to the economically successful integration of biomass as a source of renewable power. For biomass companies, finding locations where the public sector environment is friendly could be one of the most important factors in designing a sustainable business model. As such, North American companies should not limit themselves to the 50 states. In fact, Ontario, Canada, has emerged as a location with a unique blend of natural resources, regulation and investment programs that make it a business-friendly location with advantages specifically beneficial to biomass power generation.&nbsp;
 Strong tax incentives, a highly trained workforce, a surplus of forestry materials and direct government investment in research and development initiatives all contribute to the biomass-friendly culture of Ontario. By embracing the biomass industry, Ontario has cleared a path forward for both national and international companies to pilot in the new era of biomass power generation, and to do so profitably.
 The Ontario Biomass Opportunity
 Ontario could be considered a natural early adopter of the biomass opportunity. The province identified early on that its North American location, forestry industry community expertise and vast natural resources would make it an advantageous location for biomass power generation.&nbsp;
 With fuel prices fluctuating, concerns about North America&rsquo;s dependence on fossil fuels are increasing. Countries, states and provinces are looking to create innovative energy solutions while strengthening economies. Increasingly, biomass is emerging as an important new source of renewable fuel, and Ontario offers an early blueprint. Leveraging significant investment in research and development and tax incentives, Ontario has begun converting coal plants to biomass generation facilities, including one already operating at Atikokan, in northern Ontario.
 This early adoption of biomass is not surprising, given that Ontario&rsquo;s forests cover an area larger than the size of forests in Belgium, France and Germany. With their vast size and excellent track record for sustainable forestry, Ontario&rsquo;s forests provide a wealth of high-quality and diverse wood and bioenergy products from a reliable source of renewable and diverse forests. In fact, 80 percent of the total licensed land base has been independently certified to one of the following performance standards: Forest Stewardship Council, the Canadian Standards Association and the American Forest and Paper Association&rsquo;s Sustainable Forestry Initiative.
 Additionally, many Ontario communities offer a labor force that is educated in the processing of wood and related wood products and outputs. The value-added wood products field represents one such industry, and it makes up 60 percent of Ontario&rsquo;s $18 billion ($18.3 billion) forest products industry. There are more than 2,000 companies producing everything from pallets to engineered products using composite technology. With the global downturn and worldwide restructuring of the forestry industry, however, many of Ontario&rsquo;s forestry facilities have experienced decreased demand. But there is a silver lining for biomass energy production&mdash;the downturn has spurred a number of innovative uses for the unused wood, including increased energy production.
 In fact, in addition to those resources already mentioned, bioenergy resources are plentiful in Ontario and include residual materials from forestry operations left on the forest floor, waste matter from agricultural production and byproducts of food-processing operations. As such, the Ontario Power Authority estimates that a total of 450 megawatts (MW) of energy could be produced by biomass projects in the province by 2027, five times the current and committed capacity.
 Trading Coal for Biomass in Atikokan
 To achieve this goal, Ontario is converting multiple existing coal power stations to use biomass to generate energy. The first power plant to undergo the conversion to biomass is the 211-MW Atikokan generating station, which has already achieved full load on 100 percent wood pellets. The fuel contract for Atikokan was put in place in 2010, and Ontario Power Generation (which is owned by the province and produces 66 percent of Ontario&rsquo;s electricity) has published a fuel supply request for an initial 90,000 tons of wood pellets, a figure that is expected to increase over time.
 There is good news at Atikokan both economically and environmentally. The annual fuel requirements for the plant are estimated to amount to less than 1 percent of the total allowable forest harvest in Ontario each year. Even given this low consumption of wood, the plant is expected to generate enough power to support 15,000 homes each year.
 Support for R&amp;D, Entrepreneurship
 In addition to the direct power generation already taking place, research in the biomass field to pioneer future relevant technologies is also supported by the Ontario government. Ontario is home to the Centre for Research and Innovation in the Bio-Economy. CRIBE&rsquo;s role is to aid the transformation of the forest products industry in northern Ontario by acting as a conduit for companies interested in investigating opportunities in the bioeconomy. CRIBE is able to partner financially with relevant industry organizations and private sector partners to bring emerging technologies to fruition.&nbsp;
 Biomass-Friendly Government Programs
 The future has never been brighter for biomass and other renewable energy technologies in Ontario and in other jurisdictions ready to make the investment to move to such an efficient renewable energy source. Stephen Roberts, a strategic sector coordinator at the Ontario Ministry of Northern Development, Mining and Forestry points to the wide variety of market entry options for U.S. companies, and emphasizes that the Ontario government is supportive of U.S. investment and welcomes U.S. technology, experience and investment. &ldquo;A smart operator could be very successful with a business model that draws on our surplus wood supply, our new bioenergy legislation, and our existing forestry and logistics infrastructure,&rdquo; he says.
 Through leveraging its natural resources, its early adoption of biomass as a renewable energy source, and its direct government support for research and development and entrepreneurship within the industry, the Ontario government has created an environment designed to support the success of biomass-related companies. In doing so, Ontario is demonstrating to the rest of the world how to use biomass to truly diversify sources of energy, and move into an era of clean, green power. Author: Shirley Townsend Senior Economic Officer, California Ontario Ministry of Economic Development and Trade <a href="mailto:Shirley.Townsend@international.gc.ca">Shirley.Townsend@international.gc.ca</a>

2011/08/13141149603347.jpg

Strong tax incentives, a highly trained workforce, ample forestry materials and government investment in research and development make Ontario a great location for biomass power development.

Biomass: The Ontario Opportunity 

In the U.K. every year nearly 35 million metric tons of municipal solid waste (MSW) is generated. And up to 60 percent of MSW can be made up of renewable materials that could be used to generate energy.
 In the U.K., generators of renewable energy can receive Renewable Obligation Certificates, which can then be sold on to electricity suppliers. ROCs are issued for every megawatt hour (MWh) of renewable electricity generated and each of these ROCs currently sells for around &pound;50 ($81.13).
 When you convert mixed waste streams into electricity, however, it can be difficult to determine how much of this energy is renewable. Many approaches have been considered (see table on page 51) but up until now, only one energy-from-waste (EfW) power station in the U.K. has received any ROCs.
 The Energos plant on the Isle of Wight has been receiving ROCs since the start of this year, but its approach is to measure the biomass content of the fuel and the gross calorific value of the flue gas. This can be an unrepresentative and time-consuming affair.
 Carbon 14
 Now, the British electricity and gas market regulator, Ofgem, which issues ROCs, has approved the use of a new method known as the carbon 14 technique to help calculate the renewable content of EfW so installations can benefit financially from the renewable energy they produce.
 &ldquo;Independent reports concluded that the carbon 14 technique is based on mature and well-understood technology,&rdquo; says Richard Bellingham, biomass, waste and cofiring manager at Ofgem.
 &ldquo;We are therefore prepared to consider fuel measurement and sampling (FMS) procedures that propose to use the carbon 14 technique. As always, the FMS proposals will be considered on a case-by-case basis, taking into account the different feedstock used and the nature of each generating station.&rdquo;
 The approach takes advantage of the fact that as living organisms die and are converted to fossil fuel, the proportion of carbon 14 isotopes they contain will decrease, due to radioactive decay. So fossil fuels contain far fewer carbon 14 isotopes than recently living biomass. This can be measured in the smokestack (or flue gas) of power plants so they can claim ROCs.
 Double or Nothing
 EfW installations can receive double ROCs if they can prove the renewable content of their feedstock. The double ROCs banding is the highest incentive available under the U.K. Renewables Obligation system and is designed to support investment in emerging technologies, such as advanced gasification and pyrolysis.
 Finding a technique to simply and accurately determine the renewable energy produced by EfW installations has been a major stumbling block for the industry, and has until now presented a missed opportunity for energy generators who could be claiming ROCs.
 &nbsp;&ldquo;Waste-derived fuels are a vital indigenous source of renewable energy for electricity, heat and ultimately transport fuels,&rdquo; said Chris Manson-Whitton of clean energy project development company Progressive Energy Ltd. &ldquo;We are very pleased that Ofgem has adopted this technique, which will facilitate industry in unlocking this valuable resource.&rdquo;
 &ldquo;This has been the culmination of a four-year story to establish this exciting technique as a method for measuring the renewable content of waste-derived energy. We, along with other advocates like the National Non-Food Crops Centre, New Earth Energy and the Renewable Energy Association welcome Ofgem&rsquo;s decision and are pleased that our efforts have opened the door for generators to use this pioneering approach,&rdquo; he adds.
 While the technology is new to the U.K., it is already in use in countries such as Belgium and the Netherlands and has proven highly successful in measuring the renewable carbon in their flue gases. Now several U.K. EfW installations have decided to start using the technology. The U.K.&rsquo;s National Centre for Biorenewable Energy, Fuels and Materials&mdash;the NNFCC&mdash;were amongst the first to propose carbon 14 as a simple and accurate method for measuring the renewable carbon of flue gas.
 &ldquo;The carbon 14 method is enabling easy and accurate differentiation between carbon dioxide emissions created from fossil sources and those from renewables,&rdquo; says John Williams, head of materials for energy and industry at the NNFCC. &ldquo;As a long-term advocate, the NNFCC hopes this trusted and established analysis technology will significantly increase the number of power stations making renewable energy from waste biomass.&rdquo;
 The carbon 14 technique starts with a sample of carbon dioxide taken from the flue gas of a facility. This can be taken in small increments every 30 minutes or so, then a composite sample can be made to accurately represent the whole month. The carbon dioxide is then sent to a lab for analysis, where it is burned, reduced to graphite and tested for isotopic abundance using a process known as accelerator mass spectrometry. From this, the renewable content of an EfW power station can be determined.
 The method itself is an established technique operated under international standards ASTM 6866 and CEN 15591/15747. In 2010, the NNFCC was invited to be the U.K. representative on the European Committee for Standardisation panel for adopting a standard measurement of renewable content. This led to the creation of a new U.K. standards committee, designed to look at the wider implications of developing a biobased standard, which helped influence Ofgem&rsquo;s decision.
 But the carbon 14 method has some critics, including Richard Black, operations director of the U.K. Resource Efficiency Knowledge Transfer Network, who says &ldquo;The advantage of this process is that gas analysis is very representative of the actual feedstock input, but the major disadvantage of the method is that it's retrospective and expensive.&rdquo;
 Similarly Tony Grimshaw, technical director of Energos, says. &ldquo;This is the first step that Ofgem accepts it is an alternative,&rdquo; he says. &ldquo;But some trials need to take place and it needs to be demonstrated on the ground. Cost is the other issue. In my view, it is probably a year away before it all beds down.&rdquo;
 Future
 EfW could play an important role in contributing toward European Union targets to produce 20 percent of its energy from renewable sources by 2020. However, the problem until now has been how to measure the renewable content of waste.
 But all things have a built-in time clock to differentiate, between renewable carbon (carbon 14) and fossil carbon (carbon 12). By measuring this ratio in a power station smokestack, we can determine the renewable carbon content of any source material using a single physical measurement, independent of secondary information. This will allow simple regulation of certification schemes in the future. Author: Matthew Aylott Staff Writer, U.K. National Non-Food Crops Centre <a href="mailto:M.Aylott@nnfcc.co.uk">M.Aylott@nnfcc.co.uk</a> <a href="http://www.nnfcc.co.uk">www.nnfcc.co.uk </a>

2011/08/13141152726119.jpg

PROS AND CONS: Comparison of advantages and disadvantages of different methods for measuring renewable content of energy from waste




2011/08/1314115302989.jpg

A technique based on carbon dating will soon be used in the U.K. to determine the proportion of energy from waste that is renewable. 


Calculating the Renewable  Fraction of Energy from Waste

The biomass and biodiesel industries collided in St. Louis this spring at the International Biomass Conference &amp; Expo as Dino Mili, co-founder and CEO of Montreal-based New Forest Industries, gave a presentation titled Low Severity Process Yields Functionalized Wood Pellets and Biodiesel. The process Mili discussed is an ideal biorefining retrofit strategy for a distressed pulp and paper mill, the end products from which would be wood pellets and biodiesel&mdash;a counterintuitive pair of products. It involves hydrotorrefaction in which wood chips are cooked in a digester with water, &ldquo;just like the pulp industry has been doing for years,&rdquo; he tells Biorefining Magazine, at about 160 degrees Celsius for an hour and a half. The hemicellulose (woody biomass consists of three main components: cellulose, or six-carbon sugars; hemicellulose, or five-carbon sugars; and lignin) and soluble fractions like ash and chlorides are separated out, and the lignin and cellulose portions are used for high-grade wood pellets optimized for combustion. Mili says the resulting wood pellets are harder, more energy dense and hydrostable, since the hydrophilic fractions are removed. The hemicellulose is separated and hydrolyzed to five-carbon sugars, a base feedstock for many advanced ethanol projects; but rather than make ethanol from these sugars that are more difficult and costly to ferment, Mili says the project reverts to more robust, homogeneous organisms to convert the five-carbon sugars to lipids for use to make fatty acid methyl esters (biodiesel). New Forest Industries has hired FPInnovations to help put the project together. &ldquo;The biggest issue is the conversion of the sugars to lipids,&rdquo; Mili says. He says most of the organisms the project will use were originally developed for the wastewater treatment industry. In explaining the process, he also noted that if we eat too much sugar, our bodies will convert those sugars to fat, or lipids; so these microorganism conversions work in a similar way. Mili couldn&rsquo;t give too much detail because his company is still finalizing patent applications on the process. The oil properties from the converted sugars to lipids&mdash;the microbial oils&mdash;fall between those of vegetable oils and animal fats, Mili says. Mili says he predicts 60 percent of the revenue stream from the process will come from pellet sales, while the remaining 40 percent will be equally distributed between green power and biodiesel. While this biorefining approach would work well in a pulp and paper mill, finding one to work with might be more difficult than it appears. Mili likened a partnership between a biorefining startup and pulp and paper mill as a man with a cart who wants to hook it up to a horse. The stable owner (the mill owner) has only thoroughbreds (new, efficient mills) and crippled horses (outdated, inefficient or mothballed mills). The stable owner isn&rsquo;t about to let the man with the cart slow down his thoroughbred, and the cart can&rsquo;t be pulled by the crippled horses because they have to be put down.&nbsp; &mdash;Ron Kotrba

Splitting Wood into Biodiesel, Pellets

Say the word &ldquo;location&rdquo; three times and you&rsquo;ve basically summed up the No. 1 factor that will allow a bioenergy project to succeed. Placing a facility in the best possible location is much more complex than finding a nice view or having the right neighbors. Typically, the first place to start in the location research process would involve allocating the availability of needed resources such as feedstock or infrastructure, but, if the theory holds that future success &ldquo;is all in the details,&rdquo; then knowing the availability of woody biomass in a 50-mile radius is only the first step down a very long road. Kristi Moriarty, senior analyst for the Center for Transportation Technologies and Systems for the National Renewable Energy Laboratory, and her team at NREL have developed a map to get you there. Of course, the Biofuels Atlas developed by the NREL team can provide information on feedstock availability ranging from corn stover to forest residues, but the atlas, which is linked into Google Maps, and is a compilation of information (when available) from the U.S. DOE, the U.S. EPA and the USDA, can provide much greater detail. &nbsp;&nbsp;&nbsp; Want to know the flex-fuel vehicle density for an area around St. Louis? The atlas can tell you. Want to know the biofuels potential based on a specific feedstock in a specific collection radius? The atlas can provide that information. Or&mdash;and this is where the map is truly an asset to project developers&mdash;if a user wants to understand the energy demands of a particular state, how those energy users are receiving their energy (coal plants, oil refineries, ethanol plants, etc.) and how many gallons of biofuel could be created in that state given the availability of a feedstock like wheat straw or corn cobs, the atlas can do all of that too. If that isn&rsquo;t enough, the map also provides information regarding state-by-state incentives and laws for energy along with the general energy capacity for each state. &nbsp;&nbsp; &ldquo;It gives you an idea of what may be possible,&rdquo; Moriarity says. &ldquo;When you are looking at a map like this, it really starts to highlight some opportunities.&rdquo; While the atlas is somewhat subject to the amount of funding the data sources receive throughout the year, the ability of the atlas to analyze and overlay a number of different aspects like rail lines, methane production sites or even nuclear power plants shows the benefit of the tool that to this point has already received 10,000 views, according to Moriarity. And, in 2012, the plan is to include dedicated energy crop acres on the map. So, hopefully by then, the atlas will provide even more data on available feedstock like the 50,000 acres the USDA has awarded under the Biomass Crop Assistance Program to Missouri and Kansas to establish native grasses and herbaceous plants specifically for bioenergy uses.&nbsp; &mdash;Luke Geiver

Is there anything the Biofuels Atlas can't do? 	

Success is in the Bioenergy Details

Anaerobic digestion systems have long been used to produce methane, a renewable form of natural gas. The microbial communities found in anaerobic digesters, known as undefined mixed cultures, essentially degrade organic materials into chemical precursors that are eventually converted into methane by methanogens, a group of microorganisms found in those undefined mixed cultures. While producing methane through anaerobic digestion systems can be economical in some configurations in the U.S., such as those treating waste water or burning the resulting methane to provide heat and power to a plant or other industrial facility, the economics can be more difficult to manage in other situations; specifically, in situations where the renewable methane is used to create electricity that is fed to the grid. This is economically challenging because the methane used to produce electricity must compete with fossil-based natural gas used to fuel power plants. Low natural gas prices have made it hard for renewable methane to compete economically. However, researchers at Texas A&amp;M and Cornell Universities are developing respective anaerobic biotechnologies that inhibit methane production in undefined mixed cultures. Instead, the cultures produce higher value molecules, known as carboxylates, which are chemical precursors to alkanes found in fuels, such as gasoline and Jet A-1. The resulting carboxylates feature a significantly higher value than methane. According to Mark Holtzapple, Texas A&amp;M professor of chemical engineering, methane is currently valued at approximately $4 per million Btu. In comparison, drop-in biofuels that can be manufactured from carboxylates are worth nearly $20 per million Btu. Terrabon Inc., which is currently working to commercialize a carboxylate platform developed by Holtzapple and his team at Texas A&amp;M, further estimates that methane production results in approximately $80 to $90 of value per dry ton of feedstock introduced into the system, while the carboxylate platform creates between $250 and $400 in value from the same amount of feedstock. Research and Development Holtzapple has been working on developing a carboxylate platform for more than a decade. &ldquo;We wanted to come up with an economical way to convert biomass into fuels and chemicals,&rdquo; he says. &ldquo;In my view, the beauty of this is there is no sterility required and you do not have to purchase enzymes.&rdquo; This significantly reduces the capital costs and operating expenses when compared to many other advanced biofuel production technologies. There are several ways research teams are working to inhibit methane production in undefined mixed cultures, including the use of inhibitors and manipulation of heat and pH in a digester. Holtzapple&rsquo;s team is using a methane inhibitor known as iodoform. &ldquo;It&rsquo;s a methane analog,&rdquo; he says. &ldquo;It has a structure similar to methane. What it does is it binds to the active site of enzymes that release methane and plug them up.&rdquo; Holtzapple and his team built a pilot-scale carboxylate facility on the Texas A&amp;M campus in 2000. The plant can process approximately 100 pounds of feedstock per day. &ldquo;The purpose of the pilot-plant on campus is to go all the way to ketones,&rdquo; he says. &ldquo;We can make a few kilograms of ketones. From that, we&rsquo;ve actually made gasoline and jet fuel. By converting the ketones to alcohols you can covert the alcohols to gasoline and jet fuel.&rdquo; Researchers at Cornell University are working to develop a different carboxylate platform. According to Lars Angenent, an associate professor of environmental engineering at Cornell, his team has been working to develop its technology for approximately three years. To date, some of Angenent&rsquo;s research has focused on studying the microbiology communities found in existing anaerobic digestion systems. Undefined mixed cultures contain thousands of microbial species that work together in a food web, he says, noting his team is interested in learning what types of microbes are in those systems, what they are doing, how they work together, and how the system can be improved. The team recently conducted a study of nine full-scale anaerobic digestion systems treating brewery wastewater. Samples were collected from each system once a month for a year, resulting in 112 samples. According to Angenent, there have been important technological advances in gene sequencing in recent years that have allowed his team to generate 400,000 sequences of a particular gene from the microbes to characterize them. &ldquo;We found about 5,000 different species of microbes in these reactors,&rdquo; he says. &ldquo;They were all working together to treat waste and eventually make methane.&rdquo; The research determined that each of the nine anaerobic digestion systems featured its own unique community structure, which didn&rsquo;t change much over time. Data gathered from the samples was then analyzed with operational data provided by the brewery, which included pH and temperature. The ultimate goal of the study and Angenent&rsquo;s research is to alter microbial communities in a way that inhibits methane production. While the technology developed by Texas A&amp;M features a methane inhibitor, Angenent and his team are working to inhibit methane by adjusting the pH within the digester. A pH of 5.5 has been shown to mitigate methane production by the communities, he says. According to Angenent, pilot-scale evaluations of process could begin within three to four years. Scaling Up While Angenent and his team at Cornell continue to work towards pilot-scale production, Terrabon is working to commercialize the carboxylate production technology developed at Texas A&amp;M.&nbsp; Terrabon, which has exclusive license to the carboxylate platform developed by Holtzapple, is already operating a demonstration-scale plant and has plans to break ground on a commercial facility late this year or early next. The demonstration-scale plant became operational in early 2009, says Terrabon Director and CEO Gary Luce. There are essentially two components to the plant he says: an upstream portion that takes in waste materials; and a downstream process that converts the resulting carboxylates into renewable gasoline and JP8 jet fuel. The facility can take in approximately 40 to 50 tons of biomass material per month. It currently processes food waste collected from a Texas A&amp;M cafeteria, local hospitals and several grocery stores. According to Luce, the carboxylate technology employed by the plant is very similar to traditional anaerobic digestion systems. &ldquo;[In methane production] you basically start with biomass,&rdquo; Luce says. &ldquo;A mixed culture breaks down the biomass [into carbohydrates and sugars] using its own set of enzymes. Then those get further digested into organic acids, and the organic acids ultimately get eaten by methanogens that make methane and CO2. That one step right before the methane is where these organic acids&mdash;or carboxylate acids&mdash;are being produced by this mixed culture. What our process does is it follows that same biological process, which you would find inside a cow&hellip;.What we&rsquo;ve done is create through chemical engineering, process design and optimization [a way to] control temperature, pH, and mixing through fermentation tank design to optimize the maximum yield of these organic acids.&rdquo; That&rsquo;s what the front end of the technology does, Luce explains. &ldquo;Then we effectively convert those acids to salts so we can get them to dissolve in water and separate it out from the mush that is still [in the digester]&mdash;that is the biomass that hasn&rsquo;t been digested,&rdquo; he says. &ldquo;Then we concentrate that down and effectively thermally convert those organic acids into ketones&hellip;From there we use a traditional chemical engineering catalyst to convert those secondary alcohols into gasoline and JP8. The upstream is the biological system and the back end of our system is just a traditional chemistry system. The IP [intellectual property] and know-how is kind of how we think those two systems [work] together.&rdquo; In addition to using additives to inhibit methane production, Terrabon&rsquo;s process also uses a timing mechanism to mitigate methane. &ldquo;It takes awhile for methanogens to organize themselves,&rdquo; he says. &ldquo;We run our system at a very small liquid residence time. Because the system is being flushed so quickly, it&rsquo;s not being held up in there. It actually doesn&rsquo;t give time for the methane to be produced.&rdquo; The scale of the system can also impact methane production. As the anaerobic digestion industry began producing bigger and bigger reactors they found that the reactors would get &ldquo;stuck.&rdquo; In other words, they wouldn&rsquo;t turn the carboxylates into methane. &ldquo;What we&rsquo;ve done is captured some natural tendencies of how systems operate and then wrapped it around chemistry to make renewable fuels,&rdquo; Luce says. Terrabon currently expects to have a commercial-scale system operational by 2013, and already has strong development partners on board. &ldquo;We&rsquo;ve got two large strategic partners invested in us, Waste Management Inc. and Valero Energy Corp.,&rdquo; Luce says. Finding a Home There are several key factors that make the carboxylate platform an attractive biorefining technology. Perhaps most importantly, it is economical. &ldquo;Because it does not require sterility or enzymes, the cost is very attractive compared to other process options,&rdquo; Holtzapple says. The process is also flexible in terms of both feedstock and final products. &ldquo;With the carboxylate platform you can produce almost any base chemical currently made from petroleum or natural gas,&rdquo; he adds. &ldquo;In addition, you can make every basic category of hydrocarbons.&rdquo; Early on in its commercial development, Holtzapple says he expects the technology to take in waste products as feedstock. This includes municipal solid waste and sewage sludge. &ldquo;But, eventually I think it will be scaled up to use energy crops for agricultural residues,&rdquo; he says. There are several operational configurations under which the carboxylate platform may prove economically competitive. While Terrabon intends to construct a new, free-standing plant that will utilize waste feedstock sourced from Waste Management, Angenent notes that there is also potential to co-locate carboxylate production systems with existing biorefineries, where waste biomass and wastewater could be taken in as feedstock. In addition, it may also be possible to retrofit existing anaerobic digestion systems to produce carboxylates rather than methane. Although Angenent notes that standalone plants are likely to be constructed in the future, he thinks co-location strategies would be advantageous. &ldquo;The biggest value for the dollar is if you have a biorefinery concept where you&hellip;get the most value out of the biomass that you have going into a plant,&rdquo; he says. For example, existing wet mill corn ethanol plants typically produce a significant amount of waste water. Feeding that waste into a carboxylate production facility would allow a plant owner to convert waste nutrients found in the water into a biofuel, resulting in a new revenue stream. The carboxylate platform would also allow the resulting clean water to be recycled back into the ethanol plant. With all the potential the carboxylate platform is showing, there is surprisingly little research going into the technology right now. &ldquo;I want to predict that this is going to be a hot topic and a big area, but it&rsquo;s not at this point,&rdquo; he said. The lack of ongoing research in the platform might be tied to the fact that research money for methane production technologies has slowed significantly in recent years, and the two technologies are similar enough that they often get lumped together. A great deal of research interest has been focused on synthetic biology routes to biofuels. &ldquo;There is nothing wrong with that, but I think it is also very scientifically exciting to [develop] new ideas on the same angle with these undefined mixed cultures,&rdquo; says Angenent, noting that he will continue to work to bring more interest to this exciting technology. Author: Erin Voegele Associate Editor, Biorefining Magazine (701) 540-6986 evoegele@bbiinternational.com

