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May 2011

Biomass 101 Is District Energy Right for Your College Campus? Page 48

Plus: What Was the Impetus Behind France’s Mega CHP Plant? Page 34

Energy Independence is Within Reach in Montpelier,Vt. Page 40

Why More Sawmills are Turning