Undefined mixed cultures traditionally used to produce methane through anaerobic digestion show potential for creating higher-value carboxylates

An Anaerobic Alternative

On Good Friday more than a year ago, a team of renewable energy investors, lobbyists and lawyers met with 20-plus high-ranking members of USDA for several hours to discuss changes to the USDA&rsquo;s 9003 Loan Guarantee program that offers up to $250 million of guaranteed debt to project developers. The results of those talks, along with more than 4,000 hours of unbilled time, have transformed the overall biorefining outlook from one of &ldquo;could be someday&rdquo; to one of &ldquo;will be soon.&rdquo; By incorporating the changes to the loan guarantee program first offered by the renewable energy all-star team that met with the likes of USDA Under Secretary Dallas Tonsanger and USDA Secretary Tom Vilsack, the USDA has already been able to supplant companies like Ineos Bio, Coskata and Enerkem as biorefinery developers that have already, or will in the next year, break ground and begin construction on their way to advanced biofuels and biobased chemical production. For John May, managing director for Stern Brothers, the brainchild of the revamped loan guarantee program came down to a simple, yet incredibly complex idea: match the reality of the financial markets with a loan program whose entire goal is to provide imperfect applicants with the necessary funding to unleash an unproven technology into a world where off-take agreements, which might mitigate the risk of such commercially unproven technology, are more of a myth than reality. With the help of Mark Reidy, partner for Mintz Levin, Cindy Thyfault, founder and CEO of Westar Trade Resources and John Kirkwood, partner for Krieg Devault, May and his team have singlehandedly shifted the hope for aspiring biorefining project developers away from the cash-strapped, heavily regulated banking atmosphere that had previously hindered the effect of loan guarantee programs like 9003, to what is today a trillion dollar market atmosphere where market players aren&rsquo;t afraid to take on risk and they aren&rsquo;t afraid to pay a lot for it: the bond markets. Now, with the continuation of funding to the 9003 program, future biorefining projects have in place a system that will create an unlimited&mdash;think in terms of trillions&mdash;source of debt financing that can provide the needed capital for projects like Coskata or Enerkem to go commercial, all while feeding the appetite of institutional investors looking to expand their portfolios through the bond market. If you are in the biorefining industry and you aren&rsquo;t familiar with the bond markets and what they could mean to the growth of the industry, then now is the time to learn. Why Bonds? If a person were to sum-up the global economic climate over the past three years, there might be words like &ldquo;bleak,&rdquo; &ldquo;tight&rdquo; or &ldquo;downright impossible&rdquo; to describe the time period. Translate those sentiments into an impact statement on the biorefining industry that is still moving towards commercialization, and the result is an industry strapped by banks not willing or unable to lend the type of money, to the type of unproven clients, that is needed to make a bioprocess worthwhile. &ldquo;The problem with the 9003 program was that it wasn&rsquo;t being used,&rdquo; May says. &ldquo;The reason for no use was that the program was designed to use commercial banks as the so-called lender of record, and the commercial banks did not have the liquidity or the risk appetite to be involved in transactions of renewable energy that presented technology risk and off-take risk.&rdquo; In the wake of the subprime crisis and the credit crunch May says of the banks, &ldquo;they couldn&rsquo;t take the risk.&rdquo; But, the near-term economic climate isn&rsquo;t the only factor to blame for the 9003 program&rsquo;s lack of effectiveness. &ldquo;A lot of the problems with the 9003 program were not something that was intentionally created by the USDA as a roadblock,&rdquo; May says. &ldquo;It was simply a holdover of an earlier era when small farm loans and agribusiness loans were made on very simple projects,&rdquo; and most importantly, he adds, &ldquo;I don&rsquo;t think that when those regulations were put together that anyone thought the same sorts of regulations would be used by large biofuels projects with extremely complex technology and equipment.&rdquo; This technology and equipment also comes with a steep cost per project, May adds. With the help of other industry experts, May set out to change the landscape for the loan guarantee program. &ldquo;I was trying to bring the 9003 program up to date and make it consistent with reality of not only the renewable energy market, but also the financial market,&rdquo; he says. The team&rsquo;s answer was the bond market. Why? A bond is another form of borrowing. The money, instead of coming from the bank, comes from investors like mutual funds, life insurance companies or pension funds looking to invest. The market has been around for roughly 150 years according to May, and in the market &ldquo;there are many, many investors.&rdquo; Those investors are looking for several things, many of which coincidentally are provided by a USDA 9003 Loan Guarantee&rsquo;s successful applicant. For one, a bond investor typically has the financial ability to invest large chunks of money into a particular investment because of the size of the investor&rsquo;s institution. This means that investors can invest in several areas and take on more risk if so desired. Second, unlike a bank-based lender, a bond-holder wants a long-term, 15-plus year lifespan for the senior debt (loan) in the hopes of earning more interest over time. Time will tell if the new set-up is perfect for the biorefining industry, but so far, it seems that way. Typical project developers are seeking high amounts of cash to start a project, upwards of $100 million, amounts that the bond market can easily provide. Those project developers, however, can&rsquo;t justify taking out a five- to seven-year loan with unfixed interest rates equaling double digits. &ldquo;It&rsquo;s not like the old days when you had a grain plant with a crush margin of $2.50 to $3 because of the disparity of the price of grain that was so low and the price of fuel which was so high,&rdquo; Mark Reidy says, &ldquo;where the guys would take that and pay off their plants within two years or sooner.&rdquo; He adds, &ldquo;You aren&rsquo;t going to see that anymore, so guys will want to amortize them as long as they can.&rdquo; As May says, somebody has to own these projects, &ldquo;but they aren&rsquo;t going to do it if they can&rsquo;t make any money.&rdquo; A more realistic, or at least better, situation allows those developers to spread out the debt over time, to know beforehand what the interest rate on that debt will be, and, to pass off some of the risk of investing in a unproven technology with no contracted end-user, refiner or oil company to start with. Because the bond markets can offer a fixed interest rate on more than three-fourths of the loan, and the USDA can guarantee that more than three-fourths of the loan will be covered by the U.S. government in the event that a project goes belly-up, the bond financing mechanism in the new 9003 program looks, if nothing else, pretty good. Essentially, the bond market offers an alternative for financing. And if one looks at the numbers, considering how willing the banks have been, it is a welcomed alternative. Bond Numbers The most important number to remember about the 9003 program is really more about the ranking of the rating that the bonds created by the project developer will equal. Reidy says the bonds guaranteed by the USDA will be Triple AAA rated, or in bond rating terms, the best. The bonds earn that rating directly from the presence of the loan guarantee, which in effect acts as a major credit enhancer, and qualifies the bonds as investment grade. The current system can be seen in this example. Consider an advanced biorefinery developer is awarded a $100 million loan guarantee from the USDA under the 9003 program. Through the system, 80 percent (or $80 million in this case) of the loan request will be guaranteed. The other 20 percent (or $20 million) will not be guaranteed. Because the USDA is guaranteeing 80 percent of the $100 million, bond holders will be willing to accept a lower coupon rate (interest rate) on the $80 million, somewhere around 5 percent. But, as Reidy explains, do to the reality that the bonds are financing an unproven technology (this is where the reality of the applicants come into play), the bond holders will be seeking a much higher coupon rate for the 20 percent of the loan that is not guaranteed, a rate that could be anywhere from 10 to 15 percent. But, because the interest rates are blended together, the project developer will ultimately end up with the money needed to construct a facility at an interest rate between 8 and 10 percent spread out over a 20-year period. Thyfault explains that the bond financing system inherently brings three major positives to the lender and two major benefits to the borrower. For the lender, she says, they can make more loans. Under the bond approach she also says a lender only has to carry 5 percent of the unguaranteed portion, the rest the lender can sell on the bond market, which allows the lender to expand a portfolio and take on less risk. Second, the lender, unlike a bank, does not have to go through syndication (or work with more banks) because the bond holders are the syndicates. And third, in the past when the unguaranteed portion of the loan was difficult for a bank to participate in, &ldquo;the unguaranteed portion of the loan is readily accepted by the bond market.&rdquo; For the borrower, the advantages are related first to the length of the term of the issued bonds. And second, the borrower can typically see an interest rate for a bond that can be less than a bank loan, the result, she points out, &ldquo;is a long-term, low-cost interest rate for the borrower.&rdquo; All four of the applicants that received USDA loans in 2010 used the bond financing approach, May says, and in doing so they helped prove May&rsquo;s idea to revolutionize the way projects financed with a loan guarantee can work. The situation used to be one where, as May says, an applicant&rsquo;s credit was good enough and the bank would do the deal, or the credit was not up to par and the deal was dead, but now has changed to a situation under the bond financing approach where &ldquo;we can find a way to get the deal done,&rdquo; a deal, he says, that is just a matter of how high the interest rate will be on the unguaranteed portion of the loan. And even with four deals already done for biorefining developers earning loan guarantees, the most significant part of the new bond financing approach may be more linked to what hasn&rsquo;t happened yet. &ldquo;We filed four applications last year and receive four loan guarantee awards,&rdquo; he says, &ldquo;and we have half a dozen that we intend to file for in 2011.&rdquo; And that, he says, is just his all-star team. Reidy, who says nothing like this has ever truly been done before, is also excited about the potential for this type of renewable energy financing for foreign investors and other countries that his group has already spoken to, including China, India and several countries from Europe. &ldquo;As long as we have a loan guarantee or something as good to credit enhance the bonds, because you have to credit enhance them to make them palatable for the institutional investors to buy them,&rdquo; he says, &ldquo;we can do these projects of any type offshore.&rdquo; From Reidy&rsquo;s perspective, he could be putting together these types of deals for the rest of his career, and from May&rsquo;s, the process has been rewarding to see an idea turn into reality&mdash;a reality it seems that will affect anyone who consumes energy in a sustainable way. Author: Luke Geiver Associate Editor, Biorefining Magazine (701) 738-4944 lgeiver@bbiinternational.com

Bond financing is here—and all signs point to a perfect match 

Transforming Financial Reform

St. Louis is not only the Gateway to the West, it also acted as the gateway to the future of the biomass industry in May as nearly 1,400 professionals representing all aspects of the sector descended upon its America&rsquo;s Center conventional hall to network, conduct business and learn about recent technological and agronomic breakthroughs. A highlight of the event was the Tuesday morning plenary session, titled Association Executive Roundtable: Our Industry in a Changed Political Landscape. Leaders of seven biomass trade associations shared the stage during the session, discussing policy objectives, cooperation strategies and methods to overcome common obstacles. Those participating in the discussion included Algal Biomass Organization Executive Director Mary Rosenthal, Biomass Thermal Energy Council Chairman Charlie Niebling, Biomass Power Association President and CEO Robert Cleaves, American Biogas Council Vice Chair of External Affairs Norma McDonald, Renewable Fuels Association President and CEO Bob Dinneen, National Biodiesel Board CEO Joe Jobe, and Advanced Biofuels Association President Michael McAdams. While different segments of the biomass industry have, at times, unintentionally worked against rather than with each other, the tide seems to be shifting. In fact, McAdams commented on how far the organizations represented in the panel had come in a single year, noting that many cooperative policy efforts between the organizations were a direct result of a similar session at last year&rsquo;s 2010 International Biomass Conference &amp; Expo. Today, organizations like the ABFA, NBB, RFA and BIO are working together to support areas of common policy goals and objectives. Near-term Objectives To open the panel, each association leader provided the audience with an overview of its respective near-term policy goals. Rosenthal kicked off the discussion by stating the ABO will continue to push to achieve parity for the algae industry with regard to tax credits. &ldquo;[The algae industry] receives no fuel credits at this point in time,&rdquo; she said, noting that it is imperative algae-based fuels are eligible for the same tax incentives that cellulosic fuels and other advanced biofuels qualify for. &ldquo;The other key with this 112th Congress is education,&rdquo; Rosenthal continued. There is a continual need to educate federal lawmakers on the energy security benefits and advantages of algae-based fuels. According to Rosenthal, the ABO will also continue to advocate for continued renewable fuels funding through the U.S. DOE, USDA and the U.S. Department of Defense. While the RFA also has plans to focus on educating members of Congress, Dinneen stressed that his organization must also work to maintain certainty for the ethanol industry. &ldquo;It&rsquo;s not that we don&rsquo;t support parity&mdash;we do&mdash;but, we&rsquo;re looking at a situation where our tax incentive expires at the end of this year,&rdquo; he said. &ldquo;When the tax incentive was extended [last year] it was made clear by friend and foe alike that going into the future there needs to be a fairly significant meaningful reform of that tax incentive. That&rsquo;s what we&rsquo;ve been working on.&rdquo; According to Dinneen, the RFA is working to reform some of the existing incentives in a way that reflects the fact that the ethanol industry has grown. &ldquo;There needs to be a fiscally responsible approach to this that will allow the industry to continue to grow, and more important to evolve,&rdquo; he added. Extending tax incentives is also a primary goal of the NBB, Jobe said. &ldquo;Our top priority is successful implementation of the RFS2, and a big part of that is extension of our tax credit in order to help buffer the cost of compliance and get this program more mature,&rdquo; he said. &ldquo;It&rsquo;s going to be very difficult given the focus on debt reduction in this Congress, but we believe that we&rsquo;ve got a good chance&hellip;Our tax credit is a quarter of a century younger than the ethanol tax credit. We just need a little bit more time to get a little bit more mature.&rdquo; Responding to a question posed by a member of the biomass industry regarding speculation that some members of the biodiesel industry would prefer to see the credit lapse, Jobe reiterated that extending the biodiesel tax credit is the No. 1 goal of the NBB. He elaborated by explaining 2011 is the first full implementation year of the RFS2 program. &ldquo;Really, this is the first year&mdash;and the only year&mdash;we&rsquo;ve ever had the tax credit and the RFS2 working in tandem,&rdquo; he said. &ldquo;And guess what? It works.&rdquo; In addition to helping to increase the favorability of blending economics, Jobe also noted that the tax credit also plays an important role in driving investment in next-generation feedstocks, such as algae. Although many of the association leaders taking part in the panel spoke about policy goals, McAdams said the primary goal of ABFA members is to get plants built. &ldquo;The number one objective of the advanced and cellulosic industries is to deploy new technologies to build new plants&mdash;put steel in the ground,&rdquo; he said. One policy element that McAdams said could help support this objective would be for federal lawmakers to alter the fuel procurement requirements of the U.S. military in a way that would allow the formation of long-term off-take agreements. &ldquo;What we are really trying to do is deploy these technologies,&rdquo; McAdams said. &ldquo;If we could extend the procurement process, particularly with the Department of Defense, by extending the period of time in which the military can buy renewable fuels or jet, for instance, that would be enormously helpful.&rdquo; New Sectors, Old Debates Industry leaders who participated in the panel also briefly discussed recent energy-related environmental disasters, such as Japan&rsquo;s nuclear crisis and the oil spill in the gulf. These events did not spur a significant, widespread public demand for renewable technologies, and seem unlikely to do so in the future. There has also been a noticeable lack of renewed political support for renewable sources of energy following these disasters. &ldquo;I think it&rsquo;s just a reflection of the dysfunction that is the United States Congress today,&rdquo; Dinneen said. &ldquo;Congress does not do thoughtful policy on much of anything. It reacts to negative events, they give speeches, there is a lot of fervor but not much that really happens as a consequence. Biofuels are not radioactive; they are not going to degrade the ecological system of the Gulf of Mexico; you don&rsquo;t need a no-fly zone for biofuels and bioenergy, and yet trying to get members of Congress to focus on the importance of growing these domestic clean energy supplies has been a real challenge,&rdquo; he said. &ldquo;There are entrenched, powerful, well-healed interests that like the status quo. We have to accept that, but we also need to figure out what we can to do change it. It doesn&rsquo;t happen overnight, and it doesn&rsquo;t happen because of a catastrophic event. You have to build support for these clean-burning energies. It takes time. We will this week&mdash;on average&mdash;top $4 a gallon gasoline. If that&rsquo;s not a clarion call for doing more to extend our domestic energy supplies, I don&rsquo;t know what would be.&rdquo;
The panelist also addressed the food vs. fuel debate. While on the surface it may seem as though second- and third-generation biorefining industries should be immune to the issue, Dinneen cautions the ABO and others to be wary. &ldquo;You need to take a much more educated and robust look at what is really driving food price inflation and then you need to consider that the food vs. fuel debate isn&rsquo;t about food; it&rsquo;s about land,&rdquo; Dinneen said. &ldquo;As soon as there is land that is being used to produce algae, if [that land] could be used to produce a food crop [the debate will focus on algae]&hellip;I think we all have a responsibility right now to make sure that this debate doesn&rsquo;t continue to undermine the growth and evolution of our industry.&rdquo; According to Dinneen, the food vs. fuel debate has focused nearly exclusively on corn ethanol to date because it was the first biofuel to achieve commercial success. That will change as other forms of biofuel find increasing success. A Look Ahead RFS2 was also a hot topic addressed by the panel. Dinneen noted that he doesn&rsquo;t think the U.S. EPA has done a particularly stellar job implementing the program, specifically when it comes to some areas of congressional intent around carbon scoring. &ldquo;They&rsquo;ve [also] been overly restrictive on feedstocks,&rdquo; he said. &ldquo;They&rsquo;ve been very slow to certify some of these new pathways, and when they&rsquo;ve done it, they&rsquo;ve done it in a way that almost defines some of these technologies out of existence before they get going.&rdquo; However, Dinneen also noted that the agency can&rsquo;t be faulted for lowering the cellulosic targets within the RFS2. &ldquo;The RFS was never intended to be something that cellulosic companies could take to the bank to help them gain financing,&rdquo; he said, noting, however, that the targets do create an important market lenders should consider. McAdams also spoke about the reduced cellulosic targets under RFS2. It was very significant that the agency shifted the cellulosic volumes into the advanced biofuel pool rather than reducing the volume targets as a whole. &ldquo;That is verification that they believe that biodiesel and renewable diesel and advanced fuels are going to fill that number for the advanced pool,&rdquo; McAdams said. &ldquo;That looks good going forward.&rdquo; In addition, McAdams stressed the importance of EPA moving forward to certify new feedstocks, molecules and pathways in a swift, efficient manner. &ldquo;EPA needs to get in place&hellip;the [regulations] that allow these feedstock processes and products to be compliant with RFS2,&rdquo; he said. &ldquo;That is a key mission for them in the next six to eight months.&rdquo; During the panel discussion, McAdams also responded to a question posed by a member of industry regarding possible competition between biofuel and biochemical producers for investment funds. McAdams stressed he disagreed with the assertion that the financial and investment communities are showing a reluctance to support the developing advanced biofuels industry while support for biochemical is flowing exclusively from traditional chemical companies. &ldquo;I would suggest to you that biobased chemicals and biofuels go hand in hand&mdash;particularly with a lot of the synthetic biology companies,&rdquo; McAdams said. &ldquo;What they may be able to do in the short-term is actually make a chemical that will make them profitable to where they can get the funding to do the fuel following the chemical.&rdquo; Furthermore, McAdams noted that several ABFA members have completed highly successful IPOs in recent months. &ldquo;What you are beginning to see with those technologies that have really done their R&amp;D and have really done their homework, you are beginning to see private capital fly in to give them the wherewithal to build commercial facilities,&rdquo; McAdams continued. &ldquo;All those companies have models in conjunction with fuels and chemicals. I think they leverage each other. It&rsquo;s very similar to our current refining chemical structure and I think you&rsquo;ll see more of it, not less of it.&rdquo; Author: Erin Voegele Associate Editor, Biorefining Magazine (701) 540.6986 evoegele@bbiinternational.com

Industry leaders take the stage at the International Biomass Conference to discuss policy objectives and collaboration opportunities

Gateway to Cooperation and Parity

Imagine that your biofuels company had decided to establish business operations in Japan. Your first decision would be whether to appoint an independent consultant or to hire an employee in Japan to help expand your business. Which one should you choose? In the event that your company decided to appoint an independent consultant to help expand your business in Japan, be careful to structure the relationship such that the independent consultant would not constitute your &ldquo;permanent establishment&rdquo; in Japan. Under Japanese tax law, a permanent establishment of a foreign company in Japan subjects that company to corporate income tax in Japan based upon the revenues generated by and attributable to the company&rsquo;s permanent establishment in Japan. In order to ensure that your independent consultant would not be considered a permanent establishment under Japanese tax law, several guidelines must be followed. Your independent consultant should be a corporation, not an individual.&nbsp; Your company would enter into an agreement with the corporation to expand business in Japan on your behalf. The corporation would, in turn, hire an individual to perform these tasks. Your independent consultant would not have authority to bind you to any obligation whatsoever. It would not have the authority to sign contracts on your behalf in Japan. It could, however, assist you in negotiating business deals and in discussing the terms of contracts with potential customers in Japan. You would pay your independent consultant in the form of commissions, not in the form of a standard monthly (or annual) consulting fee. If your independent consultant were paid in the form of a standard monthly (or annual) consulting fee, the consultant might be considered a &ldquo;standing agent&rdquo; under Japanese tax law, which would constitute your company&rsquo;s permanent establishment in Japan and subject you to corporate income tax in Japan. In the event that your company decided to hire an employee in Japan, the employee would, under almost all circumstances, constitute your permanent establishment in Japan, which would subject your company to corporate income tax in Japan based upon the revenues that are generated by and attributable to that employee. You would also be required to pay U.S. corporate income tax on the revenues generated by and attributable to the employee in Japan because the U.S. taxes its corporations on their worldwide income, regardless of where it is earned. However, under the Convention between the U.S. and Japan for the Avoidance of Double Taxation and the Prevention of Fiscal Evasion with respect to Taxes on Income, which entered into force on July 9, 1972, you would be entitled to receive a partial tax credit in the U.S. for the corporate income tax paid in Japan. This would, to a certain extent, relieve the double taxation imposed upon your company by virtue of having an employee in Japan. In addition, your employee in Japan would be entitled to all of the rights and safeguards accorded to employees under Japanese labor laws. Your employee would be entitled to participate in the Japanese National Health Insurance Plan and the National Welfare Pension Plan, and your company would be required to enroll in such plans. The payment of the premiums for such plans would be shared equally by your company and your employee in Japan. Your employee would be entitled to participate in the Japanese Worker&rsquo;s Compensation Insurance Plan, and you would be required to pay the entire cost of the premiums for such plan. They would be entitled to participate in the Japanese Unemployment Insurance Plan, and you would be required to pay 75 percent of the premiums while the employee would be required to contribute the remaining 25 percent. Your employee would be entitled to receive between 10 and 20 days of paid vacation per year and approximately 25 days of paid holiday time per year. Japanese companies usually give their employees both winter and summer bonuses, which are equal to 3 months&rsquo; salary each. You could not unilaterally change the terms of the employment contract between your company and the employee, especially if such changes were detrimental to the employee. You could not unilaterally terminate the employee&rsquo;s employment unless you had &ldquo;just cause&rdquo; to do so. Just cause is narrowly defined under the Japanese labor laws and involves more than simple misconduct or negligence. You would have to show that the employee engaged in serious misconduct or that the employee repeatedly and systematically performed poorly in the execution of his duties. The standards of performance expected of the employee would have to be articulated in his employment contract, and written warnings would have to be issued to him if he failed to meet the performance standards. The employee would also have to be given a period of time within which to improve his performance after you had issued warnings to him before you could terminate him for just cause. Branch Office or Subsidiary? In the event that your company decided to hire an employee in Japan, your company would be required to establish a Japanese registered branch office or a Japanese subsidiary in which the employee could work. In order to establish a registered branch office in Japan, you would have to appoint a registered representative who would be deemed to have the power and authority to represent the branch office. Your representative would have to be a resident of Japan but would not need to be a citizen of Japan. You would have to register the branch office&rsquo;s place of business and its representative with the appropriate government authorities in Japan. An &ldquo;initial inward direct investment&rdquo; report containing details about your company and business objectives would also have to be submitted. Any claim or cause of action against the registered branch office or any risk or liability of the registered branch office would be considered to be a claim or cause of action against or risk or liability of your company in the U.S., since the registered branch office would be considered to be an extension of your company into Japan. The registered branch office would be taxed in Japan only on the income that it generated from sources in Japan.&nbsp; As indicated above, you would be taxed in the U.S. on the income generated by the registered branch office. However, under the U.S.-Japan Income Tax Treaty, you would be entitled to receive a partial tax credit in the U.S. for the corporate income tax that the registered branch office paid in Japan. In the event that your company decided to establish a subsidiary in Japan, you would probably form a Japanese limited liability company (known as a &ldquo;Yugen Kaisha&rdquo;). In order to establish an LLC in Japan, you would be required to file an Application for Commercial Registration for the new subsidiary. You would also have to submit an &ldquo;initial inward direct investment&rdquo; report containing details about your company and business objectives in Japan. Furthermore, you would be required to file a report after you acquired shares in the subsidiary, which would describe the type, purchase price and amount of the shares purchased by your company.&nbsp; You would have to file various tax reports with the Japanese national and municipal tax authorities regarding the subsidiary. Finally, you would be required to make an initial capital investment in the subsidiary of at least 3,000,000 yen ($37,000). You would have to elect directors to serve on the subsidiary&rsquo;s board of directors, and the directors would appoint the officers of the subsidiary. The directors on the board of directors of the subsidiary would have general supervision over the business operations of the subsidiary, and the officers of the subsidiary would be responsible for the day-to-day operations of the subsidiary. Any claim or cause of action against the subsidiary or any risk or liability of the subsidiary would be limited to the subsidiary and its assets, and would not be considered to be a claim or cause of action against or risk or liability of your company in the U.S., provided that the subsidiary was properly incorporated and operated in compliance with Japanese commercial laws. As a domestic Japanese company, the subsidiary would be taxed in Japan on its worldwide income. In addition to Japanese corporate income tax, local enterprise tax and corporate residence tax would also be imposed upon the subsidiary. The combined rate of tax on the subsidiary would be approximately 41 percent. As indicated above, you would be taxed in the U.S. on the income generated by the subsidiary. However, under the U.S.-Japan Income Tax Treaty, you would be entitled to receive a partial tax credit in the U.S. for the corporate income tax that the subsidiary paid in Japan. A withholding tax would also be imposed upon your company on the issuance of dividends to your company from the subsidiary. The rate of such withholding tax would be 10 percent. Establishing business operations in Japan requires careful strategic planning and an in-depth understanding of the Japanese corporate, tax and labor laws. Depending upon your business objectives, you may wish to appoint an independent consultant or hire an employee in Japan. Your decision will have significant business, legal and tax consequences as you attempt to expand your business activities in Japan. Author: Richard Weiner Vice President, Fredrikson &amp; Byron (612) 492-7009 rweiner@fredlaw.com

Understanding customs and laws is critical to opening business overseas

Establishing Business Operations in Japan

It is still anyone&rsquo;s guess what the impact of boiler and environmental regulations will be on U.S. coal-fired power plants. But that isn't stopping the biomass industry from making preparations for eventual plant retirements or retrofits involving cofiring.
 According to a study by The Brattle Group, emerging U.S. EPA regulations on air and water quality could result in a reduction in electricity-generating capacity of more than 50,000 megawatts due to coal plant retirements.
 Of course, there are conflicting estimates of just how much electrical capacity is at risk, but there will no doubt be some reduction.&nbsp; &nbsp;&nbsp;&nbsp;
 After reading the features for this month&rsquo;s magazine, I&rsquo;m convinced that the biomass industry understands the potential for biomass cofiring at coal plants and several companies are trying to come up with solutions to make the transition as seamless as possible.&nbsp;
 The bottom line is that cofiring biomass and coal can be done. But it can&rsquo;t be done overnight and it may take some trial and error to eventually come to the right balance of feedstock and the right assemblage of equipment.

2011/08/13141110815174.jpg

The Quest to Make Cofiring as Seamless as Possible 

The first week in August, the U.S. Energy Information Administration unveiled a long-awaited study, called &ldquo;Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010.&rdquo; The report promises to be controversial. Already, various renewable trade associations have charged that the report fails to accurately capture subsidies for the oil and gas sector, which will in turn claim that the total support for all renewables&mdash;estimated to be $28.5 billion since 2009&mdash;is not affordable in an age of fiscal austerity. We have a slightly different take.
 A closer look at the report reveals the profound disparity among renewable technologies.
 Let&rsquo;s start at the 30,000-feet level. The U.S. Department of the Treasury&rsquo;s 1603 program, enacted in 2009 as part of the Obama stimulus package, provides a cash payment in lieu of an investment tax credit (ITC) equal to 30 percent of the cost of a project. Since September 2009, treasury has paid out a total of $7.78 billion to 3,159 renewable projects. Of that total, $5.6 billion was spent on wind, and another approximately $1 billion on solar. Biomass, on the other hand, received approximately $115 million&mdash;or 1 percent of the 1603 dollars&mdash;funding only a handful of projects. Geothermal (at 1.7 percent), and hydropower (1.8 percent) didn&rsquo;t fare much better. The authors overlooked waste to energy, but we suspect the numbers would be the same.
 In other words, this means that 1 percent of the money was spent for a renewable energy that represents 50 percent of the nation&rsquo;s renewable supply, while about 85 percent of this grant funding went to sources that account for only 10 percent of the nation&rsquo;s renewable energy supply.
 So what&rsquo;s going on here? Do baseload sources of renewable energy have a future? After all, according to EIA, annual growth from 2000 to 2010 was downright anemic for some (geothermal grew by only 1.3 percent), while biomass actually lost ground (-0.7 percent) along with hydroelectric (-0.75 percent). Will the future of federal renewable energy tax benefits (assuming there is a future) be skewed to solar and wind (the latter growing 31.8 percent), which admittedly play an essential role, to the extent that they essentially edge out baseload sources of renewable energy?
 The EIA study is the best evidence yet of what happens when Congress creates a tax code that results in an unlevel playing field across renewable technologies. How unlevel? For starters, biomass, hydro and waste-to-energy facilities are only allowed 50 percent of the value of the production tax credit (PTC) compared to other renewables, with absolutely no public policy reason. Second, the code favors technologies with more immediately achievable &ldquo;placed in service&rdquo; dates. Remember that in order to qualify for the PTC or ITC, a biomass facility must be placed in service by Dec. 31, 2013. Given that typical biomass plants take easily five years to develop and construct, there is no certainty that projects developed now could qualify for the benefit. As a result, the code favors projects with shorter development horizons. This explains in part why so few biomass projects are qualifying for federal benefits.
 For starters, Congress needs to provide tax equity across all renewables by enacting H.R. 2286, the Renewable Energy Parity Act. Second, BPA joins other renewable associations in advocating for the extension of the 1603 program, but an extension alone will not correct the inequities of the code. Enactment of a longer placed-in-service date window is essential if biomass is to realize its full potential in this country. Author: Bob Cleaves President and CEO, Biomass Power Association <a href="http://www.USABiomass.org">www.USABiomass.org</a>

2011/08/13141113021879.jpg

Looking at the Bigger Energy Subsidy Picture

When the Biomass Thermal Energy Council was founded in 2009, federal and state policy makers barely understood the potential of making heat from biomass to meet our nation&rsquo;s lofty energy goals.&nbsp;
 Early forays by BTEC leaders into congressional offices were met with blank stares. State energy and climate plans overlooked this energy pathway. If it wasn&rsquo;t about making electricity or a liquid transportation fuel, it did not merit consideration in policy platforms such as state renewable portfolio standards (RPS) or federal renewable fuel standards.
 After years of persistence by BTEC and activists, this is changing. Every day I see indications that heating and combined heat and power (CHP) with biomass is increasingly being viewed as a wise component of America&rsquo;s broader renewable energy strategy.&nbsp;
 Take the Northeast, for example. In the past six months, biomass heating has moved forward on several fronts:
 &bull; In Massachusetts, the Mass Clean Energy Center recently funded a comprehensive analysis of renewable heating options. This study is under way and includes biomass thermal. The expectation is that the findings and conclusions will form the basis of new policies and incentives.
 &bull; In Massachusetts, activist efforts by the Northeast Biomass Thermal Working Group led the state legislature&rsquo;s Joint Committee on Telecommunications, Utilities and Energy to issue a critique of RPS changes calling for a strong look at policy favoring high-efficiency biomass thermal.
 &bull; In Vermont, Gov. Peter Shumlin enthusiastically endorsed using state Regional Greenhouse Gas Initiative funds to support a rebate program for high-efficiency biomass heating appliances. That program is now moving forward.
 &bull; In Vermont, activists responding to a NEBTWG action alert sent letters to state officials developing a Comprehensive Energy Plan to incorporate stronger consideration of biomass thermal.
 &bull; In New York, the New York State Energy Research and Development Agency announced a funding opportunity that will provide grant support for high-efficiency, low-emission commercial-scale biomass heating technology. Details will become available in September. NYSERDA also announced that it will issue a request for proposals to conduct a statewide biomass heating roadmap strategic planning effort; details will come out in October.
 &bull; In Pennsylvania, industry activists have come together to revitalize the Pennsylvania Biomass Energy Association with a more focused mission &ldquo;To promote and support the use of sustainable biomass feedstocks for heat and/or CHP applications.&rdquo; More than 50 member companies attended an initial strategic planning meeting.
 &bull; In Maine, industry activists with the Maine Pellet Fuels Association led an effort to change state regulations to allow solid fuel combustion to utilize the same chimney flue as fossil fuel combustion, a major regulatory barrier to widespread use of high-efficiency biomass in homes.
 &bull; In New Hampshire, legislation to provide renewable energy certificates for thermal output from biomass CHP is moving forward. It was also the only state to use stimulus funds to finance a residential rebate for high-efficiency biomass boilers. And the state&rsquo;s Public Utilities Commission is evaluating how to include thermal renewables in a revision of the state&rsquo;s RPS, with recommendations due in the fall.
 &bull; Finally, in September NEBTWG issued a &ldquo;call to action&rdquo; to Northeast governors and congressional delegation calling for inclusion of biomass thermal in incentive programs, state energy plans and the federal tax code. Representatives of nearly 400 businesses, agencies and organizations signed the letter.
 Individually, these actions represent small but incremental evidence that biomass thermal is gaining momentum. Collectively, they demonstrate an unstoppable movement toward recognition that biomass thermal represents a hugely overlooked renewable resource.&nbsp;
 Further indication can be found in the formation of the Midwest Biomass Thermal Working Group, with a conference being planned in the north-central states for 2012.&nbsp; And, with support from the USDA Forest Service Wood Education Resource Center, BTEC hosted seven webinars with nearly 2,000 participants on a range of topics related to biomass thermal.
 The biomass thermal community is not waiting for Washington to hand down progressive energy policy.&nbsp; Rather, we are making progress one community, one state and one region at a time&mdash;through innovative private/public partnerships. I have confidence that these efforts will build strength, and this most renewable resource&mdash;biomass&mdash;will be restored to its once prominent place in meeting our nation&rsquo;s thermal energy needs. Author: Charlie Niebling Chairman, Biomass Thermal Energy Council <a href="http://www.biomassthermal.org">www.biomassthermal.org</a>

2011/08/13141114656968.jpg

Progress on the Biomass Thermal Front

Biomass &rsquo;11 was held for the ninth time in Grand Forks, N.D., on July 26&ndash;27. The 250 participants from 26 states, Washington, D.C., and 11 foreign countries were provided with an eye-opening revelation: biomass industries are going to have to compete hard with other energy industries over the next few years. Of course, anyone associated with biomass utilization in the past decade knows that it is no easy task to produce renewable energy, fuels or chemicals from plant or animal matter. An overriding theme seemed to be that the United States just doesn't have the impetus and incentives for biomass to thrive, but research and demonstration are an absolute must to position biomass technologies into competitive niches.
 Gerald Groenewold, director of the Energy &amp; Environmental Research Center, kicked off the event and extended gratitude to the major sponsors of the event: his institution, the EERC; the North Dakota Department of Commerce; and the U.S. DOE. Groenewold stated clearly that game-changing biomass research at the EERC began with pioneering support from U.S. Sen. Byron Dorgan more than a decade ago. This led to critical advances such as 100 percent renewable jet fuel, distributed-scale biomass gasifiers and renewable ammonia fertilizer. As important as these types of advances and many others are, the toe-to-toe ability for biomass technology to compete in U.S. markets is still lacking. Biomass industries need to be patient and continue to find those competitive or complementary niche markets. EERC research is all about finding those commercial footholds.
 One of the niche areas that has some competitive assistance in North Dakota was described by N.D. Gov. Jack Dalrymple. Dalrymple described North Dakota as the ethanol blender pump capital of the world &hellip; per capita, that is. Adding to the U.S. picture on incentivizing biomass, Corinne Valkenburg from the DOE Office of Biomass spoke of the tremendous investment by the federal government to spur viable technologies in producing biofuels and the grants and loan guarantees that have been provided for small commercial demonstrations.
 Margo Shaw, a senior biologist with Golder Associates Ltd., in Winnipeg, Manitoba, Canada, reiterated the theme of niche opportunities in the United States but showed that many other places around the world have tremendous incentives that provide for greater biomass promotion. Her statistics showed only 1 to 3 percent biomass electricity in the United States, with a predicted growth of 3 percent in the next 20 years. In contrast, European policies such as a 20 percent renewable energy directive, feed-in tariffs that guarantee renewable energy access to the grid at higher prices, grants and loans, and other tax incentives have created a thriving business environment, at least for biobased power and heat generation.
 With too many technical presentations to mention, this year&rsquo;s program emphasized development and processing of biomass feedstocks. Varieties of methods were reported to chop, shred, pelletize, bale or liquefy using a method called fast pyrolysis. Fast pyrolysis uses low-oxygen heating of lightweight, low-density biomass to convert it to a mostly watery mix of low-grade organic tars and acids, with 10 to 20 percent each of char and gaseous matter. I have always liked the fast-pyrolysis process as an on-farm method of densifying straws and agricultural residues, so the work presented was quite encouraging.
 In summary, it was quite apparent that biomass industries are indeed up for the fight: ready to go head-to-head in hard competition with fossil energy to at least carve out a significant role in America's diverse future energy portfolio. Author: Chris Zygarlicke Deputy Associate Director for Research, &nbsp;Energy &amp; Environmental Research Center (701) 777-5123 <a href="mailto:czygarlicke@undeerc.org">czygarlicke@undeerc.org</a>

2011/08/13141115578043.jpg

Biomass '11 Delivers a Stunning Update

Biomass cofiring with coal is a great idea. Biomass cofiring is a technology that is readily available, energy plant improvements are often minimal, and feedstock is abundant and often low cost. It also helps lower CO2 emissions, sulfurous gases and other harmful gases. As a supplier of biomass feedstock for cofiring systems, these are surely at the top of your sales benefit list.
 But, when you are working on the sale, be aware of the risks and how they may impact your bottom line. Obviously, the cost of the biomass is a large issue. Make sure the price you quote your buyer is one you can manage during the life of the contract. If you don&rsquo;t control the biomass, strongly consider trying to get a variable pricing structure from your customer so you are not squeezed between escalating costs on one side and a fixed sales price on the other. Think of this as well for other variable costs, specifically fuel if you have to deliver the feedstock. I had a plant client who had a fixed-price contract for feedstock, but not long after the contract started, the feedstock provider demanded more money because diesel fuel costs were rising. There was no provision in the contract for variable fuel costs and it created significant difficulties for the supplier, ultimately costing them the contract and their company. If you can&rsquo;t get variable pricing for feedstock or key inputs, carefully consider your cost and pricing model so that you can survive reasonably expected changes.
 Think also of biomass quality. Cofiring systems require the biomass to have certain moisture content, size, ash content and other quality issues. Not long ago, a renewable energy company with a biomass gasifier had serious difficulties due to feedstock quality issues and ultimately shut down the gasifier because it would not work on anything but high quality and expensive biomass. Know up front what your customer will need and make sure that the contract provides for that.&nbsp;
 Consider what happens if you cannot supply acceptable feedstock. Usually, the customer can cancel or suspend the contract and find an alternative source. Sometimes however, when a customer has penalty clauses in their power purchase agreement or would otherwise suffer losses from a failure to deliver feedstock, the customer asks for liquidated damages. This means that if you cannot supply the feedstock, you are liable for their losses.&nbsp;
 Pricing mechanisms are often a subject of negotiation and many mechanisms exist. Avoided cost basis, cost of feedstock, impacts of renewable energy credits or other tax or policy pricing, pricing for quality (both premiums and penalties), Btu variability, ash content and more are valid and often used mechanisms. Understanding how each works and will impact your business is important.
 If you are a biomass cofiring technology provider, feedstock quality issues, including the quality and size requirements for your system, should be clearly listed in the contract. Emissions profiles, ash content and disposal, performance guarantees, warranties and indemnification are also important contract provisions that need careful consideration. Too often, performance guarantees, warranties and indemnification are considered &ldquo;boiler plate&rdquo; and not given the attention they deserve. But, they can all have significant impact on how fault, and thus financial responsibility, is determined. While your advisers can help you with many of these issues, you need to think of how these contract provisions will impact the relationship with your customer and your own business. An unfortunate example of this was a technology provider whose contract did not define many key terms related to performance and emissions. Because they were not defined, when a problem occurred, it was uncertain whose job it was to fix the problem. Uncertainty often leads to disagreements and disagreements lead to lawsuits, which help neither party.
 Like most things, an ounce of prevention is worth a pound of cure. Asking your customers these questions may not be as fun as closing the deal, but both you and your customer will later appreciate your attention to detail &hellip; or you will both wish you had read that fine print. Author: Todd Taylor Co-Chair Clean Technology Group, Fredrikson &amp; Byron P.A. (612) 492-7355 <a href="mailto:ttaylor@fredlaw.com">ttaylor@fredlaw.com</a>

2011/08/13141116804395.jpg

Managing Risks in Cofiring Contracts

Metso supplies technology for French biomass plants Metso will supply automation and environmental technology to control five biomass power plants to be built by Dalkia in France. The investments are part of France&rsquo;s national green energy program, which aims to reduce carbon dioxide emissions and curb climate change. Dalkia chose Metso because of its track record from Dalkia&rsquo;s biomass plant in Fracture, France. Dalkia wants to standardize the automation systems at all these six plants to save costs on erection, operation and maintenance, spare parts and staff training, among others. The first plant will be built in Limoges and is due to start up in February. The others in Angers, Orleans, Tours and Rennes will be completed next year. The Limoges plant in west-central France will have a capacity of 17.5 megawatts (MW) of electricity and 17 MW tons of district heat.
 Vecoplan hires LaGoe Mike LaGoe has joined Vecoplan LLC as a project engineer/manager. LaGoe, formerly engineering manager at a manufacturer of air pollution control systems, brings 12 years of practical experience to his new position. LaGoe&rsquo;s responsibilities will include coordinating the design and development of large-scale, turnkey systems for the processing and production of alternative fuels from biomass and waste, as well as general waste treatment systems. To ensure continuous quality control, he will also oversee the manufacture and implementation of his projects once the engineering phase has been completed.
 HRE signs licensing agreement with Achor Anaerobic Homeland Renewable Energy announced that its anaerobic digestion (AD) division, Homeland Biogas Energy, has signed an exclusive licensing agreement with Achor Anaerobic LLC. Under the agreement, HB Energy will use Achor&rsquo;s &ldquo;achorlytic&rdquo; enzyme and digestion inoculating technology to enhance the productivity of AD in its projects in the U.S. and elsewhere. HB Energy will also work with Achor to license the technology to third parties. Achor&rsquo;s technology uses enzymes to increase the biogas production from digestible materials, including animal and food wastes as used by HB Energy at its facilities. Achor and HB Energy are carrying out large-scale tests of the Achor technology at AD facilities operated by HB Energy in Wisconsin. Test results are expected to be available during the summer, and preliminary indications show favorable improvements in productivity. HB Energy has a pipeline of more than 15 AD projects, ranging in size from 3 to 20 megawatts.
 DP CleanTech develops biomass fuels tool Aurelie Sol, a DP CleanTech biomass fuel expert, has developed an innovative tool to help people better understand the properties of biomass fuels and fuel mixes under combustion. The proprietary web-based tool is called Biomass Lab and is an interactive database of biomass fuels from around the world. Users can conduct a series of chemical analyses to determine the performance of biomass residues as a fuel for direct combustion biomass power. The user-friendly tool is the only biomass database that allows users to input their own fuels and conduct analyses for fuel mixes. Sol has studied biomass fuels closely and spends much of her time analyzing biomass fuels from around the world. The Biomass Lab can be accessed at www.dpcleantech.com/biomasslab/the-biomass-lab.
 Covanta receives LEED award for corporate headquarters
Covanta Energy Corp. announced that the U.S. Green Building Council has recognized its new corporate headquarters in Morristown, N.J., with Leadership in Energy and Environmental Design Gold Certification. LEED is the nationally accepted benchmark for the design, construction, maintenance and operation of green buildings and office spaces. The U.S. Green Building Council is a coalition of leaders from across the building industry working to promote buildings that are environmentally responsible. The LEED Green Building Rating System is a voluntary, consensus-based national standard for developing high-performance, sustainable buildings. LEED ratings are awarded through a point system that provides building owners and operators with a framework for identifying and implementing practical and measurable green building design, construction, operations and maintenance solutions.
 Martin Engineering finalizes Chinese expansion plans Martin Engineering has announced final plans for a new 10,000 square meter (107,600 square foot) facility in Kunshan, which is in the Jiangsu Province of China.&nbsp; Scheduled to open late this year, the new building will house 8,000 square meters of manufacturing and warehouse operations and 2,000 square meters of office space, making it eight times larger than the existing space. When construction is completed on the recently purchased 16,000-square-meter property, the site will produce a variety of systems used to improve efficiency and reduce fugitive material in bulk material handling, including belt cleaners, impact cradles, skirtboard seal systems, air cannons and industrial vibration. Martin Engineering&rsquo;s existing China facility began operation in Kunshan in 2005, and quickly outgrew the 1,200-square-meter leased space.
 Webb names Roberts regional sales manager of bulk material handling Jervis B. Webb Co., a subsidiary of Daifuku Webb Holding Co., and provider of material handling solutions, has named Mike Roberts as regional sales manager of its Bulk Material Handling division. In this role, he is responsible for supporting business development and sales throughout North America. Webb&rsquo;s BMH division provides durable and reliable systems to industries such as power generation, biomass/biofuel, mining, pulp and paper. Roberts has more than 20 years experience working in bulk material handling. He has had a successful career in the solid waste, recycling and scrap metal industries where he provided material handling and processing solutions.&nbsp; Before joining Webb, he was a sales manager for an engineering and manufacturing firm that provided equipment for shredding and separating ferrous and nonferrous scrap metal.
 Bandit welcomes new dealers in Indiana, Louisiana Bandit Industries announced the addition of three dealers to its authorized dealership network. Tri-County Equipment in Evansville, Ind., Arrow Tool Rental Corp. in Indianapolis, and Emery Equipment Sales &amp; Rentals Inc. in Baton Rouge, La., join more than 150 dealers in more than 50 countries to offer Bandit equipment. These new locations will further extend Bandit&rsquo;s line of hand-fed wood chippers and stump grinders to the professionals who need them, while also providing customer service. Arrow Tool Rental Corp. has stocked Bandit rental machines for years, and will now offer Bandit&rsquo;s full line of hand-fed wood chippers and stump grinders for sale, while also continuing to rent Bandit equipment alongside their rental stock that includes everything from larger industrial equipment to basic hand tools. Tri-County Equipment operates locations in Evansville and Poseyville, Ind., serving residents of southern Indiana, Kentucky and Illinois. Bandit hand-fed chippers and stump grinders will join other represented manufacturers including Kubota, Bobcat, New Holland, Great Plains and more. Emery Equipment Sales &amp; Rentals will sell Bandit&rsquo;s line of hand-fed chippers and stump grinders alongside their new and used Bobcat machinery and King Kutter attachments.
 Vermeer redesigns horizontal grinder Vermeer Corp. has redesigned the HG6000 horizontal grinder with new design enhancements and an engine that meets wood waste processors&rsquo; needs for productivity and government emission regulations. The HG6000 is powered by a Cat C18 Tier 4i/Stage IIIB engine that meets all U.S., Canada and European Union tier regulations while producing 755 horsepower, a 20 percent increase in horsepower over the previous Tier 3 engine. A dual-screen system allows screens to be mixed and matched to attain the desired end product. The screens are also reversible and interchangeable to obtain the maximum usage of the wear portion of the screen. Customers also have the ability to adjust the screen support on the HG6000, allowing the screen to be moved closer or farther away from hammer tips to match clearance with the type of material being processed. Vermeer eliminated the transition area between the anvil and screen, increasing the screen area on the HG6000 by 20 percent, allowing for more throughput.
 Komptech beefs up its Crambo shredder Since its beginnings in 1992, Komptech has developed its machines in close consultation with customers, and been quick to create solutions to their needs. The Crambo low-speed, high-torque shredder, for example, was designed to shred whatever came its way, including logs and stumps. Now, not all stumps are equal, of course. There are stumps from regular forestry&mdash;from ground long ago cleared of rocks, where trees are harvested before they get too old, and where everything is generally under control. And then there are stumps from hardwoods that grew where the seed happened to fall, sometimes around rocks or even old pieces of metal. So Komptech decided to beef up the Crambo for more longevity with any diet, creating the new Crambo HD (heavy duty). The Crambo HD has 10 percent more horsepower, armored drum, armored teeth, heavy-duty gear box and drum bearing.

BIOMASS SYSTEM SPECIALIST: Mike LaGoe joins Vecoplan as a project engineer/manager. 

2011/08/13141119239423.jpg

BIGGER AND BETTER: Martin Engineering designs and supplies equipment for bulk materials handling.



2011/08/13141119663036.jpg

WOOD WRANGLER: Vermeer's redesigned grinder meets the government's emission standards. 

2011/08/1314112057296.jpg

Business Briefs

The U.K.&rsquo;s Renewable Energy Roadmap, released as part of a government white paper on reforming the electricity market, identifies both biomass heat and power within the eight technologies with the greatest potential to meet the U.K.&rsquo;s 15 percent by 2020 renewable energy goals. In fact, biomass is listed among the top three, along with wind and air heat pumps.
 The central range for deployment indicates that biomass electricity could contribute up to 6 gigawatts (GW) by 2020, equal to an annual growth rate of 9 percent, the roadmap says. Conversion of existing coal plants to biomass is a major new development, representing another 4.2 GW, including cofiring capacity, plus more with any new projects. Those increased expectations for biomass power have large power providers excited and hopeful that meaningful incentives will follow.
 &ldquo;We welcome the publication of the Renewable Energy Roadmap,&rdquo; says Dorothy Thompson, chief executive of Drax Power Ltd. The company is looking to cofire biomass in its 4,000 megawatt Drax Power Station, and possibly develop more dedicated biomass power plants. &ldquo;In particular, we are encouraged by the recognition of the greater role that electricity generation from sustainable biomass can make to meeting the government&rsquo;s climate change targets,&rdquo; she says. &ldquo;That is very much in line with Drax&rsquo;s focus as we seek to expand our biomass operations. However, in order to do so, we will need an appropriate level of support under the current renewables incentive mechanism. To that end, we eagerly await the government&rsquo;s proposals for the support levels from April 2013.&rdquo; Through the U.K. Renewables Obligation, Renewables Obligation Certificates are awarded to qualifying operations. The amount of ROC support is determined by technology type, but support levels past 2013 are currently being decided. Many, including Drax, are hoping to see elevated support for biomass applications.
 The roadmap lists priority actions for the government to help further establish the biomass power industry, including minimizing investor risk, de-risking the feedstock supply chain, establishing access to finance, and accessing long-term waste fuel contracts. &ldquo;Biomass electricity has significant upside potential and could feasibly exceed the industry high, helping to meet the 15 percent target cost effectively,&rdquo; the roadmap states. &ldquo;However, the projections can only be achieved if sufficient sustainable feedstocks are available.&rdquo;
 The roadmap continues into biomass heat, saying the nondomestic sector could contribute up to 50 terawatt hours by 2020. That requires a large annual growth rate of up to 17 percent. Priorities in that area include technology costs, the report says, adding that implementing the U.K.&rsquo;s Renewable Heat Incentive will help make it competitive with fossil fuel generation. Air quality regulation is another important priority, as are planning and environmental permitting, investor confidence, and RHI&rsquo;s capacity to help with costs associated with biomethane injection into the grid.
 The Renewable Energy Roadmap was released along with the Electricity Market Reform White Paper, which states that the government intends to zero rate biomass in its Emissions Standards Performance program, a regime for new fossil fuel power stations supporting decarbonization objectives. &ldquo;The government expects sustainably sourced biomass to make a significant contribution towards achieving the U.K.&rsquo;s renewable energy targets,&rdquo; it says. &ldquo;Applying the ESP to any level of biomass emissions above zero could reduce the incentive to invest in sustainable biomass generation.&rdquo;
 The publication of the white paper marks the final stage of the reform process. The government intends for the legislation to reach the statute book by spring of 2013, so the first projects can be supported under its provisions around 2014.
&mdash;Lisa Gibson

2011/08/13141122219585.jpg

A U.K. white paper and accompanying energy roadmap put emphasis on biomass potential.

Burgeoning Biomass

The coupling of biomass technologies with carbon capture and storage (CCS) yields negative carbon dioxide emissions and the global potential is enormous, according to &ldquo;Potential for Biomass and Carbon Dioxide Capture and Storage,&rdquo; a study recently released by innovation company Ecofys and international research collaborative IEA Greenhouse Gas.
 The study aimed to provide an assessment of the potential for biomass and CCS technologies up to 2050, with an additional focus on the medium term. Combining the two could result in up to 10 gigatonnes of negative carbon dioxide across the globe annually, researchers found. Putting that in perspective, global energy-related carbon dioxide emissions in 2010 reached almost 31 gigatonnes. &ldquo;The combination actually removes CO2 from the atmosphere,&rdquo; says Joris Koornneef, a consultant at Ecofys. &ldquo;The biomass extracts CO2 from the atmosphere during photosynthesis and the CCS takes out the CO2 released in the energy conversion process.&rdquo;
 The study carefully distinguishes between technical potential: potential that is technically feasible and not restricted by economic limitations; realizable potential: potential that is technically feasible and takes future energy demand scenarios for the phase out of existing generating capacity into account; and economic potential: the potential at a competitive cost compared to alternatives.
 Looking at both electricity and fuel production, the study explored six technology routes. For power, it included pulverized coal with direct biomass cofiring; circulating fluidized bed dedicated biomass; integrated gasification combined cycle with cogasification of biomass; and biomass integrated gasification combined cycle. For biofuels, the study evaluated advanced production of bioethanol through hydrolysis and fermentation; and biodiesel based on gasification and Fischer Tropsch synthesis. The report also distinguishes three types of biomass: energy crops, forest residues and agricultural residues. It also includes global sustainable biomass potential.
 Taking only technical limitations into account, the maximum annual potential is about 10 gigatonnes of negative emissions annually in the power sector alone, or 6 gigatonnes in the biofuel sector. The realizable potential in the medium- and long-term appears to be the greatest for pulverized coal coupled with CCS and cofiring with biomass, according to the report. The best economic potential in both the medium- and long-term lies in biomass integrated gasification combined cycle with CCS. It has the lowest cost of electricity when using low-cost biomass.
 But even with all the potential, barriers remain, including the lack of a clear economic incentive. &ldquo;Without such an incentive, the huge potential for negative emissions will not be deployed,&rdquo; the report says. Moving forward in the near-term, the researchers recommend a detailed look at the most promising regions.
 For a copy of the full report, contact Toby Aiken, IEA Greenhouse Gas communications dissemination manager, at toby.aiken@ieaghg.org.
&mdash;Lisa Gibson

2011/08/13141122963552.jpg

Study: Biomass technologies plus carbon capture/storage have global potential for negative CO2 emissions.

Coupling with CCS 

Since late last year, the U.S. Air Force Special Operations Command in Hurlburt Field, Fla., has been generating energy from municipal solid waste (MSW) in lieu of landfilling, using a 10.5 metric-ton-per-day plasma gasification process.
 The system is small, but represents the first commercial installation of the technology for developer and vendor Quebec-based Pyrogenesis Canada Inc. &ldquo;It is a showcase for them, as well as a showcase for us,&rdquo; says Tom Whitton, business development leader for the company.
 The MSW feedstock will be sourced from Hurlburt, but the system will also use some industrial, medical and hazardous waste from nearby Eglin Air Force Base, Whitton says. The 400 to 500 kilowatts it will produce is enough to power itself, with no surplus for sale to utilities. Pyrogenesis, does, however, have systems available up to 100 metric tons per day, which would allow for excess power sales.
 The two-step plasma gasification system includes a furnace with graphite electrodes that operates at 1,600 degrees Celsius (2,912 degrees Fahrenheit) to create the plasma, Whitton explains. In the furnace, all inorganic materials are converted to vitrified slag that can be mixed with cement or asphalt and used in construction, while the organics begin partial gasification. The gas created in the furnace goes directly through the plume of a plasma torch, producing the syngas that is then cleaned. &ldquo;What we&rsquo;re doing in Florida is we&rsquo;re actually feeding that gas, once it&rsquo;s been completely cleaned up &hellip; into an internal combustion engine to produce electricity,&rdquo; Whitton says.
 One of the advantages of using thermal plasma in the gasification process, he adds, is that it can handle a high variation of feedstock with its temperatures in excess of 10,000 degrees Celsius. &ldquo;Because of the extreme temperatures that plasma operates in, virtually no chemical substances or compounds can survive that.&rdquo;
 The cost to build the plant was $7.4 million, funded by the U.S. Foreign Comparative Testing Office, Air Force Smart Operations for the 21st Century, the Canadian government, the U.S. Air Force Surgeon General's office, and Gulf Power. While Pyrogenesis is a vendor and does not typically operate its technology when installed, the company is operating the Hurlburt Field plant through a contract with the Air Force, Whitton says.
 The system is perfectly suited for the Air Force because it is transportable and designed for &ldquo;plug and play,&rdquo; Whitton says. It can be disassembled, moved and reassembled easily. &ldquo;They work as an island,&rdquo; he says of Air Force bases, adding that self-sufficiency is crucial.
 "This is history in the making," Terry Yonkers, assistant secretary of the Air Force for installations, environment and logistics, said at a ribbon-cutting ceremony for the plant in April. "This is the first waste-to-energy project of this technology to go into an air base. It has been a long time in the making." For the base, it will mean diverting nearly 8.3 tons of daily domestic trash from landfills, reducing gas emissions by over 83,000 tons per year and eliminating toxic materials while producing energy.
 &ldquo;It&rsquo;s much more of a waste management project than an energy project,&rdquo; Whitton says. &ldquo;But without the energy recovery, it wouldn&rsquo;t fly.&rdquo;
&mdash;Lisa Gibson

THE POWER OF PLASMA: The first commercial installation of the Pyrogenesis plasma gasifier cost $7.4 million, and allows the Air Force to divert 8.3 tons a day of trash from going to the landfill. 

2011/08/13141124270733.jpg

The first application of Pyrogenesis's plasma gasifier is operating for the U.S. Air Force in Florida.

Pyrogenesis Perfecting Plasma

With increased interest in the U.K.&rsquo;s Renewable Heat Incentive, The Mersey Forest has developed a free online tool to determine the payback for users interested in the program.
 The RHI is designed to help the U.K. meet its renewable energy goal of 15 percent by 2020. It&rsquo;s based on the amount of heat used, not the amount generated, and is intended for use by public and private sectors, charities and other users of all scales. The U.K.&rsquo;s Department of Energy &amp; Climate Change has released the details of the program, the money has been allocated and the primary legislation is making its way through Parliament.
 The calculator works under two scenarios. It will determine potential income streams based on current heat usage, or calculate the paybacks if the user is switching from a fossil fuel system to woody biomass and knows the capital installation cost figures. It is designed to also calculate how quickly the users&rsquo; boilers will pay for themselves, the expected difference in annual fuel bills, and what return they could see after 20 years.
 The tool is geared mostly toward woody biomass, says Nigel Blandford of The Mersey Forest Team. &ldquo;However, the RHI as a whole, very interestingly, does accept a range of fuels,&rdquo; he adds, citing municipal solid waste.
 So far, the calculator has found that areas off the gas grid and plants that produce over 1 MW have the most attractive paybacks. Not all areas in the U.K. have been added to the calculator, as the necessary data in most cases is well-guarded, Blandford says.
 The Mersey Forest is a network of woodlands and green spaces spread across Cheshire and Merseyside. &ldquo;By building both supply of and demand for wood fuel in Merseyside and Cheshire, The Mersey Forest is working to not only support the local economy, but also show how sustainable renewable fuel can be part of the solution to climate change and energy security,&rdquo; Blandford says.
&mdash;Lisa Gibson

A new online tool calculates the benefits of the U.K.'s Renewable Heat Incentive.

By the Numbers 

When Chris Wiberg was introduced at the Pellet Fuels Institute Annual Conference to update attendees on PFI&rsquo;s standards and third-party certification system, it was said that he has spent thousands of hours on the project. Taking the stage, Wiberg, chief operations officer of Twin Ports Testing and co-chair of PFI&rsquo;s Standards Committee, said he wished that were an exaggeration. The process of forming the standards and three-level verification system is arduous, but the benefits to the market and customers of having the standards in place are hard to deny.
 During his presentation at the conference, held in Ponte Vedra Beach, Fla., from July 24-26, Wiberg addressed changes to the standards that have come about since the draft release in October, which outlined three fuel grades: premium, standard and utility. It specifies parameters for a number of properties including ash content, diameter, durability, fines, moisture and chloride content, among others. In the ash content category, PFI&rsquo;s premium fuels require 1 percent or less, standard requires 2 percent or less, and utility grade requires 6 percent or less. For moisture content, premium fuels require 8 percent or less, while both standard and utility must be equal to or less than 10 percent.
 The most important aspect of the system is the third-party audit of those parameters and PFI proposes a three-level verification system, beginning with the pellet mill itself. The second verification comes from monthly on-site visits by inspectors who are well-versed in the timber industry, doing other forest product inspections such as lumber grading. Finally, the inspectors&rsquo; assessments will be audited by the accreditation body, which Wiberg announced at the event will be the American Lumber Standard Committee. &ldquo;I&rsquo;m feeling confident that they are the right body,&rdquo; he said.
 Wiberg also walked the audience through what he called &ldquo;semantic-type changes&rdquo; to the draft documents. For instance, in the program document, &ldquo;certification body&rdquo; was changed to &ldquo;accreditation body,&rdquo; &ldquo;certified fuel&rdquo; is now &ldquo;graded fuel,&rdquo; and &ldquo;certified&rdquo; is now &ldquo;qualified.&rdquo;
 &ldquo;Bottom line is, nothing changed in all of that, but we ended up with a lot of red ink,&rdquo; Wiberg joked. Also, internal laboratories at mills are no longer required, he announced, the standards specification document has been restructured, and the inspection and re-inspection criteria have been altered. Now, a product must be within 95 percent compliance for grade qualification.
 And the cost of compliance will differ from mill to mill, Wiberg said. Factors to consider include the PFI enrollment and operations fee; internal lab quality assessment and quality control program development; third-party lab and testing services; auditing services; and ALSC&rsquo;s administration costs. Wiberg estimated it will cost 50 to 70 cents per ton.
 The annual conference also included a symposium detailing the standards for pellet manufacturers and compliance with the program. Program presentations are available at www.pelletheat.org. PFI hopes that the standards will be adopted by appliance manufacturers who will outline the use of certain grades and void warranties where the specifications aren&rsquo;t followed.
 Moving forward, the standards committee will finalize the language in the agreement with ALSC; and ALSC and PFI boards will need to review, approve and sign the agreement. A timeline for the release and implementation of the standards is hard to nail down, Wiberg said.
&mdash;Lisa Gibson

PFI is working diligently on its third-party fuel certification standards.

Standards Status  

The Energy &amp; Environmental Research Center&rsquo;s Biomass &rsquo;11: Renewable Power, Fuels, and Chemicals Conference, which was held July 26-27 in Grand Forks, N.D., welcomed more than 250 attendees from 28 states, Washington, D.C., and 11 foreign countries, to discuss trends, opportunities, economics and technological developments surrounding the biomass energy industry.&nbsp;
 The underlying theme during the first day of the conference seemed to be that while next-generation biofuels hold a great deal of promise, commercialization is still a ways off and smaller-scale biomass-based heat and power remains the most economically feasible option.
 EERC Director Gerald Groenewold kicked off the ninth annual conference by discussing the EERC's mission and current areas of focus. The EERC, which is a nonprofit, high-tech division of the University of North Dakota, focuses on applied research, development, demonstration and commercialization of clean energy and environmental technologies. The center has been involved in more than 300 contracts over the past year, according to Groenewold, 87 percent of which were private-sector clients. The EERC has had clients from all 50 states and 51 countries, he added.
 &ldquo;As an American citizen, if we&rsquo;re talking about energy security, I don&rsquo;t believe in the concept of energy independence,&rdquo; Groenewold said. &ldquo;We have Canadian friends who provide a lot of energy to this country and they&rsquo;re going to continue to, and the same thing is true for a few other places around the world. To be energy secure, we need a portfolio of all kinds of energy technologies; we need to look at every possible option.&rdquo;
 With biomass utilization there are lots of challenges, but there are also lots of opportunities, Groenewold said. &ldquo;Biomass has key roles to play, but it&rsquo;s not a silver bullet,&rdquo; he said. For biomass power generation specifically, Groenewold says power plants between 10 and 15 megawatts (MW) are a realistic expectation in terms of feasible development in the U.S. &ldquo;Larger plants won&rsquo;t be a factor in the U.S., not in the foreseeable future.&rdquo;
 Groenewold discussed some key biomass projects the EERC is involved in, including a program focused on small distributed power generation&mdash;100- to 500-kilowatt gasifier systems for electric power that run on feedstocks such as turkey litter&mdash;and large-scale biomass gasification, in which he said EERC was seeing significant financial interest, mostly from China and India.&nbsp;
 Following Groenewold&rsquo;s presentation, U.S. Sen. John Hoeven, R-N.D., addressed attendees via video message, touching on North Dakota&rsquo;s comprehensive energy plan and how he&rsquo;s working with federal policymakers to craft a similar national policy. &ldquo;We recognized we need all of our nation&rsquo;s resources to build our energy future, including fuel and electricity from biomass,&rdquo; he said. He added that North Dakota has great potential for the production of dedicated energy crops and crop residues, and that its current energy policy encourages investment in projects that utilize them and other renewable energy technologies.&nbsp;
 Chris Zygarlicke, deputy associate director for research at the EERC, addressed trends and opportunities in biomass. Fossil fuels will dominate until around 2030, he said. Natural gas leads energy source growth with about a 2 percent increase each year, he said, &ldquo;and that&rsquo;s having an impact on biomass and renewables. Renewables have seen some growth, but it&rsquo;s small.&rdquo;
 The main challenges for biomass growth are related to feedstock and its high cost, particularly issues related to processing, and inconsistencies in rules, regulations and policies that will help propel biomass energy forward, Zygarlicke said. &ldquo;Will it grow? Yes, but it&rsquo;ll grow along with all the rest of the [renewable] resources.&rdquo;
 In terms of biopower development in the U.S., Zygarlicke said that there is really no interest from large-scale fossil baseload utilities. &ldquo;That&rsquo;s because we don&rsquo;t have the incentives that Europe has, where they&rsquo;ll pay per ton of carbon that&rsquo;s alleviated from going into the atmosphere,&rdquo; he said. &ldquo;If we did, that would definitely bring interest to the larger scale utilities. However, smaller scale, industrial heat and power does have continued interest.&rdquo;
 Small biopower will keep growing under the radar, from Zygarlicke&rsquo;s perspective. &ldquo;It doesn&rsquo;t get a lot of publicity, but development of smaller plants&mdash;distributed energy or larger 15- to 20-MW combustion systems, will continue,&rdquo; he said. &ldquo;Larger-scale cofiring/refiring projects will continue to wait in the wings until we see the incentives, and biofuels still need to be proved technologically at commercial scale.&rdquo;
&mdash;Anna Austin

RENEWABLE REALM: The Energy and Environmental Research Center held its annual biomass conference in Grand Forks, N.D., in July. 

2011/08/13141128723712.jpg

Biomass is not a silver bullet but it plays a key energy role.

Energy Options

John Bonitz wrote this letter in response to an article that appeared earlier on the magazine website, and is published in this magazine on page 15. With debate raging over the carbon neutrality of bioenergy, America should embrace biomass technologies that are actually carbon negative. Thus, I applaud the article on the recent IEA Greenhouse Gas study, &ldquo;Coupling with CCS.&rdquo;
Thank you for jump-starting the conversation. Beyond this, the study has limited usefulness in the U.S., as policymakers and investors have already largely rejected carbon capture and sequestration (CCS). July&rsquo;s cancellation of the Mountaineer coal-fired CCS project prompted Businessweek magazine to report, "Five largescale CCS projects have been canceled or postponed, while the fate of several others remains doubtful." In a policy regime where the costs of carbon pollution remain externalized, CCS projects fail due to complexity, high operational costs, large scale and high capital costs.
Current CCS technologies&mdash;often called "clean coal"&mdash;require 10 to 40 percent more energy input for the same output of a non- CCS power plant. If CCS with energy-dense coal is expensive, then CCS with low-energy density biomass will be even more expensive.
In contrast, the other carbon-negative bioenergy pathway&mdash; pyrolysis or gasification with coproduction of biochar&mdash;is less complex, can be built at smaller scales, and is less capital intensive. Biofuels and/or biopower are produced while also creating biochar for use as a soil amendment. Any &ldquo;energy losses&rdquo; perceived in the conversion of potential Btu into charred carbon is a justifiable form of tithing back to the earth. Afterall, this biochar puts stable, recalcitrant carbon back in the soil, where it has many beneficial impacts.
CCS has ready markets for CO2 pumped underground to enhance oil recovery (EOR). But biomass is a distributed resource, oil wells are not, and there is little biomass in oil country&mdash;inherently limiting the EOR market.
Soil scientists are finding biochar has many benefits, including increased crop yields, retention of nutrients and water, and suppression of greenhouse gas emissions.
Granted, until Americans put a price on carbon, both CCS and thermochemical bioenergy are precommercial technologies. Also, additional research is needed to determine the precise benefits of different types of biochar in different soils, for different crops. But investors and policymakers with limited capital might ask themselves, which is a better investment: complex, centralized engineering monoliths or heat-treating biomass for distributed energy and beneficial biochar?
Carbon-negative bioenergy with biochar is a pathway to rebuild the soil, provide for the needs of future generations and provide some of today&rsquo;s energy needs, while helping to mitigate climate change.
Either way, let&rsquo;s stop dithering over debatable carbon accounting and take actions that prove their merits with measurable physical sequestration of multibenefit biogenic carbon.
Author: John Bonitz Southern Alliance for Clean Energy <a href="mailto:Bonitz@cleanenergy.org">Bonitz@cleanenergy.org</a>

CCS Versus Carbon-Negative Bioenergy with Biochar

I recently had the privilege of testifying before the Energy and Power Subcommittee of the U.S. House Committee on Energy and Commerce and share with its members the incredible progress the advanced biofuels industry is making in moving our nation closer to energy independence while creating jobs right here at home. As I wrote in last month&rsquo;s magazine, I emphasized the importance of providing stable, long-term, common sense public policies that allow the various renewable and alternative energy sources to compete to achieve our national policy goals. I also urged the government to resist the temptation in their public policy efforts of attempting to pick a winner. Specifically I called for a technology-neutral, feedstock-neutral approach while providing a level playing field in terms of grants, tax credits and loan guarantees. I told the members of the House Committee that recent developments in advanced biofuels technologies enable our companies to make significant contributions in diversifying our transportation fuels pool. One of the most noteworthy developments I recounted was the ability of many of our companies to manufacture gasoline, jet, diesel, heating oil and crude oil from renewable sources. It is essential that lawmakers know these &ldquo;drop-in fuels&rdquo; are fungible in today&rsquo;s planes, trains, boats and automobiles. No changes to the current infrastructure or transportation fleets are required and they provide economically competitive alternatives with current products on the market. I thought you would be interested in reading other points I shared with lawmakers as I have been writing about the vital role all of us play in helping educate Washington on our progress as an industry and the work ahead of us. I told the Committee, there are some who would like Washington to believe that advanced and cellulosic biofuels are a long way off, but nothing could be further from the truth. These fuels are being commercially produced today, with many more gallons on the way. In fact, Dynamic Fuels, a joint venture between Tyson Foods of Arkansas and Syntroleum of Oklahoma, is currently producing 75 million gallons of renewable diesel and jet fuel in Louisiana. This plant makes diesel and jet fuels as if they were made in a refinery out of a traditional barrel of oil. In addition, I am pleased to report that several advanced biofuels companies have recently gone public with great success. Gevo, as a result of its recent $127 million offering, has begun its plans to retrofit a traditional corn ethanol plant to produce 18 million gallons of isobutanol next year. It has also announced plans to develop over 350 million gallons of production by 2015. Similarly, Amyris completed a successful IPO and plans to deploy 75 million gallons of renewable diesel in 2012, while Solazyme and Kior, companies that also plan to produce fungible drop-in fuels also announced their intentions to go public this year.&nbsp; Several of our members including Rentech, Kior, Coskata, Sundrop Fuels, Honeywell, and LS9 are currently negotiating financing for future commercial facilities;&nbsp; while many others, such as BP, DuPont and Virent, are moving forward rapidly in demonstrating their fuels and building or operating their pilot or demonstration plants with commercialization in their future plans.&nbsp; These developments would simply not be occurring if it were not for the vision of this committee in the House and the Congress to enact a framework to expedite the development of advanced and cellulosic biofuels. Our association and member companies strongly believe the current RFS2 is the most important federal policy in supporting the development of a biofuels industry in this country. We would specifically urge this committee and Congress to not tinker with the statute at this time. As most of you are aware, the chief challenge of the advanced and cellulosic industries has been acquiring the necessary funding to build the next generation of facilities. One of the primary reasons for the disappointing lack of commercial funding has been our biofuels tax policy. The current code is inconsistent in what it rewards according to the molecule, or feedstock or process used. Advanced and cellulosic biofuels tax policy does not provide parity and in many cases the credit is not in the right form to enable companies to monetize their value. Depending on your size and scale as a company, many in the advanced or cellulosic industry believe they would have been more successful if they had a similar Investment Tax Credit to the solar and wind industries rather than the production credits afforded under current law. I told the committee the system of loan guarantees has been challenging at best. However, pulling the plug on the money in the middle of the game for those companies that have expended significant monies to apply was simply wrong. I urged the Congress to help the industry on the procurement side of the equation by extending the period of time in which the military could purchase advanced biofuels similar to the long-term electric power purchase agreements. This would afford an offtake agreement enhancing the ability to secure financing.&nbsp; As the bells rang out loudly calling the members of Congress to cast votes on the House floor, I concluded my remarks by pointing out that a significant amount of progress has been made over the past two years by the advanced biofuels sector. Much more is on the way as these fuels continue to make significant contributions towards diversifying America&rsquo;s and the world&rsquo;s transportation fuels in the future. Author: Michael McAdams President, Advanced Biofuels Association (202) 469-5140 Michael.McAdams@hklaw.com

Making the case for advanced biofuels to Congress

Taking It to the Hill

Awell-structured indemnity provision is critical to ensuring both parties are protected in relation to breaches of an asset or stock purchase agreement.&nbsp; &nbsp; When negotiating an acquisition, the parties carefully allocate the risks between them through the use of warranties, representations and covenants. Indemnity provisions provide the mechanism by which those obligations are enforced and limit the parties&rsquo; exposure to delayed claims. This article will discuss the key terms of an indemnity provision and the considerations that go into negotiating such provisions.&nbsp; Survival provisions serve as a statute of limitations for claims related to the breach of an agreement. Obligations under the agreement are usually divided into two sets, one set which lasts indefinitely and a second set that lapses within one to three years of the closing date.&nbsp; The indefinite set usually includes obligations related to corporate authority, government authorization, environmental matters, taxes, employee benefits, related party transactions, and similar matters that could have large liability, could completely unwind the deal, or are completely within the seller&rsquo;s control.&nbsp; The second set of obligations usually lapses within one to three years of the closing date. These obligations generally include all business related representations and warranties, including those related to financial statements, the sufficiency of assets, the condition of assets, any material adverse changes, and litigation. The time lapse provides certainty to the seller, and breaches are generally discoverable before the time period lapses. The time period is generally set to match the term of an escrow, discussed below.&nbsp; Almost every party to an acquisition agreement recognizes that there will be small breaches that do not materially impact the operation of the business. Therefore, the parties often create a minimum threshold that must be crossed before the seller will be required to pay damages for a breach. The seller also desires to limit its potential liability. The primary mechanisms used to manage these risks are a &ldquo;basket&rdquo; and/or a &ldquo;cap.&rdquo;&nbsp; A basket is a threshold amount of damages that must be reached before a party is liable to pay any claims. There are two primary types of baskets, deductible baskets and first-dollar baskets. With a deductible basket, the seller only pays for indemnity claims that exceed the deductible basket threshold. In contrast, a first-dollar basket provides that once the basket threshold is reached, the seller is responsible for all claims, including those used to reach the threshold. Through negotiation, a party can also craft a hybrid of these approaches with different basket thresholds and deductible levels.&nbsp; A cap is a flat dollar limit on the claims that the seller and/or the buyer may be liable for under the agreement. A seller&rsquo;s liability is often limited to at least the purchase price, though it may be negotiated to a lower amount as well. While the cap may be as high as the purchase price, the ability to collect may be functionally limited to the escrow amount, discussed below. Often, cap is inapplicable to the certain obligations due to the magnitude of the liabilities that may be covered, like environmental liability. A buyer may also seek to limit their liability for damages, though the focus is usually on the seller. The parties should also consider how damages should be measured. While terms like materiality and knowledge are carefully negotiated in various representations and warranties, sellers often seek to ignore such limitations when calculating indemnity claims. This increases the likelihood that a basket threshold will be reached. Both parties should carefully consider whether such a provision is appropriate in their particular deal.&nbsp; All the promises in the world are not worth anything if the seller distributes the purchase price and the buyer has to chase down every shareholder to recover the funds. For this reason, the parties often place a portion of the purchase price into escrow as security for indemnity claims. A common escrow amount is 10 percent of the purchase price, though the actual escrowed amount will depend on the risks involved in the transaction and the bargaining power of the parties. This summary merely scratches the surface of the complexity related to indemnity provisions. Any party to an acquisition should question their attorney about the risks associated with indemnity provisions and the ways in which indemnity provisions can serve that party&rsquo;s interests.&nbsp;
Author: Drew D. Larson Attorney, BrownWinick (515) 242-2485 <a href="mailto:larson@brownwinick.com">larson@brownwinick.com</a>

When acquiring assets, indemnities 
enforce the deal's various obligations  


Understanding Indemnities

The advanced renewable fuel standard (RFS2) requires aggressively increasing amounts of cellulosic biofuels to be included in the fuel pool each year, and it is likely that there will be a strong market demand from obligated parties for this type of fuel as blend requirements increase. The current federal RFS2 requires that 36 million gallons of biofuels must be used in transportation fuel by 2022, including at least 21 billion gallons of advanced biofuels such as cellulosic biofuels, creating a gigantic market.
The U.S. DOE has identified a small number of potential intermediates obtainable from cellulosic biomass resources. Levulinic acid, a breakdown product from the acid hydrolysis of cellulose, is one such intermediate and has been studied by the Energy &amp; Environmental Research Center and other laboratories. One of the biggest challenges to utilizing levulinic acid as a biofuel intermediate is its costly separation out of the product mix. The EERC in partnership with Mercurius Biofuels has shown in the laboratory that cellulosic biomass in an alcohol medium can be catalytically converted to levulinate esters instead (ethanolysis). These chemicals are also useful for fuels and chemical intermediates. However, a major advantage of forming levulinate esters, as opposed to levulinic acid, is that the ester form is much easier to extract using a simple condensation reaction. Experiments were performed by the EERC using laboratory-scale batch reactors. Tests were done using laminated particleboard, cellulosic municipal solid waste, shredded paper and pineapple waste; all of which successfully were decomposed to ethyl levulinate. Further processing was done to create higher molecular-weight compounds.
A major push will now be made to create a pilot-scale version of a biorefinery based on this technology. The biorefinery, in very simple terms, will run in a sustainable mode using common agricultural feedstocks such as wheat straw and corn stover. The process will include three steps: 1) ethanolysis, 2) condensation, and 3) hydrotreatment to stabilize the fuel products. Final products from this biorefinery will include advanced fuel additives in the form of cyclic ethers and hydrocarbons. This technology will ultimately be used to improve engine performance using a renewable product, both in gasoline and diesel engines. In the case of diesel fuel, the additives will boost the cetane levels, improve flow properties and, most importantly, reduce particulate emissions.
Subsequent product-upgrading steps will also be conducted in continuous reactor systems, and sufficient volumes of the desired fuel products will be produced so that more extensive fuel testing can be done. The data collected from these continuous production runs will be used to further assess process economics and will also be used for the future design and construction of a larger pilot plant facility. Calculations at this time show that this type of three-step biorefinery will have a lower cost than competing technologies. Capital costs will be lower because residence times are measured in minutes compared to hours or even days for fermentation-based technologies. Also, operating conditions are moderate compared to gasification or pyrolysis. In summary, this biorefinery technology is superior to other technologies because it does not depend on enzymes and fermentation or extreme operating conditions. This technology is more in line with the petroleum refining model and will benefit from many of the same efficiencies.
The technology is patent pending for the EERC Foundation and licensed to Mercurius Biofuels on a global, exclusive basis. Author: Ed Olson Senior Research Advisor, EERC (701) 777-5155 eolson@undeerc.org

The new biorefinery will resemble an old, familiar model

Cellulosic Fuel Production:  One Step Closer to  Standard Refining

The leaders of seven renewable energy industry trade groups lined the stage at the general session of BBI&rsquo;s International Biomass Conference &amp; Expo in early May in downtown St. Louis. The seven panelists were Mary Rosenthal, executive director of the Algal Biomass Organization; Joe Jobe, CEO of the National Biodiesel Board; Bob Dinneen, president and CEO of the Renewable Fuels Association; Michael McAdams, president of the Advanced Biofuels Association; Charlie Neibling, chairman of the Biomass Thermal Energy Council; Robert Cleaves, president and CEO of the Biomass Power Association; and Norm McDonald, chair of external affairs for the American Biogas Council. The gathering of these individuals together all under one roof to discuss policy, energy, markets and the futures of their respective industries was truly impressive. I couldn&rsquo;t help but think, 50 years into the future when a majority of our energy will (we hope) come from renewable sources, that these seven individuals&mdash;and their constituency&mdash;could be thanked. It was almost historic, or at least it felt that way to me. Biorefining Magazine Associate Editor Erin Voegele was on scene to capture the discussion and provides us with a feature article, &ldquo;Gateway to Cooperation and Parity,&rdquo; on page 32 of this issue. Voegele writes, &ldquo;St. Louis is not only the Gateway to the West, it also acted as the gateway to the future of the biomass industry in May as nearly 1,400 professionals representing all aspects of the sector descended upon the city&rsquo;s America&rsquo;s Center to network, conduct business and learn about recent technological and agronomic breakthroughs. A highlight of the event was the Tuesday morning plenary session, titled Association Executive Roundtable: Our Industry in a Changed Political Landscape.&nbsp; &hellip; While different segments of the biomass industry have, at times, unintentionally worked against rather than with each other, the tide seems to be shifting.&rdquo; This changing tide is evidenced by recent cooperation between organizations such as the Advanced Biofuels Association, National Biodiesel Board, the Algal Biomass Organization, the Renewable Fuels Association and BIO, on areas of common policy and objectives.

MEMORABLE GATHERING

1. Elevance Renewable Sciences Inc. and Royal DSM N.V. have signed a letter of intent for a collaboration to evaluate Elevance&rsquo;s unique monomers for the production of specialty biobased high-performance thermoplastic materials for DSM&rsquo;s engineering plastics portfolio. Specifically under the proposed partnership, Elevance will provide natural monomers produced from plant oils along with its proprietary metathesis technology to enable the production of various polymers. DSM will provide expertise on polymer research, application development and commercialization. DSM, along with BP, also recently invested an undisclosed amount in biotech firm Verdezyne from the closing of a new investment round. Previous investors OVP Venture Partners and Monitor Ventures also participated in the new round. In other company news, DSM and France-based starch and polyols producer Roquette Freres plan to jointly build a 10,000 metric ton per year commercial-scale biobased succinic acid facility near a Roquette starch manufacturing site in Cassano Spinola, Italy. The proposed production plant, scheduled to come online by second quarter 2012, would be Europe&rsquo;s largest biobased succinic acid production facility. 2. Los Angeles-based Rentech Inc. has received approval by the Province of Ontario, Canada, to obtain a long-term supply of up to 1.3 million tons per year of Crown timber for the company&rsquo;s planned biobased jet fuel project, Project Olympiad, located in the Township of White River, Ontario. The proposed wood allotment for Rentech&rsquo;s planned project is the largest ever awarded in the Provincial Wood Supply Competitive Process administered by the Ontario Ministry of Northern Development, Mines and Forestry. Scheduled to be operational by 2015, Project Olympiad is expected to produce approximately 23 million gallons annually of RenJet fuel&mdash;Rentech&rsquo;s trademarked renewable and certified low-carbon jet fuel&mdash;via a proprietary process based on Fisher-Tropsch chemistry that, together with gasification and upgrading, is capable of converting syngas from biomass and fossil sources into hydrocarbons that are subsequently upgraded utilizing technology from an alliance with UOP, a Honeywell company. The project will also produce 13 MMgy of biobased naphtha, an intermediate hydrocarbon that can be used for the production of polyethylene for plastics, along with other applications. 3. Cobalt Technologies and American Process Inc. have announced an agreement to build an industrial-scale cellulosic biobutanol refinery. The companies have also agreed to jointly market a joint biorefining solution to biomass power facilities and other customers. API is developing and commercializing lignocellulosic sugar production and bioenergy process technologies. The company is currently working to construct a facility in Alpena, Mich., which will demonstrate the conversion of hemicelluloses extracted from woody biomass into fermentable sugars. The project, funded in part by an $18 million U.S. DOE grant and a $4 million grant from the state of Michigan, will initially produce cellulosic ethanol. API&rsquo;s technology, known as GreenPower+, is a patent-pending proprietary process for extracting hemicelluloses sugars from woody biomass using steam or how water. The sugars are then converted to fermentable sugars. The extracted biomass is returned to a boiler and used to produce steam and electricity. The sugars are further processed into end products. 4. The Chempolis Biorefining Park has been a busy place over the past month, hosting energy commissioners and prime ministers. Gunther Oettinger, the EU energy commissioner, took a tour of the facility that puts the 3G formico biorefining technology to use. Members of Chempolis, including Paivi Rousu, vice president of R&amp;D, spoke to the commissioner on the company&rsquo;s ability to make biofuels and biobased chemicals from nonfood raw materials during his visit. Along with Oettinger, Esa Hamala, the director general for the ministry of employment and the economy, also toured the facility in Oulu, Finland. Nearly a month earlier, Farooq Abdullah, Indian minister of new and renewable energy, also visited the park to discuss Chempolis&rsquo; technology. The prime minister was on a four-day tour across Finland that aimed to &ldquo;promote cooperation in the exchange of renewable energy know-how and technology between the countries.&rdquo; Earlier this year Chempolis signed with a Chinese company to build a biorefining facility similar to the Oulu facility. The company has already appointed a managing director for the joint-venture, Esa Niemi, to oversee the company&rsquo;s operations in its Asia Pacific pulp and biofuels businesses. Chempolis has invested roughly $20 million in R&amp;D, resulting in a portfolio of more than 100 patents. 5. Roughly 20,000 biobased products are made in North America, according to the USDA, but how many consumers are familiar with the term biobased? A leading enzyme maker based out of California might have a fairly good estimate. Through the company&rsquo;s study &ldquo;Household Sustainability Index,&rdquo; Genencor now has a better guess at how many people in the U.S. and Canada know about some of the products its enzymes help to produce. According to the study, four out of 10 American consumers &ldquo;have heard of the term &lsquo;biobased&rsquo; to describe products or product ingredients used in cleaning and personal care products, clothing and fuels such as ethanol and biodiesel.&rdquo; For Canadians, the number is roughly one-third of the population. Fortunately, the number of both Americans and Canadians that said they would &ldquo;definitely,&rdquo; or &ldquo;likely&rdquo; buy a biobased household product in place of a non-biobased product (if the cost and effectiveness of the products were the same) was much higher, totaling eight out of 10. Genencor currently provides enzymes for nearly 400 products, and Tjerk de Ruiter, CEO of Genencor, says that the findings of the study show that consumers are prepared to choose biobased products, &ldquo;especially those consumers who are familiar with green products and are generally confident about their environmental claims.&rdquo; 6. Sapphire Energy has signed with the Linde Group in an effort to collaborate on a commercial-scale system that could deliver CO2 to open-pond algae systems like those currently being used by Sapphire. Linde is currently the leading supplier of CO2 in the U.S., providing CO2 for processes like dry-cleaning to cooling food products. The goal of the project is cut the costs of delivering anthropogenic CO2 to the open ponds, and before the multiyear agreement is able to develop a commercial-scale system, Linde will provide CO2 at Sapphire&rsquo;s Columbus, N.M., demonstration facility. In the Netherlands, Linde has already created a CO2 delivery system that supplies 550 greenhouses with the gas through a 100-kilometer pipeline from a nearby refinery. &ldquo;Producing fuel by algae using CO2 from large emitters like power stations and chemical plants is a very promising way of reducing greenhouse gas emissions,&rdquo; says Aldo Belloni, a member of the executive board of Linde AG. According to Linde, a single commercial algae-fuel facility will require roughly 10,000 metric tons of CO2 per day. 7. A program in St. Louis is offering citizens the opportunity to become involved with algae biofuel development by collecting algae samples that will be analyzed for oil content at the Donald Danforth Plant Science Center. The second annual Backyard Biofuels Citizen Science Project kicked off May 7 with AlgaePalooza. The event was held in the Life Science Lab at the St. Louis Science Center, and is co-hosted by the Center for Advanced Biofuel Systems at the Donald Danforth Plant Science Center. Members of the public who attended the AlgaePalooza had the opportunity to talk with the research scientists behind the Backyard Biofuels Citizen Science Project and learn why algae has the potential to be a sustainable source of fuel used to power cars, trucks and airplanes. Attendees also learned how to identify various types of algae and participate in hands-on experiments and activities like painting with algae and making algae ball necklaces. 8. Genomatica and Mitsubishi Chemical Corp., the eighth largest chemical maker in the world, signed a broad memorandum of understanding (MOU) outlining multiple potential areas of collaboration. Mitsubishi and Genomatica will explore forming a joint venture to build the first commercial plant in Asia for Bio-BDO. This plant would use Genomatica&rsquo;s direct, one-step technology and leverage Mitsubishi&rsquo;s leadership in BDO applications and sales, as well as their manufacturing expertise. The companies will also discuss collaborating to develop several major chemicals, which are strategic to both companies. Mitsubishi also made an equity investment in Genomatica as part of Genomatica&rsquo;s recently-announced $45 million Series C-1 funding. &ldquo;We respect and share Genomatica&rsquo;s vision of the importance of sustainability for the chemical industry, and we recognize their achievements with C4 chemicals, which are strategic to us,&rdquo; says Hiroaki Ishizuka, representative director of Mitsubishi Chemical. &ldquo;Asia is the fastest-growing chemicals market in the world and we see great potential to deliver biobased chemicals to this market as a growing complement to our current conventionally sourced chemicals. We believe that a strategic partnership with Genomatica will provide market-leading economics and quality that will benefit both parties.&rdquo; 9. Evonik is helping to expand the bioenergy industry, and nearly every place from Argentina to Nebraska is reaping the benefits. Nearly a month after announcing that the German-based company would expand its global position in biodiesel catalyst production by building an alcoholate catalyst plant in Argentina, Evonik has ensured its business ventures in Iowa will also expand. Through a $50,000 donation, the company will &ldquo;help prepare individuals for work in the biotechnology and milling industries,&rdquo; according to the company. The money will be used to operate the Washington County Technology Center at the Cargill-owned Blair, Neb., BioRefinery Campus for five years. The hope is to train future employees for technical jobs within the campus. Alan Brewer, vice president of Evonik&rsquo;s Health and Nutrition Business Unit in North America, notes the critical need for highly trained, highly qualified people to work at the Evonik plant in Blair, which produces lysine, an amino acid used as a feed additive in the swine and poultry industry. &ldquo;In the past,&rdquo; Brewer says, &ldquo;Evonik has hired people and trained them. Now, graduates of the Technology Center program will have a leg up on qualifying for jobs offered by Evonik and other businesses.&rdquo; During a two-year program, students will develop skills in chemistry and other processes used at the facility on the way to earning an associate degree in applied technology.
&nbsp;
Share your industry briefs To be included in Business Briefs, send information (including photos and logos if available) to: Industry Briefs, Biorefining, 308 Second Ave. N., Suite 304, Grand Forks, ND 58203. You may also fax information to (701) 746-8385, or e-mail it to rkotrba@bbiinternational.com. Please include your name and telephone number in all correspondence.

The process formula being used successfully by Inbicon in its Danish biorefinery has not yet seen the same success in wheat-straw biorefining tests in North Da&shy;kota. Cole Gustafson, professor from North Dakota State University, says that &ldquo;the bottom line is yes, it can be commercially done&rdquo; in North Dakota. But for that to happen, the biorefinery will have to overcome some common, and not so common, hurdles to get there. Collection of wheat-straw biomass is already happening, Gustafson says. &ldquo;We have a cabinet manufacturer who is collecting wheat straw to make a composite panel that is used for cabinetry,&rdquo; he points out, and the cabinet maker is paying $15 a ton for the biomass if it is left in the field and an additional $35 a ton if it is baled and delivered to the facility. But, like most projects, even though the collection of the feedstock may be possible, there is still a density versus distance issue. In this case, the areas of the greatest wheat straw density are further away than the desired distance. Another common issue that could affect the success of the biorefinery is some basic agronomic information that Gustafson thought would be readily available: plant matter left standing after initial harvesting. Because the information didn&rsquo;t exist, he spent a week driving through North Dakota collecting information and determined that the average height of the wheat straw farmers are leaving is seven inches. But issues such as density versus distance or the amount of biomass typically left in the field after a harvest will affect every project. It&rsquo;s the state&rsquo;s unemployment rate though that shows why every project really is different. &ldquo;When we looked at their (farmers) preferences, they are interested in leaving the straw in the field and not doing much more than that,&rdquo; he explains. Why? Because the state has one of the lowest unemployment rates in the nation at roughly 2 to 3 percent, meaning that farmers don&rsquo;t have access to labor in rural areas. &ldquo;So,&rdquo; he said, &ldquo;they were very hesitant to committing any additional field operations to bale, collect or store because they didn&rsquo;t have a labor source.&rdquo; But the labor force dilemma isn&rsquo;t the only hurdle that shows why a project developer can&rsquo;t base a project strictly off past projects. In North Dakota, he explains, there is a question of who to negotiate with to purchase biomass crop residues. &ldquo;It turns out that in most cases the tenant has a say in terms of what can be done with the crop stovers.&rdquo; But, he adds, &ldquo;the tenant has to leave the land in the same condition as he acquired it at the beginning of the production period,&rdquo; noting that this can be another dilemma in feedstock contracts. Even with state-specific challenges, however, Gustafson says, &ldquo;everything at this point looks very positive.&rdquo; &mdash;Luke Geiver

Don't forget that no two projects are alike

What Unemployment Rates Tell Project Developers

The goal for any cellulosic ethanol developer is to perform the necessary due diligence at pilot and demonstration scale before making the leap to commercialization. That&rsquo;s exactly what Canadian cellulosic ethanol developer Lignol Energy Corp. did when, with its Vancouver-based engineering contractor Poyry Inc., it completed an engineering design package for a commercial-scale biorefinery that could potentially produce up to 80 MMly (21 MMgy) of cellulosic ethanol and 55,000 metric tons of lignin, trademarked HP-L, derivatives annually. In its design calculations, Lignol took into account the recent price of crude oil, incentives for the construction of biorefineries and the production of advanced biofuels along with pricing indications received from key suppliers and customers. Additionally, the company intends to perform ongoing studies at its 100,000 liter per year pilot-scale cellulosic ethanol facility on the campus of the British Columbia Institute of Technology in Burnaby, British Columbia, to refine the design basis and equipment selection needed to scale up its proposed commercial plant. &nbsp;&ldquo;Completing this milestone is a significant step forward in our plan to develop a financially viable, commercial-scale biorefinery and market our technology worldwide,&rdquo; says Ross MacLachlan, president and CEO of Lignol.&nbsp; &mdash;Bryan Sims

How forward-thinking cellulosic development is key to achieving commercial-scale 

Innovation by Design

Despite a recovering economy, a number of biorefining firms are obtaining the necessary capital to take their technologies to the next level. Mountain View, Calif.-based biobutanol developer Cobalt Technologies, for example, landed $20 million in Series D financing in April. The deal was led by The Whittemore Collection Ltd., the investment vehicle of Parsons &amp; Whittemore, formerly one of the world&rsquo;s largest manufacturers of pulp. Chief financial officer Steve Shevick says the added capital will enable Cobalt, in collaboration with American Process Inc., to build a 470,000-gallon-per-year demonstration facility in Alpena, Mich., which is currently under construction. The plant, anticipated to be the nation&rsquo;s first cellulosic ethanol and biobutanol production plant utilizing biomass sources, is scheduled to be operational by second quarter 2012. Shevick wouldn&rsquo;t disclose how much of the $20 million would be going toward financing the Alpena project, but admits that the funding Cobalt received is an indication that investor confidence may be mounting to aid commercial development. &ldquo;Many data points indicate a greater belief in the biorefining industry, not just our Series D, but also the successful IPOs of Amyris and Gevo, the pending IPOs of Solazyme and KiOR, and a growing number of strategic relationships being formed between startup biorefining companies and major fuel, chemical, agriculture and consumer projects companies,&rdquo; Shevick says. &ldquo;As [investors] have emerged from the recession they are now taking a look at the products and technologies of the future, and that&rsquo;s biorefining.&rdquo;&nbsp; &mdash;Bryan Sims

How the investment window is opening in the biorefining sector

Capital Infusion

While an increasing number of biorefining firms are focusing on converting wood biomass&mdash;logs or chips&mdash;into biofuels, biochemicals and other bioproducts, scientists are also exploring how best to extract value-added bioproducts from the abundant, yet underuti&shy;lized, fraction of the wood: the bark. Among these is the Bark Biorefinery Consortium, a team of world-class experts in biomaterial, adhesive and polymer sciences, chemistry and chemical engineering, seven industrial partners and several government research organizations engaged in a four-year collaboration led by researchers from the University of Toronto and Lakehead University, in Ontario, Canada.&nbsp; According to Ning Yan, principal investigator at the University of Toronto, the BBC is focused on producing two major industrial bioproducts from tree bark. One, she says, is to exploit the inherent aromatic compositional properties within tree bark and produce a substitute for phenolic-based adhesives. The other platform is to break down bark components, either through extraction or chemical conversion, to produce biobased intermediates in polyurethanes or foams, such as isocyanate, which is commonly found in bark-derived foams. &ldquo;We hope to be able to produce a more environmentally friendly counterpart and hopefully at a lower cost from a forest residue like bark,&rdquo; Yan says. She adds that while the majority of the research is being conducted in the lab, the goal is to demonstrate the processes at pilot scale and envisions existing saw mills integrating the process as a complimentary utilization effort with bark used as hog fuel. &ldquo;We already have promising results for the feasibility of an integrated bark biorefinery that could convert the aromatic portions for biobased adhesives and cellulosic fractions that could be converted into foams,&rdquo; Yan says. &ldquo;We have demonstrated promise in the lab, but optimization efforts are ongoing to perfect the process.&rdquo;&nbsp; &mdash;Bryan Sims

Wood biomass utilization is taking on a whole new shape in Canada

Taking Stock in Bark

A team of researchers at NASA&rsquo;s Dryden Flight Research Center recently tested renewable jet fuel in a DC-8 aircraft. According to information released by the administration, the biobased jet fuel used in the test was manufactured from chicken and beef tallow. Information released by NASA states that the research team ran one engine using hydrotreated renewable jet fuel (HRJ), another using JP-8, and a third using a 50/50 blend of the two fuels. The testing, referred to as the Alternative Aviation Fuels Experiment, occurred with the plane on the ground. The research team evaluated both the fuel&rsquo;s performance and resulting emissions. According to NASA, the evaluation included measurements of nitrogen oxide and particulate emissions. Data released by the organization notes that black carbon emissions were 90 percent less at idle in the engine that burned the HRJ, and nearly 60 percent less at takeoff thrust. According to Bruce Anderson, the experiment&rsquo;s chief scientist, the biofuel also produce significantly lower sulfate, organic aerosol, and hazardous emissions than the standard, fossil-based jet fuel. &ldquo;The test results seem to support the idea that biofuels for jet engines are indeed cleaner-burning, and release fewer pollutants into the air. That benefits us all,&rdquo; says Ruben Del Rosario, a researcher at NASA&rsquo;s Glenn Research Station in Ohio who manages the organization&rsquo;s Subsonic Fixed Wing Project, which sponsored the experiment through the Fundamental Aeronautics Program.&nbsp; &ldquo;NASA Dryden was excited to contribute to the study of alternative fuels for aviation use,&rdquo; says Frank Cutler, NASA&rsquo;s DC-8 flying laboratory project manager in a release issued by NASA. &ldquo;The results of these tests will tell us a lot about emission generated by modern turbine aircraft engines using these fuels.&rdquo;&nbsp; &mdash;Erin Voegele

NASA tests renewable fuel blends in a DC-8

Positive Results for Biojet

A new symbol will soon aid consumers in identifying products made using renewable, bioplastic materials. The symbol, which was chosen via a competition titled &ldquo;Make Your Mark,&rdquo; was announced by Cereplast Inc. on Earth Day Eve. Cereplast and its partners will initially use the symbol to differentiate its products from traditional, petroleum-based plastics. According to Nicole Cardi, Cereplast&rsquo;s vice president of marketing and communications, it is also possible that the symbol will be opened up for wider use in the future. Cardi said the new symbol will be featured on Cereplast products as soon as possible. &ldquo;We actually have some new products that we are rolling out soon&hellip;and anticipate rollout [of the symbol] within the next few months at the very least,&rdquo; she says. Cereplast&rsquo;s Make Your Mark competition was modeled after a similar graphic design contest in 1970 that resulted in the recycling symbol. More than 1,500 bioplastic symbols were submitted to the Cereplast. The winner was selected using a multitiered voting system that featured a public voting component. More than 2.8 million public votes narrowed the selection to 200 finalists which were further ranked by a panel of judges that included Gary Anderson, the creator of the recycling symbol. The winning design was created by Laura Howard, a third-year design student at the University of Louisville in Kentucky. &ldquo;We are excited to congratulate Laura Howard for designing a symbol that has the potential to become a revolutionary logo representing the next generation of plastics&mdash;plastics that protect and preserve our environment and are made from renewable resources,&rdquo; says Frederic Scheer, Cereplast&rsquo;s chairman and CEO. &ldquo;The new bioplastic symbol will be used in a similar fashion to the recycling symbol as it will be stamped on products, and it will serve as an identifying mark of bioplastic material&hellip;We believe that this new symbol will help provide consumers with the tools they need to make more environmentally intelligent purchasing decisions.&rdquo; According to Howard, the symbol she submitted was designed to represent the creation of a structural element from a plant source. She also noted that she was familiar with bioplastics before entering the competition. &ldquo;That&rsquo;s one of the things that drew me to the contest,&rdquo; she says. &ldquo;I am very excited to be part of that movement.&rdquo;&nbsp;&nbsp; &mdash;Erin Voegele

Cereplast's new symbol distinguishes biobased plastic from fossil-based counterparts 

Differentiating  Bioplastics

Don&rsquo;t mistake BioAmber Inc. as a biochemical company that would gloat or come off as pretentious when it comes to having the confidence that its two biobased product offerings derived from agricultural residues&mdash;succinic and adipic acid&mdash;will someday enter the commercial market. &ldquo;We think we have a pretty good business plan,&rdquo; Mike Hartmann, vice president of corporate affairs, tells Biorefining Magazine. In April, BioAmber joined forces with Mitsubishi Chemical Corp. in the field of biobased succinic acid, in a strategic agreement that makes BioAmber and Mitsubishi Chemical&rsquo;s distribution partner, Mitsui &amp; Co., exclusive suppliers of biobased succinic acid to Mitsubishi Chemical. As a result, the three companies plan to conduct a feasibility study to build a succinic acid production facility adjacent to Mitsubishi&rsquo;s planned polybutylene succinate (PBS) production plant in Thailand. BioAmber and Mitsubishi Chemical also intend to incorporate elements of Mitsubishi&rsquo;s succinic acid technology into BioAmber&rsquo;s biobased succinic acid platform. The goal, according to Hartmann, is to produce low-cost succinic acid that will drive down the manufacturing cost of Mitsubishi Chemical&rsquo;s patent-protected PGS, a renewable and biodegradable polymer. BioAmber has begun to supply Mitsubishi Chemical with biobased succinic acid produced at its 2,000-metric-ton-per-year commercial facility in Pomacle, France. BioAmber has also secured the right to source biobased PBS from Mitsubishi Chemical for its modified PBS polymers, which are marketed through its Sinoven Biopolymers subsidiary. Additionally, BioAmber secured $45 million in a Series B round that will be used to accelerate the commercialization of biobased succinic acid and modified PBS via its forged venture with Mitsubishi Chemical, including funding ongoing development work on biobased succinic acid in collaboration with Cargill Inc., to strengthen its management team and build out its research and development capabilities to accelerate development of its adipic acid platform. According to Hartmann, BioAmber intends to use a portion of the funds toward the construction of a proposed commercial biobased succinic acid production facility in North America. While a specific location isn&rsquo;t determined, Hartmann says the company has identified potential sites in Canada and in the Midwestern U.S. &ldquo;It all comes down to what kinds of government funding, whether its state, provincial or federal, we can leverage for the project,&rdquo; Hartmann says. &ldquo;That&rsquo;s a definite consideration aside from the logistical issues with siting a project like this.&rdquo;&nbsp; &mdash;Bryan Sims

How BioAmber is closer to achieving commercial scale than one might think

Amber Waves of Potential

Researchers at Michigan State University, led by Bruce Dale, professor in the department of chemical engineering and materials science, have found a way to use the properties of lignin to their advantage. To do it, they&rsquo;ve nearly perfected a process they call AFEX, ammonia fiber expansion. Using AFEX, the team has also shown that transporting biomass can be much more efficient if the properties of lignin, namely its binding qualities, are put to use to form (or bind) the biomass into easy to transport biomass packs that are similar to briquettes. Dale, who has been working on the AFEX process for roughly 30 years, says that some people might be familiar with the process as a gaseous treatment to improve the material for animal feed. To form the biomass packs, here is how it works. Starting with plant material that can contain moisture content as high as 50 percent, the process uses roughly a pound of ammonia for every pound of plant matter. The biomass (hay, straw, corn stover, etc.) is treated at 150 to 200 degrees Fahrenheit for approximately 15 minutes at a pressure of 200 pounds per square inch. After the treatment time is up, the ammonia evaporates and nearly 20 to 30 percent of the original amount is recovered. &ldquo;One of the effects of the treatment is to break down the lignin into smaller pieces,&rdquo; Dale says. &ldquo;When the pressure is released, the mixture of ammonia, water and lignin migrates to the surface of the plant fiber and it leaves behind the lignin fiber, which is naturally sticky.&rdquo; Essentially, the AFEX process breaks down the lignin into pieces that are more than capable of acting as a binding agent to hold the rest of the biomass together, making the biomass easily compactable and transportable. The material, Dale says, &ldquo;has about the bulk density of corn and it flows like corn and should store well in grain handling equipment.&rdquo; And, because the AFEX-effected biomass holds those properties, Dale believes the system will allow for a more distributed process approach for biomass to biofuel biorefineries. The idea is to utilize regional biomass processing depots that perform this pretreatment step and densify the biomass. &ldquo;We envision a series of these smaller distributors that maybe process a hundred tons a day of plant material that could be owned by rural interests.&rdquo; This vision can all be made possible, he says, because of one of the greatest advantages to the AFEX process. &ldquo;There are no other processes like the AFEX process&rdquo; that would work, he says, on a distributed basis because, unlike the AFEX process, they all use heavy amounts of water.&nbsp; &mdash;Luke Geiver

Already licensed, ammonia fiber expansion can cut biomass transport costs

The AFEX Has Almost Arrived

North Carolina-based Avjet Biotech Inc. has announced the selection of Boulder, Colo.-based Continental Technologies LLC to establish its pre-prototype laboratory system, prototype aviation biofuel facility and commercial aviation biofuel refinery. Continental Technologies has experience designing, fabricating, installing and operating refineries and other processing systems. &ldquo;Our agreement with Continental Technologies will produce plans, specifications, schematics and equipment designs that we can implement at other small, distributive refineries across the globe,&rdquo; says Marty Oliver, president of ABI. &ldquo;Continental&rsquo;s knowledge, support and years of experience will help Avjet become the turnkey provider for organizations that need small, distributive refineries.&rdquo; According to Avjet Biotech, it has delved a unique, patented refining technique that utilizes a thermal catalytic process to refine triglycerides into aviation fuels. The technology, referred to as the RWR System, is currently under development for sale as a small distributive refining system. The company&rsquo;s subsidiary Red Wolf Refining has already been approached by potential customers regarding sublicenses. &ldquo;We are pleased to take this next step forward to see the laboratory scale facility built on the N.C. State University campus,&rdquo; says Don Evans, chairman and CEO of ABI. &ldquo;As our facilities grow into three stages of production scale, we will be able to provide aviation biofuels that will benefit the military and commercial aviation biofuel demands worldwide.&rdquo;&nbsp; &mdash;Erin Voegele

Avjet Biotech selects design, installation partner

Preparing a Prototype

Reports on global potential for clean technology, renewable energy or any other category that biodiesel might fit into, reveal an obvious fact: The maximum potential for the development, production or use of renewable energy in India, in this case biodiesel, is virtually unlimited. Most of us don&rsquo;t need a report to tell us that India is a massively populated, rapidly developing nation that is fast catching up to the rest of the world in its quest and usage of energy. More specific information can be found in a report Novozymes commissioned this year that shows fuel demand in India will grow by 8.5 percent a year by 2020. Roughly estimated, a $100 barrel of crude would equate to $19.4 billion the country would spend on imported fuel. A report done by the Pew Charitable Trusts earlier this year examining global investment in renewable energy shows that, for the first time, India has entered into the top 10 countries of the G-20 nations that have invested clean energy dollars over the past year.
 Combine all of those report findings with the high volume of diesel vehicles or the promising allure of a nonedible feedstock that can be grown on marginal lands from coast to coast, and it&rsquo;s easy to see why India creates so much excitement and grandiose visions of future biodiesel production capacity. Unfortunately, however, no statistics on available acres suitable for jatropha, number of diesel engines required, or size of population in need of a safe, renewable energy source indicate the amount of time it will take to convert those big dreams into a significant biodiesel powerhouse.
 To provide a more accurate picture of the biodiesel landscape in India, Biodiesel Magazine left the reports behind and spoke with individuals who&rsquo;ve experienced first-hand what the country does, and does not, have to offer renewable energy producers. Their perspectives show us that big potential has meant very little to the country&rsquo;s progression towards greater biodiesel or other renewable fuel usage. Their personal reports, however, indicate that there is still hope.
 The Traveling Professor
 When Biodiesel Magazine first spoke with Kasiviswanath Muthukumarappan (Muthu for short), professor of agriculture and biosystems at South Dakota State University, he was calling from a hotel room in China, well past midnight. Muthu is part of the innovative SDSU research team that has tackled everything from biomass handling to algae cultivation, and as his call demonstrated, Muthu is not afraid of spending time away from South Dakota, traveling to China, Italy, Indonesia and certainly, India. For our second conversation, Muthu called from Washington, D.C., where he was reviewing proposals to the USDA regarding food processing techniques.
 Last year, he attended a first-ever biofuels conference in India and, since then, he says his inbox has been filled with requests to return. In addition to last year&rsquo;s conference, he&rsquo;s been to India several times looking for new collaborators. &ldquo;We are trying to work through proposals and collaborations with China and India,&rdquo; he says. But a seminar on biodiesel or other biofuels is vastly different in Atlanta than it is in India or China, he says. &ldquo;It is very difficult to compare the trips. You aren&rsquo;t comparing apples to apples,&rdquo; he says. &ldquo;It is different going to India.&rdquo; While there is a lot of work going on in India and China in terms of biodiesel, according to Muthu, there isn&rsquo;t as much in comparison to the U.S., Europe or Latin America.
 &ldquo;There is not much going on with biofuels [in India],&rdquo; he says, &ldquo;because there just is not much feedstock. They cannot collect feedstock at the higher amounts.&rdquo; Although biofuels research is lacking, Muthu says of all biofuels, biodiesel gets the most attention as several research institutions are testing different oilseeds as feedstocks.
 In addition to the research efforts in biodiesel throughout the country, Muthu also explains that during his visits to conferences or meetings, he&rsquo;s not only linking up with other researchers, but also private companies. &ldquo;I have some important contacts from those meetings,&rdquo; he said. One of which is Praj Industries, a global EPC contractor and technology developer that has already signed on with U.S.-based Qteros to help in building a facility that would put the Qteros Q-microbe for cellulosic ethanol production to work.
 As Muthu explains, though, it is apples to oranges when comparing a trip to Washington, D.C., with a trip to New Delhi. There is no lack of research happening in either country, but the logistics and necessities of feedstocks are vastly different, and have put the biofuels industry in India years behind the U.S. But, even with the differences, Muthu says his trips and time spent in underdeveloped places such as India are worth it. &ldquo;They want to collaborate with us,&rdquo; he says, adding that he is already working through a number of proposals for collaborations that would possibly send some of his students back to India to help tackle the issues of feedstock logistics and operating costs confronting the developing nation. &ldquo;It could create a win-win situation,&rdquo; Muthu says.
 Indian Producer Tells All
 If Muthu represents a perspective showing the type of work being done to develop India, then Sanjeev Gupta, president of Universal Biofuels, a 50 MMgy biodiesel facility in India, represents a perspective of what is already happening. Listen to Gupta, and all of the numbers from those reports start to seem misleading. When asked a general question on the state of biodiesel in India, Gupta replied, &ldquo;Literally, nothing is happening.&rdquo;
 The Kakinada, India, plant, a wholly owned subsidiary of U.S.-based AE Biofuels Inc., was built in 2008 by Desmet Ballestra, and, according to Gupta, is only one of about six facilities remaining in the entire country. &ldquo;We are still open because we are doing a little bit of this and a little bit of that,&rdquo; Gupta says. &ldquo;I&rsquo;m trying to compete and wrestle with the Indonesian and European markets.&rdquo;
 From Gupta&rsquo;s perspective, the general landscape for biodiesel production in India doesn&rsquo;t reflect the promise of potential seen in those reports, but rather the reality of a dysfunctional government unwilling or unable to make good on promises that would significantly help the industry. First, he says, export regulations do not allow the country to export their product. As far as the domestic market is concerned, he says, &ldquo;The problem here in India is that the government controls the refining and distribution of all petroleum products,&rdquo; and, with the sort of emphatic tone to his voice that one could only take as a true feeling of concern, &ldquo;it is a very corrupt system over here.&rdquo;
 Essentially, Gupta says, the government&rsquo;s attempts to further the industry have been muddled due to that corruption. While the government has said it will give a tax break to fuel mixed with a blend of 5 percent or more biodiesel, that benefit has never been realized by Gupta or any other producer. The problem, he explains, is linked to the &ldquo;tax guy,&rdquo; who is unwilling to recognize a blended product. So, he says, &ldquo;you pay the same tax (for a blended product) as you would pay on regular diesel. They are basically asking me,&rdquo; he explains, &ldquo;to call the biodiesel blended diesel, diesel.&rdquo;
 &ldquo;This is not a developed nation so people don&rsquo;t understand,&rdquo; he says. There are scams coming out every day that Gupta says most people don&rsquo;t even hear about. Because of that, &ldquo;the government doesn&rsquo;t have time to look at everything.&rdquo;
 Gupta hasn&rsquo;t been one to sit idle in the face of a corrupt system that has virtually capped his ability to make a profit via biodiesel. He says he&rsquo;s gone all the way to the top, which appears at first glance to clearly be in favor of renewable energy such as biodiesel. In 1987, the country established the Indian Renewable Energy Development Agency as a specialized financial institution to provide support for energy conservation and renewable energy projects. IREDA, a part of the Ministry of New and Renewable Energy, has since financed 1,921 projects reaching a $3 billion. The IREDA recently stated that &ldquo;of late, the growing awareness and favorable government policies and regulatory mechanisms (both at the central and state level) have led to gradual increase in confidence of domestic commercial banks providing loans to renewable energy projects.&rdquo;
 But, for all that talk, Gupta says he cannot reach the traditional transportation market. &ldquo;I&rsquo;m basically catering to the fleet owners and the discretionary blenders and the industrial sector,&rdquo; he says. Because India is a net importer of oils, and palm oil is the cheapest, closest available feedstock, Gupta uses only palm oil. Waste vegetable oil (WVO) or used cooking oil isn&rsquo;t even a viable prospect, he says, noting again the nation&rsquo;s need for further development, and the fact that WVO is simply reused again and again until it&rsquo;s totally consumed.
 Of course, the obvious beacon of hope, something that could provide a viable, cheap feedstock is jatropha. Remember Gupta&rsquo;s thoughts on the state of biodiesel&nbsp; activity in the country? He holds the same perspective for jatropha. Even with companies like Mission NewEnergy basing its business model on the toxic, nonedible plant in Gupta&rsquo;s own India, he says, &ldquo;Jatropha isn&rsquo;t even a [pipe] dream now.&rdquo; So what, he says, if some researcher is trying to do some research, looking for a hybrid that can yield 2 to 3 tons of oil on marginal land. On marginal land jatropha won&rsquo;t be able to meet those yields, he says, and the industry can&rsquo;t wait the two to four years it will take to grow and develop the plant. &ldquo;If somebody tells me they have a hundred acres, I&rsquo;ll believe them, but that isn&rsquo;t even enough for my one day's worth of production.&rdquo;
 Even though Gupta&rsquo;s outlook on the biodiesel industry in India is bleak at best, and his stance on the savior feedstock jatropha is even worse, he does share some of the same sentiments of Muthu, and even those promising reports. The speed of research being done in the Americas, he says, is far ahead of India. But, if the U.S. comes up with a new technology or figures out algae, he says, &ldquo;India will adopt it. India has a lot of sun and a huge coastline.&rdquo;
 As for a perspective rivaling those reports that indicate India is an untapped promise land for renewable energy, Gupta explains it this way. In the U.S., he says, when the tax credit went away, most figured it would come back and the industry would be strong again. That happened, he says. But in India, we just don&rsquo;t know what will happen. But if a 5 percent mandate was actually enforced, or the tax situation was cleared up, &ldquo;this is a huge market and we could all be running full capacity the very next day.&rdquo; Author: Luke Geiver Associate Editor, Biodiesel Magazine (701) 738-4944 <a href="mailto:lgeiver@bbiinternational.com">lgeiver@bbiinternational.com</a>
&nbsp;
A View from Japan Electric cars and government shortcomings won&rsquo;t stop biodiesel here The condition of ineffective governmental support and general lack of feedstock is not unique to India. Atushi Yoshiike of Revo International, Japan&rsquo;s largest biodiesel producer, says that even though Korean and Chinese governments have committed to promoting the use of a mixed fuel made of biodiesel and petrodiesel, &ldquo;there is a lack of feedstock oil in these countries." In both countries, he explains, there are tentative plans to increase the blend ratio from 1 percent to 3 to 5 percent within a few years.
 His home country of Japan supports a B5 blend, but unfortunately, &ldquo;there is no concrete plan in place," Yoshiike says. And, like Gupta, who said infrastructure supply issues make fueling the general transportation market with biodiesel very difficult, Yoshiike says &ldquo;we are not able to use the existing infrastructure to supply biodiesel because the petroleum industry in Japan is blocking the spread of biodiesel.&rdquo; &nbsp;&nbsp;&nbsp;
 Yoshiike&rsquo;s thoughts on Japan rival those of Yi-Fa Lee, the chairman of Chant Oil Corp., a biodiesel producing company based in Taiwan, who recently spoke about the Chinese government and its lack of biodiesel support in the Chinese newspaper, the China Post. Lee said the biodiesel industry was started by the government in 2006, but is now on the brink of collapse and is ultimately &ldquo;in need of rescue.&rdquo;
 Much like Gupta, Yoshiike does see the potential of biodiesel in Japan based on the possible size of the market, even though he says similar changes are needed in his country as those Gupta says are required in his. &ldquo;We face many difficult problems such as taxation and a lack of support for biodiesel,&rdquo; he says, adding that with the growing popularity of hybrid engines and electric cars, &ldquo;we believe that diesel engines will continue to be a popular engine all over the world.&rdquo;

FEEDSTOCK CONSTRAINTS:  Kasiviswanath Muthukumarappan, right, a professor at South Dakota State University, says the biodiesel work going on in India and China isnâ€™t much in comparison to the U.S., Europe or Latin America, mainly because of feedsto

2011/08/13135184899495.jpg

PROFESSOR BLUNT: Kasiviswanath Muthukumarappan, an SDSU professor of agriculture and biosystems, says, quite frankly, India has â€œnot much going onâ€� in biofuels, due to government corruption and ineffective policy. 

2011/08/13135185418638.jpg

SHARE THE BURDEN: Japan is recovering from a natural disaster, but along with policy shortcomings and feedstock supply issues, it continues to work at biodiesel production on all levels. 

2011/08/13135185795249.jpg

BETTER EVERY TIME: Each visit to India or China for Muthu has helped him develop relationships that allow his students to learn more about the challenges to feedstock supply each country faces. 

2011/08/13135186230661.jpg

WORK IN PROGRESS: Although the work of Farooq Abdullah, union minister for new and renewable energy in India, has looked at several renewable energy provisions, there is a disconnect between policy and enactment. 

2011/08/13135186628869.jpg

A researcher and a producer explain what it will take

Developing  India

Latin American countries continue to take ambitious steps to promote production and consumption of biodiesel. Predictably, in South America, Brazil and Argentina continue to dominate with several large-scale projects in queue, and Columbia, among others, is showing potential as a biodiesel producer and exporter. In Central America, Guatemala and Costa Rica and others are also making expansive efforts.
 Brazil&rsquo;s biodiesel market is experiencing healthy growth built around solid public policy, and it is beginning to have positive effects on the Brazilian trade balance. In January 2010, the mandated blend requirement for biodiesel in Brazil was increased from B2 to B5, three years ahead of initial scheduled targets under the national Program for the Production and Use of Biodiesel launched in 2004. This year, the Brazilian Biodiesel Union requested that the government adopt measures to increase the mandated blend requirement to B20 by 2020, and because a tight domestic supply balance for soybean oil is expected, trade sources don&rsquo;t foresee any increases to the current B5 blend requirement until 2013.
 Brazil&rsquo;s soybean processing, refining and bottling capacity continues to grow, with soybean oil consumption estimated at 5.7 million metric tons in 2011-&lsquo;12, according to a USDA Foreign Agricultural Service report published in April, and 2.2 million metric tons of that expected to be used as feedstock for biodiesel production. Rising biodiesel production may hamper Brazil&rsquo;s soybean oil exports this year, however, according to a report published in June by Hamburg, Germany-based Oil World. Brazil, the world&rsquo;s second leading soybean oil exporter, may sell only 1.5 million metric tons of soybean oil for the remainder of the year, according to Oil World, down from 1.56 million metric tons in 2010. It is expected though that within five years, palm oil will cut into the soybean oil capacity used in the food industry and thus free up additional soybean oil for biodiesel production. Soybean oil accounts for 82 percent of biodiesel produced in Brazil, followed by animal fats (14 percent) and cottonseed oil (2 percent), with other oilseed crops such as castor bean and palm oil used in nominal quantities, according to the USDA FAS.
 Brazil is the fifth largest biodiesel producer in the world, coming in just behind Argentina, and houses 69 biodiesel plants with a combined annual installed capacity of more than 5 billion liters (1.32 billion gallons). In 2010, biodiesel production reached 2.4 billion liters under its B5 blend mandate. The USDA FAS report estimates that an additional 150,000 metric tons of soybean oil will be required annually to maintain production levels under its current B5 requirement.
 Investments in new and developing biodiesel projects continue to be made as several big-name agribusiness and pure play biodiesel companies announced plans this year to expand operations in the country. In June, BioVerde Industria e Comercio de Biocombustiveis S.A., which is building Brazil&rsquo;s largest biodiesel plant, expects to sell 40 percent of its output to Europe by 2015. BioVerde is also committed to becoming Brazil&rsquo;s leading specialty chemicals manufacturer from renewable sources. BioVerde plans to retrofit a facility in the state of Sao Paulo that will be able to convert vegetable oils into 100 million liters per year of chemicals for industrial applications.
 In July, state-controlled oil and gas giant Petrobras forged a partnership with in-country producer BSBios Industria e Comercio de Biodiesel Sul Brasil S.A. to evaluate new biodiesel, ethanol and specialty chemical projects. Petrobras acquired a 50 percent stake in BSBios as part of the agreement. According to Petrobras, it plans to spend $3.5 billion through 2014 to boost biofuels ouput. The stake in BSBios &ldquo;consolidates Petrobras&rsquo; leadership in the biofuels sector,&rdquo; according to a company statement. Other notable projects under development in Brazil include a 414,800-liter-per-year biodiesel project located in the state of Mato Grosso developed by Bunge Alimentos SA. In 2010, Archer Daniels Midland Co. announced plans to construct a biodiesel plant adjacent to its existing oilseed operations in Jaocaba, and Brazilian energy company Companhia Paranaense de Energia, or Copel, is developing a very small-scale (about 5,000 liters per year) biodiesel plant in Sao Jorge d&rsquo;Oeste.
 Argentina 
 Like Brazil, Argentina&rsquo;s biodiesel industry has seen explosive growth in recent years with a healthy blend mandate to spur domestic production, feeding excess volumes to export markets&mdash;mainly to Europe.
 Argentina remains the global export leader of biodiesel, surpassing the U.S. last year. Its biodiesel exports are forecast at a record 1.6 billion liters by the end of the year, according to a USDA FAS report released in July, and in 2012, are projected to reach a record 1.75 billion liters as the country could easily supply additional volumes if the demand is stronger, depending on unused capacity and availability of feedstock. An outlook report by the Economic Cooperation and Development and the Food and Agriculture Organization of the United Nations, says Argentina is expected to reach about 2.5 billion liters by 2020.
 Despite its established export regime, there will surely be no shortage of feedstock&mdash;soy oil&mdash;or volumes of biodiesel to fulfill its national B7 mandate, which went into effect late last year. By the end of 2011, Argentina is projected to produce about 2.5 million tons of biodiesel and 3 million tons in 2012, its highest forecast ever, according to Carlos St. James, managing director of Santiago &amp; Sinclair LLC, an advisory firm focusing primarily on Latin American biofuel markets. St. James is also president of Argentine Renewable Energies Chamber (CADER). Much of the uptick in production, St. James explains, can be attributed to fulfilling the B7 mandate and the government potentially increasing the mandate from B7 to B10, possibly by the end of this year or early next. Additionally, a possible B20 mandate could be implemented for the agribusiness sector to use in off-road equipment and vehicles.
 &ldquo;We are now working to increase to a [national] B10 level and are in trials while negotiating with the automotive and oil industries,&rdquo; says St. James, adding that the government has strict oversight on how much volume gets produced under the current B7 mandate and how its data is recorded and published each month.
 Meanwhile, there was a flurry of biodiesel activity this year in Argentina as five biodiesel plants, ranging in annual production capacity from 4,000 to 240,000 tons (1.2 million to 72 million gallons). Currently, the country has 25 formally approved biodiesel plants.
 &ldquo;The larger plants tend to focus on export markets and the smaller ones on the domestic market,&rdquo; St. James says. &ldquo;Investment continues to grow and new biodiesel plants are coming online in the next two years in all sizes, from Cargill with a new 240,000-ton-per-year plant coming online at the end of this year, to a handful of smaller plants that will operate on unrefined cottonseed oil and tallow.&rdquo;
 As far as competition between process technology providers and design/build firms go in Argentina, Lurgi Inc. remains at the top with a commanding 45 percent market share, and a variety of local and U.S.-based process technology providers, such as Westphalia, Desmet Ballestra and Crown Iron Works, all holding another 23 percent, according to St. James. Desmet Ballestra, in particular, has built two major biodiesel plants in Argentina, plus several pretreatment facilities for plants supplied by its competitors, according to Fernando Markous, general manager for the firm&rsquo;s Argentina-based office. &ldquo;We recently signed a contract for a third plant with pretreatment included,&rdquo; Markous says. &ldquo;We also have exported one plant to Peru and two plants to Colombia.&rdquo;
 St. James adds that the investment climate in Argentina for the most part remains healthy, but contends that the gap between the smaller and larger producers needs to close more in order for the smaller producers to have a more competitive advantage. A key driver behind Argentina&rsquo;s surge in biodiesel investment is a differential export tax on biodiesel compared to that of soybean oil, he adds. Soybean oil exports are taxed 32 percent while biodiesel exports are only taxed 16.6 percent, enabling biodiesel producers to benefit from a 2.5 percent rebate. The current net difference between the two is 17.8 percent, which favors large biodiesel producers focused on the export market.
 &ldquo;Investment continues to grow rapidly in Argentina for large plants and small ones,&rdquo; he says, adding that access to working capital continues to be the largest hurdle for a majority of producers, big or small. &ldquo;The government has worked out most of the kinks in the approval process and has established a pricing mechanism that is favorable to smaller producers in the domestic market to help them offset their lack of economies of scale.&rdquo;
 While the majority of Argentine biodiesel exports are destined for Europe, the U.S. and Canada are also on Argentina&rsquo;s radar as possible candidates, particularly with the U.S. biodiesel blenders tax credit set to expire at the end of this year coupled with Canada&rsquo;s biodiesel mandate that went into effect in July. &ldquo;The Argentine biodiesel industry is looking to diversify exports into North America and is in the process of preparing to enter these potentially very lucrative markets,&rdquo; St. James says. &ldquo;Finding the ideal partner will be key to success.&rdquo;
 Other Opportunities
 As Brazil and Argentina dominate in South America, several other Latin American nations, such as Peru, Colombia, Costa Rica, El Savador, Guatemala and Paraguay, are making quieter biodiesel progress.
 Craig Frank, CEO of Miami-based Alternative Fuels Americas Inc., believes Costa Rica, Panama and Colombia are all attractive investment hubs to carry out jatropha cultivation for future biodiesel production. AFA has concentrated its work in Costa Rica where it secured 200 hectares to grow jatropha. Frank says he plans to eventually move to a 5,000-hectare plot, adding that AFA is looking at feedstock development at this point because technology already exists to produce biofuels efficiently.
 &ldquo;Of the projects we know of that are set to come into production, I don&rsquo;t believe the capacity will be greater than several hundred thousand gallons annually,&rdquo; Frank says. &ldquo;We will have, upon launch next year, the largest biodiesel project in Costa Rica.&rdquo;
 In addition to jatropha, AFA is studying the development and potential integration of other feedstocks such as coyol (spiny palm) and algae. Last year, AFA partnered with Sustianable Agro Biotech LLC, a Puerto Rican-based company engaged in algae-to-fuel research.
 &ldquo;We believe SABI has developed interesting ideas and has validated many of them in a lab setting,&rdquo; Frank says. &ldquo;We will, during the coming year, further this research and will, at that time, have a better understanding of what we can fairly and accurately project with regard to a timetable.&rdquo;
 While AFA may have not have produced any biodiesel in 2011, it has set ambitious goals for 2012. The company anticipates producing approximately 1.5 million gallons of biodiesel derived from coyol in Costa Rica.
 &ldquo;We believe production will increase annually with the coyol until we reach a maximum of 3 MMgy [in Costa Rica],&rdquo; Frank explains. &ldquo;Once the jatropha matures, we believe we will produce an additional 4 MMgy for a total of 7 MMgy by around 2015.&rdquo;
 AFA plans to expand its jatropha plantation operations into Panama and Colombia. Guatemala, Dominican Republic and Honduras are also possibilities, according to Frank.
 &ldquo;There are some other countries that are also on our radar, but we&rsquo;ll consider those after we complete our plans in these target countries,&rdquo; Frank says. All in all, AFA has developed a program that intends to reach 80 MMgy of combined biodiesel output from all the countries it operates in.
 While AFA&rsquo;s business strategy may seem aggressive, yet achievable in Costa Rica, surrounding Latin American countries have created, or are in the process of creating, biodiesel blend mandates that should foster development of a biodiesel industry.
 Of all the neighboring Latin American countries, Colombia appears to hold the most potential of becoming a viable biodiesel producer and emerging exporter in years to come. While it may not currently import nor export any biofuels, the country&rsquo;s Ministry of Energy has issued several resolutions to make the blend mandatory at levels that can be supplied by new biodiesel plants coming online. As a result, Colombia is expected to reach a B10 blend by the end of 2012. Author: Bryan Sims Associate Editor, Biodiesel Magazine (701) 738-4974 <a href="mailto:bsims@bbiinternational.com">bsims@bbiinternational.com</a>

2011/08/1313519176899.jpg

MOVING PRODUCT: The B5 mandate led to production of 2.4 billion liters (634 million gallons) of biodiesel last year in Brazil.

2011/08/13135194296146.jpg

COMPETITIVE MARKET: While Dedini designed this plant in Brazil, St. James says in Argentina, Lurgi commands 45 percent of the biodiesel design/build market share. 

2011/08/13135194827442.jpg

A recap of regional biodiesel developments and a look ahead

Solid Growth  in Central,  South America

The European biodiesel industry may be the largest in the world, but it seems to be struggling to regain ground lost in recent years. As U.S. biodiesel producers continue to recover from the economic disaster of 2008 and 2009, some segments of the European industry are lagging behind. Public policy and perception issues seem to be holding the industry back and making the future of biodiesel in Europe somewhat unclear.
 When asked to describe the current state of the European biodiesel industry, Dieter Bockey, spokesman of Arbeitsgemeinschaft Qualit&auml;tsmanagement Biodiesel e.V. (AGQM) paints a rather bleak picture. &ldquo;There is still huge over-capacity of biodiesel in the EU,&rdquo; he says. According to Bockey, there is currently 22 tons (6.6 billion gallons) of production capacity in the EU. However, he estimates that the industry as a whole produced only 8.9 million tons of the fuel in 2010.
 According to Pierre-Antoine Vernon, a project manager with the European Biodiesel Board, 2011 biodiesel production levels are currently relatively consistent with last year's. One change, he says, is that some biodiesel production capacity within Europe has begun to be dismantled or retrofitted. While Vernon stresses this is currently not a major trend, he says there has been a slight move in this direction.
 Frank Str&uuml;mpfel , spokesman for German biodiesel producer Verbio Vereinigte BioEnergie AG, also notes that many elements of the European biodiesel industry have remained consistent since last year. Germany is still the largest producer and consumer of biodiesel, he says. In addition, overcapacity and high feedstock prices are continuing to put financial pressure on the companies that are still producing. That said, he stresses further shutdowns of biodiesel plants are not foreseeable at this time.
 Bockey attributes the low level of production to several factors that go beyond price pressure, including the fact that the national obligations and commitments are currently below 7 percent. This is true, he says, even though the European diesel standard (EN 590) already allows for B7 blends of diesel fuel. &ldquo;This existing standard EN 590 corresponds to about 14 million tons of biodiesel,&rdquo; he said.
 Str&uuml;mpfel notes that biodiesel producers in Europe face a significant challenge in that the market is has been defragmented through heterogeneous legislation in different EU member states. Matti Lehmus, Neste Oil&rsquo;s executive vice president of Oil Products and Renewables, agrees. &ldquo;It is evident that the short-term process in implementing the Renewable Energy Directive has [been] delayed somewhat and the process is proceeding at a different pace in various countries,&rdquo; he says. &ldquo;As a result, the legislation within the EU is becoming increasingly fragmented, and the complexity in the biofuel field is growing and slowing down the development in this sector.&rdquo;
 Bockey adds that there has been a lack of strong and consistent support for biodiesel recently in Europe. &ldquo;[Policymakers] make no pressure to increase the share of biodiesel in the fuel market, due to the public discussion concerning food versus fuel, greenhouse gas (GHG) savings, the public pressure concerning rain forests, restrictions [and] and problems concerning the use of biodiesel engines and so on,&rdquo; he says. In fact, Bockey notes that biodiesel seems to be falling out of favor with some in Europe. &ldquo;The pressure against biodiesel is rising,&rdquo; he says. Especially the automotive industry does not like biodiesel&rdquo; due to perceived engine operation problems. According to Bockey, it seems unlikely that a B10 standard will be issued, even though there is a mandate within the European Commission to do so. &ldquo;The general position of the automotive industry is to substitute biodiesel with HVO (hydrotreated vegetable oil).
 Regulations, Imports, Scandal
 Although those in the European biodiesel industry note that there has been fragmentation of policy among the EU member countries, the EC has taken several actions in recent months that affect the entire sector.
 In early May, the Council of the European Union adopted regulations to extend the anti-dumping and countervailing duties that had been established for U.S. imports to biodiesel to include product consigned from Canada. These duties also were extended to apply to biodiesel blends originating from the U.S. that contain 20 percent or less biodiesel by weight. The measures were taken following an investigation that concluded U.S. biodiesel had been flowing through Canada to Europe, effectively circumventing the required duties.
 &ldquo;The anti-circumvention measures adopted by the council represent a decisive move to ensure that the remedial effect of the EU duties on U.S. biodiesel is fully maintained over time,&rdquo; said EBB Secretary General Raffaello Garofalo in a statement following the announcement. &ldquo;Operators should be aware that any future attempt to circumvent the existing duties can be investigated and remedied in the same way, with retroactive financial implications for the companies involved.&rdquo;
 More recently, the EC announced the recognition of seven new voluntary schemes for sustainable biofuels under the RED. The voluntary schemes are mechanisms designed to ensure that biofuels used within the EU deliver tangible greenhouse gas savings when compared to fossil fuels.&nbsp; Vernon explains there are two ways in which biodiesel producers can meet the sustainability requirements implemented by the RED. Producers could choose to either face 27 different frameworks, one of each EU member country, or comply with a voluntary scheme that is effective in meeting sustainability requirements in each EU nation. According to Vernon, there are clear advantages in terms of simplicity that result from complying with a voluntary scheme.
 &ldquo;The voluntary schemes are a set of rules developed by a consortium of producers [or] a wider array of stakeholders to guarantee the biofuel&rsquo;s sustainability according to the RED,&rdquo; Vernon says. &ldquo;Once the scheme is made, it has to be recognized by the European Commission&hellip;The Commission has now published these voluntary schemes. They can now officially be used by biofuels producers to satisfy the biofuels against the Renewable Energy Directive.&rdquo;
 The voluntary schemes are applicable to both biofuel producers within Europe as well as those who intend to export product to the EU. &ldquo;Provided that you follow one of these voluntary schemes and you are in compliance&hellip;no member state has the right to refuse your biofuels,&rdquo; Vernon adds, noting that meeting the requirements of a voluntary scheme is essential for selling biofuel into Europe. Not all the news about biofuels coming out of Europe has been positive, however. In mid-July, reports began coming out of Europe indicating possible scandal in which the EC had leaked previously unreleased studies regarding the indirect land use change (ILUC) impacts of biofuels. While some have speculated that the studies could mean the end for biodiesel in Europe, most in the industry indicate those claims are exaggerated.
 The leaked reports have drawn a very negative portrait of biodiesel, Vernon says. If the ILUC GHG impacts estimated by these studies were calculated into the GHG savings currently attributed to biodiesel, it would not be possible for most forms of biodiesel to achieve the 35 percent GHG savings required under the RED. &ldquo;This is a worrying outcome,&rdquo; Vernon says, adding that the studies&rsquo; ILUC values into the GHG calculations for biofuels would pretty much effectively ban the use of biodiesel within the EU.
 Vernon also states that he does not expect that possibility to become a reality. &ldquo;ILUC modeling still has a very shaky basis,&rdquo; he says. The more likely outcome is that a compromise will be made. Strumpful adds that ILUC is a theoretical pursuit at this time and that attributing those theoretical GHG values to biodiesel could cause massive damage to the European biodiesel industry.
 Lehmus points out that the EC has not yet published any official statements or reports regarding ILUC or how ILUC should be taken into account by the biofuel sector or feedstock producers. &ldquo;Therefore, it makes no sense to speculate on the possible impacts to [the] biofuel industry at this point,&rdquo; he says. &ldquo;ILUC is highly politicized, thus we are not surprised that there are various opinions and reports of various quality regarding the issue with the aim to affect public opinion and decision making. We will wait for the official statements and reports from the Commission and respond accordingly based on the official information.&rdquo;
 According to Bockey, the EC could publish a legal proposal within months regarding possible ILUC amendments to the RED. The fear, he says, is that because the ILUC factor depends on the type of biofuel, the default values will be adjusted in a way that biodiesel production will no longer be able to reach the required GHG reductions after 2017. On the other hand, Bockey says, under the national renewable action plan of 10 percent renewable content in transportation fuel by 2020, there&rsquo;s a concern that the commission will not present a legal proposal regarding biofuels in the way described, so there is still a huge amount of uncertainty regarding what the commission will actually suggest.
 The Future
 According to Str&uuml;mpfel, his company does not expect to see any growth in the German biodiesel industry, due in part to continuing overcapacity, but he says this may not be the case for all of Europe. &ldquo;Europe will see steady [growth] of biodiesel production in order to reach EU [carbon dioxide] reduction goals for the mobility sector, therefore car manufacturers have to increase their flexibility in higher biofuels blends,&rdquo; he says.
 In order to help support the continued development and recovery of Europe&rsquo;s biodiesel industry, Str&uuml;mpfel stresses that the RED has to be implemented consistently across all EU member states. &ldquo;As long as there aren&rsquo;t reliable political decisions or rules for the use and production of biodiesel set in place, we will see no further development of European biodiesel industry,&rdquo; he says.
 Lehmus agrees that the development and local implementation of the RED needs to proceed rapidly in order to support the European biodiesel industry. &ldquo;There are, for example, still various different interpretations of what is considered as &lsquo;waste&rsquo; in different EU countries,&rdquo; he says. &ldquo;From the biofuel industry&rsquo;s perspective, there should be a common interpretation of all these key issues among all EU countries.&rdquo; In addition, Lehmus says it is important for legislation related to biofuels to be technology and feedstock neutral, emphasizing the importance of GHG savings and sustainability rather than supporting specific products over others.
 Some policy makers within Europe are also pushing for greater focus on second-generation biofuels. Csaba Tabajdi, a Hungarian representative in the European Parliament who sits on the Environment Committee, recently spoke about the importance of second-gen biofuels at the ScienceBusiness&nbsp; conference in Brussels.
 Like lawmakers in the U.S., Tabajdi touted the job creation opportunities offered by advanced biofuel production. &ldquo;The bioenergy and biofuel production is a major economic and environment benefit in Hungary and throughout the European Union, while reducing external energy dependence as well,&rdquo; he said in a transcript of his speech posted to his website. &ldquo;We must ensure biofuel [production&rsquo;s] competitiveness and environmental sustainability. We should encourage scientific research,&rdquo; and encourage the development of a predictable regulatory environment that encourages research and investment of community financial resources.&nbsp; Author: Erin Voegele Associate Editor, Biodiesel Magazine (701) 540-6986 <a href="mailto:evoegele@bbiinternational.com">evoegele@bbiinternational.com</a>

The European biodiesel sector faces unique challenges

A Whole New World

For longer than the lives of the students it carried back and forth to rural Medford, N.J., schools, yellow bus No. 74 has run on biodiesel. Joe Biluck, director of operations for the Medford Township board of education, recalls that he first started looking into biodiesel&mdash;soy diesel as many called it then&mdash;in 1995. This was before any state or federal mandates existed, and well before biodiesel had an ASTM fuel specification. But even, in those early days of commercialization, the benefits of biodiesel were clear, especially to Biluck.&nbsp;
 &nbsp;&ldquo;We were in the right place at the right time,&rdquo; Biluck tells Biodiesel Magazine. &ldquo;In 1995-&lsquo;96, when I was investigating this, there weren&rsquo;t a lot of options out there for alternative fuels. So biodiesel seemed like the most appropriate fuel at the time.&rdquo; Twenty-plus years ago, when Biluck says he was still &ldquo;turning wrenches&rdquo; for the school district, he started to hear about federal mandates for the public sector and state fleets. &ldquo;We&rsquo;re a quasigovernment agency,&rdquo; he says, &ldquo;so, I wondered, what options would I have?&rdquo;
 The Medford school buses transport about 3,500 students a day, Biluck says. &ldquo;This biodiesel program was started because of the students.&rdquo; For anyone who&rsquo;s been a passenger on a school bus run on diesel, the distinct smell, laden with carcinogenic particulate matter, or soot, is sure to be one of the most prominent memories. &ldquo;It has been proven that biodiesel improves air quality both outside of the bus and in the interior,&rdquo; Biluck says, &ldquo;and that&rsquo;s the No. 1 reason for starting this program.&rdquo;
 In the early to mid-&lsquo;90s, EPAct encouraged, or mandated, really, state and utility fleets to incorporate alternative fuel vehicles, what Biluck says was referred to then as &ldquo;bi-fueled&rdquo; vehicles, and while Board of Education vehicles weren&rsquo;t specifically required to go that route, he says he thought that those regulations could find their way into the school bus fleet and other vehicles operated by the education board. But the state of New Jersey had requirements on the books that said public vehicles used for the transportation of students were to be run on gasoline or diesel fuel. &ldquo;There were no provisions for fuels like compressed natural gas or anything,&rdquo; he says. &ldquo;So if alternative fuels were wanted, they would have to change the laws to accommodate them.&rdquo;
 Biluck was told by the program manager in the Office of Clean Energy that there were federal monies available for state organizations, funding targeting the demonstration of alternative fuel vehicles. &ldquo;So, I delved into it in &lsquo;95 for that reason,&rdquo; Biluck says.
 When Biluck and others on the board thoroughly reviewed the regulations for the funding of alternatives, they realized that only vehicle acquisition, not fuel, was covered. &ldquo;It&rsquo;s ironic,&rdquo; Biluck says, explaining that the funding supported the purchase of bi-fuel vehicles that could run on either petroleum fuel or, for instance, compressed natural gas (CNG), &ldquo;but there was no infrastructure for CNG so they just ran on gasoline or diesel. But they were in compliance by operating a dual-fuel vehicle even though they almost always ran on petroleum fuel.&rdquo;
 In &rsquo;95, the DOE and the incentive program began accepting applications for not only the bi-fueled vehicles, but also for the alternative fuel itself. Biluck says they resubmitted the application for funding. The result was four years of extensive testing for the DOE. &ldquo;The federal government wanted a well-defined program,&rdquo; Biluck says. &ldquo;They wanted side-by-side test groups,&rdquo; to reduce or, if possible, eliminate variables between the test and control groups. Forty-four buses were used in the testing, half fueled with B20 from Twin River Technologies and the other half with conventional on-road diesel fuel. Not only did the program want to see Hot 505 emissions test results conducted in an EPA-certified laboratory, but Biluck also says the government wanted to see significant road-time, maintenance and repair history to establish a good baseline before the tests, in addition to generating extensive reports annually after the biodiesel testing began.
 Biluck sent a note to the power plant manager for International Harvester, the predominant engine in the fleet, because he was concerned that using biodiesel might void the warranty. In response, he was told by IH that as long as service intervals were maintained, and they didn&rsquo;t use more than 20 percent biodiesel, there shouldn&rsquo;t be a problem. And there wasn&rsquo;t.
 As opposed to buying bi-fuel vehicles, which is a significant capital expense when replacing fleet vehicles, buying alternative fuels such as biodiesel has few or no upfront costs but, instead, requires more operating costs due to the fuel&rsquo;s higher price compared to conventional diesel&mdash;something Biluck says is more effective budgeting for the state.
 A New Mindset Later
 Years of testing, generating report after report, finally came to an end. &ldquo;After four years,&rdquo; Biluck says, &ldquo;the biodiesel units were 2 cents per mile less than the control.&rdquo; This was unheard of. A new fuel that cost much more than conventional diesel fuel, and had no quality standard, could reduce overall fleet operating costs by 2 cents a mile.&nbsp;
 To put the cost savings into perspective, in a decade the Medford school buses travel 4 million miles, a long enough haul to circle the Earth 160 times. At 2 cents a mile savings using B20, this comes to about $80,000 every 10 years, or $8,000 a year. For a rural school district, where every penny counts as year after year rural township populations dwindle in favor of the fast-paced city life, reducing vehicle fleet operating costs is essential for survival.
 While a premium is paid for the biodiesel, Biluck says on the backend it lowers overall fleet costs in several ways: the higher oxygen content of biodiesel reduces the rough idle. &ldquo;It&rsquo;s noticeably reduced,&rdquo; he says, which means the buses idle smoother, reducing wear on everything from radiator bracket mounts to exhaust hangers, to the exhaust system itself, the life cycles of various pieces of equipment are extended by using biodiesel. &ldquo;The particulate matter is reduced, so you get longer lasting mufflers,&rdquo; Biluck says, &ldquo;and you&rsquo;ve got 32-feet of exhaust pipes on a bus. The fuel injectors last longer. So when you aggregate those across the fleet over time, the savings really add up."&nbsp;
 Despite biodiesel being a fairly new fuel without a specification, having known cold flow issues when proper measures aren&rsquo;t taken, Biluck says, &ldquo;I didn&rsquo;t want the bus to stall out and have our kids stuck out in a rural area in the middle of winter, but we took precautions and we didn&rsquo;t have any problems.&rdquo; The school board was so happy with its incorporation of biodiesel, they wanted to promote it. &ldquo;It had a significant impact on the state and region,&rdquo; Biluck says, &ldquo;so we wanted to take full advantage of this and participate in a solution for energy independence.&rdquo;
 Medford is an agricultural community, so there&rsquo;s a direct link between area soybean farmers and the school buses running on soy biodiesel. While insignia on the biodiesel-burning buses would have done the job promoting use of the ag-based fuel, Biluck says the board of education was not allowed to run promotion campaigns on school buses. &ldquo;I would have promoted it,&rdquo; he says, &ldquo;with 44 buses, 44 rolling billboards.&rdquo;
 He tells a story about a bus driver who, shortly after the bus began fueling on biodiesel, kept experiencing stalling. Biluck would test the bus and never had an issue. After six or seven times of the bus stalling on the driver, the natural suspicion was that the reason was the new fuel. &ldquo;So we tore into the engine,&rdquo; Biluck says, &ldquo;and found nothing wrong.&rdquo; It turned out that the driver had a globe on a chain as a key ring, which hung down low enough so when she shifted gears, the globe caught on the shifter and moved the key enough to shut off the ignition. &ldquo;She was condemning the fuel, but it was a trinket on her key ring the whole time,&rdquo; he says. &ldquo;People don&rsquo;t like change, and it takes effort and education to counteract those [misconceptions].&rdquo;
 One day Biluck says he was casually looking through the list of buses required to retire. In New Jersey, C-chassis buses must go into mandatory retirement after 12 years of use. As Biluck was perusing the list, he says, &ldquo;There was No. 74. The bus didn&rsquo;t really have a name, although over the years the kids called it &lsquo;the bean bus.&rsquo; Now those kids are 21, 22 and 23 years old. I hope they remember how progressive this was for the time.&rdquo; After its pioneering use as the nation&rsquo;s first biodiesel-powered school bus, old No. 74 will be either sold at auction or traded in for a new bus. But the impact yellow school bus No. 74 has had is still being felt. &ldquo;Several hundred municipalities in the area have begun to incorporate biodiesel into their systems,&rdquo; Biluck says, &ldquo;I mean snow removal, buses, you name it, with no down time, no significant damage.&rdquo;&nbsp;
 &ldquo;This is a great biodiesel success story,&rdquo; says Chuck Myers, a soybean farmer and vice chair of the United Soybean Board. &ldquo;The Medford Public School District in New Jersey is a great example of how incorporating biodiesel into fuel programs can result in great benefits for everyone involved. Biodiesel is a fuel every American can get behind.&rdquo;
 The Medford board of education&rsquo;s biodiesel experience was &ldquo;sort of a springboard, if you will,&rdquo; Biluck says. "It created a whole new experience and really taught us about the benefits of sustainable technology and renewable energies&mdash;to improve the bottom line, improve the environment and reduce energy dependence. Biodiesel opened our eyes to that.&rdquo;
 The board of education has a $22 million solar project (3 megawatts) underway that&rsquo;s been funded entirely by private investors, which will help realize a $7.2 million savings over 15 years for the tax payer. &ldquo;This reduces money for utilities, money that&rsquo;s realigned back into the classroom for instruction,&rdquo; he says. &ldquo;There&rsquo;s government assistance to help get over those higher upfront costs, and the long-term benefits are really cost reductions. There&rsquo;s significant opportunity for all types of renewable energy here now, and it all started with biodiesel.&rdquo; Author: Ron Kotrba Editor, Biodiesel Magazine (701) 738-4942 <a href="mailto:rkotrba@bbiinternational.com">rkotrba@bbiinternational.com</a>

The nation's first biodiesel-powered school bus has made its last run

Retiring  Ol' No. 74:  The 'Bean Bus'

The largest U.S. biodiesel company, Renewable Energy Group, filed for its IPO to go public in July. REG holds five wholly owned biodiesel production facilities and one leased plant, with a total production capacity of 212 million gallons.
 What does it mean for the industry when the nation&rsquo;s largest biodiesel producer goes public? And what does it say about REG&rsquo;s financial status right now? I asked these questions on my F.A.M.E. Forum blog, shortly after the announcement, along with this perspective.
&nbsp; In a broad sense, one school of thought is that stock exchanges, and the public&rsquo;s ability to buy and sell company shares, is the democratization of capital. Those who oppose this viewpoint insist this is only an illusion, since often only a minority of any public company&rsquo;s stock is offered for common purchase, with the majority retained by the few corporate elite. In its SEC filing, REG states, &ldquo;We have led the consolidation of the U.S. biodiesel industry.&rdquo; Consolidation is generally considered to be incongruent with democratization. The biodiesel industry is rife with localized, small, private production facilities, and larger private companies, which is a fairly good representation of what a diverse, decentralized fuel industry should be. Some would say that is democratic.
 Peter Brown, the September issue&rsquo;s Talking Point columnist, had this to say in response to my blog: &ldquo;They still have shares to put out there to be bought by the great unwashed in a market that the unwashed does not yet understand. Risky? Probably far more than anyone realizes. A gamble?
Probably not because the company now has solid assets to back its worth. Whoever buys its shares will be buying contracts, the start of an acceptable business and contacts around the world. So yes, it is a democratization process and in a very real sense an educational process for the above mentioned unwashed. As far as the regional biodiesel facility sucking off waste oil from the local McDonalds is concerned, that image is over. What we have are feedstock contracts negotiated in India and Ghana for jatropha oils that will be converted to biodiesel to allow KLM to fly to Dusseldorf. That is the real world of REG at this point in time, and that will become the reality of the biodiesel business.&rdquo;

2011/08/13134396303514.jpg

Going Public

In June, the U.S. faced new pressure from the Group of 20 nations to end government aid for the biofuels industry at a meeting of farm/agriculture ministers in Paris. The issue for the U.S. trading partners is that the U.S. is alone in actively using trade policy to promote its own industry. At the G20 summit, the discussion included the elimination of government subsidies to promote the use of biofuels. Many of the member nations present at the G20 believe that such reduction in subsidies would reduce the volatility in global food prices. The current biodiesel tax incentive expires on Dec. 31.&nbsp;
 At the same time as the G20 summit was taking place, biodiesel tax credit extension bills were introduced in both the U.S. House of Representatives and the U.S. Senate. The House bill, H.R. 2238, was introduced by Reps. Aaron Schock, R-Ill., and Collin Peterson, D-Minn. The proposed House legislation extends the $1 per gallon biodiesel tax credit to 2014 and changes the tax incentive to a production excise tax credit. The Senate version, S. 1277, was introduced by Sen. Chuck Grassley, R-Iowa, and would extend and modify the existing tax incentives for domestic biodiesel production.
The Senate bill would convert the tax incentive from a blender credit to a production tax credit. If signed into law, the Senate bill would extend the new incentive for five years. The biodiesel tax credit would be increased to $1.10 per gallon for the first 15 million gallons of biodiesel produced by small producers. Additionally, the legislation would require that production of B100 or B99 become a taxable fuel, which would require the producer to collect the 24.4 cents per gallon tax from a marketer when sold outside of a registered terminal. The legislation would still allow blenders to own the renewable identification numbers (RINs), but the blenders would not be eligible to collect the $1 tax credit. The shift from a blenders tax credit to a production tax credit is designed to improve efficiency in the administration of the tax credit and reduce opportunities for fraud and abuse.&nbsp;
&nbsp;&nbsp; The extension of the tax incentives for biodiesel production is extremely important to the industry&rsquo;s access to capital and other methods of progress. Many groups in the biofuels industry have argued that a multiyear extension is needed to provide stability and certainty to the still maturing biodiesel industry. However, as previously mentioned, the current $1 blenders tax credit expires at the end of 2011.&nbsp; Given the federal deficit discussions currently taking place, Congress may not have the desire to renew the biodiesel tax credit.&nbsp;
 Since the introduction of the biodiesel tax credit in 2004, it has helped support the production and use of biodiesel. Biodiesel production in the U.S. increased from 25 million gallons in 2004 to 690 million gallons in 2009, before Congress allowed the tax credit to lapse at the end of 2009, which resulted in the loss of jobs in the biofuels industry throughout 2010 as facilities were shuttered. However, there are many people in the biodiesel industry who believe that elimination of the tax credit would not result in the destruction of the biodiesel industry but instead would strengthen the RIN market. The thought process regarding the RIN market is that gallons earning a tax credit are able to remain in production at a lower RIN value than would be possible without the tax credit. If the tax credit is eliminated, then the thought is that the RIN value will rise approximately the same amount. There is evidence to support the concept that while the biodiesel industry struggled during the lapse of the tax credit, the RIN value traded at high enough prices to fill the void left by the elimination of the tax credit. The strength of the RIN market relies upon the continued RFS mandates. Author: Angela J. Cyr Attorney, BrownWinick (515) 242-2418 cyr@brownwinick.com

2011/08/13134401474644.jpg

The Next Big Cut: Does It Make Cents?  

The argument that the world is facing a food shortage, and that biofuels are contributing to that shortage, is bogus. There is enough food in the world to give every man, woman and child 4.3 pounds of food a day.
 A study undertaken by the Stockholm International Water Institute highlights the absolutely staggering amounts of food that are wasted every day. In the U.S. alone, it is estimated that 30 to 40 percent of our food crops never reach the table.
 The price of food is going up, and in some cases quite dramatically. It is also very clear that other staples have risen just as dramatically, none more so than petroleum products. Another study done by the World Bank in July 2010 places the blame for the increase of food prices on commodity traders who&nbsp; use food as just another commodity to be manipulated for profit and excludes any thought of food being just food.
 Wars are being fought for petroleum, not for food, because starving nations do not have the clout to get fed, they only have the right to die off while often sitting on simple solutions to their energy problems. It is fascinating to read which countries are the hungriest and least able to feed their own people. The worst off are clustered in a combination of climactic disaster, low irrigation, political insanity and religious sectarianism. What is never brought up is that those same areas are energy poor. They lack local supplies of the most basic energy sources. They have no roads, no power and no water to face their overwhelming poverty. Interestingly enough, most of them have access to some form of bioenergy; more often than not palm oil and possibly jatropha. In some of those countries, diesel sells for $4 a gallon and a small place like Liberia could be energy independent if it harvested its palm plantations.
 The basic premise that the world is gasping for food is only true insofar that there are pockets or areas, in the developing nations, that are unable to produce enough food locally to survive. A really simplistic example would include the farmer in Sierra Leone who raises tomatoes and cannot afford to move his 20 pounds a week to the local market because of the high cost of transportation (diesel fuel). The multinational food companies that fill the shelves in remote areas of the world can afford those prices because they transport in bulk over vast distances in sophisticated refrigeration units. Their fuel per pound is minimal compared to the local farmer, although you will not see them rushing into Somalia any time soon.
 We are dealing with a complex and very delicate equation that can only be solved by making assumptions on the X, Y and Z axis. X is the high cost of transportation due to the increased fuel prices; this unknown variable shifts on a daily basis for many reasons and is entirely unpredictable except that it trends up. Y is the untold damage we are doing to our planet because of X, which actively modifies Y, and is in turn modified by a horde of other factors some call the SUV (sport utility vehicle) syndrome. Then there is the Z factor, the zany factor that dictates against both reason and logic under the guise of political, ecological and ethical stances that some food staples may not be fuel, and certain forms of energy are &ldquo;unacceptable&rdquo; or unethical.
 The role of the multinational food corporations is almost as troubling as the role being played out by the large petroleum companies. They abhor biofuels because the transition from food to fuel is immediate. There are fewer intermediaries between the corn farmer and the gas tank than between the farmer and the Doritos chip. So no wonder the food companies have an altruistic attitude.
 On the other hand, changing one element of the equation changes the whole aspect of the solution. The most obvious element has to be the ability to generate energy in one way or another. Often overlooked is the fact that petroleum products have become increasingly expensive, distribution is erratic and supplies are controlled by outside sources that may not have anyone&rsquo;s best interest at heart. Making biodiesel from available feedstock to operate generators, trucks and other trappings of civilization can only be a good thing in areas where civilization comes at the point of a gun. Being part of a movement that will allow the world to maintain its standard of energy and replace those energy sources with renewables is certainly a step in the right direction. Author: Peter Brown Co-founder, International Procurement Tools Inc. (408) 426-5585 peter@euromarketingtools.com

2011/08/1313440404031.jpg

Food, Fuel or Fools

In the algae industry, biofuels and coproducts such as animal feed are equally responsible for profitability. Tryg Lundquist, assistant professor, wastewater expert and algae researcher at Cal Poly State University, San Luis Obispo, agrees. He is leading a team of researchers on a project funded by the California Energy Commission that will focus on algae, wastewater treatment and, biofuels, but not coproducts per se. With $692,000 in funding from the state and private partners, he will instead work to generate additional revenue through a coservice.
 His project on recycling nutrients, energy and water, trademarked RNEW, will attempt to &ldquo;completely wring all the value out of wastewater,&rdquo; Lundquist says, using an open-pond algae-based system. The mention of wastewater treatment and algae in the same sentence is certainly not new, Lundquist says, as wastewater and algae research and use has been happening since the 1950s. But, he says&nbsp; the possibilities for new methods of treatment involving algae&mdash;and more importantly, the state of the wastewater infrastructure across the U.S., from his perspective&mdash;and the RNEW project seems deserving and worthy of any new attention.
 &ldquo;Wastewater treatment is not inexpensive and there is a lot of demand for it,&rdquo; he says. It is something people will pay for, and is &ldquo;something they are required by law to do.&rdquo; The main infrastructure currently operating in the U.S. was established in the 1970s and '80s he says, most of which was based on federal, grants that today are not as readily available as they once were. And low-interest loans offered by most communities to build new facilities are also being cut. &ldquo;There is going to be less money available for these communities to build their wastewater plants.&rdquo;
 Not only has the money for new construction become scarce, but many of the facilities built 30 years ago are rapidly reaching the end. As Lundquist explains, there are three basic types of wastewater facilities: electromechanical plants, pond-based oxidation systems and the most popular, activated sludge. The electromechanical system typically requires a high volume of concrete, steel and electric motors. In some setups the wastewater is trickled over a substrate that requires energy to move up over the substrates (rocks). These systems are vulnerable to concrete and rebar erosion and will typically only last 20 to 30 years.
 The oxidation systems typically used in small communities are based on a deep earthen basin system and can last up to 50 years, but, Lundquist says, &ldquo;They were only good for what we call secondary treatment,&rdquo; or the removal of organic solids. Over time, sludge accumulates and they need to be upgraded. And then there is the activated sludge system that uses blower motors to send bubbles into the water, essentially creating bacteria to purify the wastewater, which also is vulnerable to concrete breaks and steel erosion.
 The RNEW system will be an open-pond, multi-culture algae system. Lundquist says his team will have access to 5-acre testing ponds, and it will try a new zooplankton control method. If they achieve their true goals, they will meet the lipid productivity levels achieved in conditions suited for biofuels productions.
&mdash;Luke Geiver

ENOUGH GRIST: The Cal Poly feed mill has been used to develop and test algae-enriched feeds for broilers and livestock.

2011/08/1313515895922.jpg

California researchers aim to recycle nutrients, energy and water with algae

Forget Algae Coproducts, Think Algae Coservice

Facetiously, Matt Roberts envisions the day when the U.S. Army might change its current slogan from &ldquo;An Army of One&rdquo; to &ldquo;Be All That You Can Be, And Be Green Doing It.&rdquo; Roberts, vice president of marketing for Springboard Biodiesel LLC, has reason to boast since his California-based firm sold a 50-gallon BioPro 190 biodiesel processing unit to the Florida Army National Guard&rsquo;s Camp Blanding Joint Training Center near Starke, Fla., in January 2010.&nbsp;
 &ldquo;The military is just a huge target market for us and we would love to have a BioPro on every military base on the globe,&rdquo; Roberts tells Biodiesel Magazine. Springboard Biodiesel is responsible for more than 6 million gallons of annual installed capacity spread across 14 countries, Roberts says.
 The feeling is mutual, according to Jessika Blersch, sustainability coordinator for Camp Blanding Joint Training Center. Using Springboard&rsquo;s processor, she says, has allowed Camp Blanding to achieve what its biofuel program was originally set out to accomplish when it first launched in January 2010: offset fuel costs with a cleaner-burning fuel by decreasing dependence on fossil-based diesel and increase energy security. Both objectives fall in line with federal and state orders. The program is just now coming out of its pilot project stage.
 The camp collects used cooking oil for free from the camp&rsquo;s large drums at the Consolidated Dining Facility. It's transported to a maintenance facility where it&rsquo;s converted into B100 so that the base&rsquo;s maintenance vehicles, such as mowers and tractors, can pull up to a maintenance facility to fill their tanks on B20. But the amount of fuel that&nbsp; can be produced ultimately depends on the number of vehicles on the installation that can use the biofuel.
 &ldquo;I&rsquo;ve noticed from the consumption that a lot of them are beginning to incorporate more biodiesel as they fill up their tanks,&rdquo; Blersch says, adding that Camp Blanding has produced an estimated 1,100 gallons since the program bought Springboard&rsquo;s processor last year for the program, at a cost of only 67 cents per gallon, roughly. &ldquo;It&rsquo;s becoming more of a trusted product,&rdquo; she says.
 In addition to the camp&rsquo;s maintenance fleet, a school on the camp designated two school buses to run on B20. Also, forestry personnel use biodiesel during burn mixes when conducting prescribed burns on camp. While biodiesel may be produced and offered exclusively at Camp Blanding, plans are to offer biodiesel to additional users outside the gate who may want to reduce fuel costs and use a cleaner burning fuel, Blersch adds.
 As for Roberts, he&rsquo;s proud to see America&rsquo;s finest take the lead by implementing biodiesel initiatives like Camp Blanding. And he&rsquo;s optimistic more will follow its example. &ldquo;We&rsquo;ve been trying to get the attention of the military to use our equipment for some time now and we&rsquo;ve found it to be a challenge,&rdquo; Roberts says, &ldquo;but we are very pleased that Camp Blanding has taken the initiative to start doing this.&rdquo;
&mdash;Bryan Sims

MIX IT UP: Jessika Blersch, sustainability coordinator for the Florida National Guard's Camp Blanding Joint Training Center, measures sodium hydroxide while processing vegetable oil from the installation's Consolidated Dining Facility into biodiesel.

2011/08/13135160113818.jpg

How one military installation closes the loop on energy security by producing, using biodiesel 

The Army is (Still) Going Green

Acetals can play a critical role in the performance and quality of biodiesel. They function as additives and can enhance the cetane for higher ignitability. They also improve oxidation stability and decrease nitrogen oxide emissions. Ion Agirre, a doctor of chemical engineering at the University of the Basque Country, has discovered a novel route for producing a different type of acetal, 1,1 diethoxy butane, from renewable sources such as plant-derived sugars.
 According to a thesis Agirre defended, titled, &ldquo;Innovative reaction systems for acetal (1.1 diethoxy butane) production from renewable sources,&rdquo; he successfully produced 1,1 diethoxy butane using reactive distillations and dehydration membranes between ethanol and butanol. The main advantage of this type of acetal, according to Agirre, is that it is derived from biobased sources where the ethanol can be obtained from fermentation of sugar-rich plants and the butanol from the dehydrogenation or the partial oxidation of its corresponding alcohol. In his research, he notes that 1,1 diethoxy butane complies with the majority of specifications required for adhering to diesel, unlike other commonly used acetals, such as 1,1 diethoxy ethane.
 Agirre concluded that the most efficient and economical option for obtaining 1,1 diethoxy butane could be the combination of dehydration membranes and conventional distillation. Agirre&rsquo;s work on acetal process optimization can also be found in the Journal of Membrane Science.
&mdash;Bryan Sims

A unique acetal could open up new options for biodiesel

Optimizing Research

Typically, biodiesel is produced via a transesterification reaction in a homogenous phase, meaning the raw materials, such as soybean oil and methanol and a catalyst are in the same liquid phase. But this route can be cost-prohibitive for producers as conventional catalysts used today, such as sodium or potassium methoxide, cannot be reused or regenerated since the catalyst is consumed in reaction. Researchers at the Autonomous Meritorious University of Puebla in Mexico believe they&rsquo;ve discovered an alternative to this conventional route, however, by employing hydrated lime, or calcium hydroxide, in a heterogeneous process that enables easier separation, higher activity, selectivity and longer catalyst life.
 According to Manuel Sanchez-Cantu, lead researcher on the project at the school&rsquo;s chemical engineering department, he and his team purchased 24-kilogram sacks of hydrated lime from a seller in Perote, Mexico, and soybean oil that they bought from a local grocery store. They then added methanol and lime to the used soybean oil. After two hours at reaction temperatures of around 60 degrees Celsius, the process yielded conversion rates that approached 100 percent. Sanchez-Cantu notes that the hydrated lime was reused twice with full conversion of the used soybean oil and methanol to produce biodiesel and the catalyst was not consumed or dissolved in the reaction, which allowed for separation from the products via centrifugation.
 &ldquo;The advantage that hydrated lime has over other catalysts is that hydrated lime represents an inexpensive option compared to other catalysts for obtaining biodiesel since it&rsquo;s produced in large amounts and it&rsquo;s readily available,&rdquo; Sanchez-Cantu says, adding that hydrated lime is also commonly used for industrial applications such as food preparation (to make tortillas in Mexico), water treatment and petroleum refining. Previous studies have indicated that a different type of lime, calcium oxide, has also shown to efficiently catalyze the transesterification process.
 That hydrated lime could also potentially be used for a long period allowing the generation of technology adjusted for continuous processing, which would improve the economics of biodiesel production, Sanchez-Cantu says, adding, "though a lot of work and research should be done."
 Sanchez-Cantu says castor oil will also be examined using hydrated lime as a catalyst, but more work is being carried out to optimize the process with soybean oil. &ldquo;We&rsquo;re performing tests on the catalyst&rsquo;s stability and investigating ways to increase it,&rdquo; he says. &ldquo;Also, research is underway on the shaping process of the catalyst employing distinct binders in order to carry out continuous production of biodiesel.&rdquo;
&mdash;Bryan Sims

Heterogeneous catalyst could offer new recipe for biodiesel production

September 2011

Business Briefs

Business Briefs

Business Briefs

Business Briefs

Columns

The Quest to Make Cofiring as Seamless as Possible

Looking at the Bigger Energy Subsidy Picture

Progress on the Biomass Thermal Front

Biomass '11 Delivers a Stunning Update

Managing Risks in Cofiring Contracts

Taking It to the Hill

Understanding Indemnities

Cellulosic Fuel Production: One Step Closer to Standard Refining

MEMORABLE GATHERING

Going Public

The Next Big Cut: Does It Make Cents?

Food, Fuel or Fools

Featured

Paper Pellets

Glorified, Torrefied & Cofired

Biomass and Coal: A Powerful Combination

Conquering Co-Combustion

An Anaerobic Alternative

Transforming Financial Reform

Gateway to Cooperation and Parity

Developing India

Solid Growth in Central, South America

A Whole New World

Retiring Ol' No. 74: The 'Bean Bus'

Contributions

Biomass: The Ontario Opportunity

Calculating the Renewable Fraction of Energy from Waste

Establishing Business Operations in Japan

September 2011.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

Business Briefs

Business Briefs

Columns

The Quest to Make Cofiring as Seamless as Possible

Looking at the Bigger Energy Subsidy Picture

Progress on the Biomass Thermal Front

Biomass '11 Delivers a Stunning Update

Managing Risks in Cofiring Contracts

Taking It to the Hill

Understanding Indemnities

Cellulosic Fuel Production: One Step Closer to Standard Refining

MEMORABLE GATHERING

Going Public

The Next Big Cut: Does It Make Cents?

Food, Fuel or Fools

Featured

Paper Pellets

Glorified, Torrefied & Cofired

Biomass and Coal: A Powerful Combination

Conquering Co-Combustion

An Anaerobic Alternative

Transforming Financial Reform

Gateway to Cooperation and Parity

Developing India

Solid Growth in Central, South America

A Whole New World

Retiring Ol' No. 74: The 'Bean Bus'

Contributions

Biomass: The Ontario Opportunity

Calculating the Renewable Fraction of Energy from Waste

Establishing Business Operations in Japan

September 2011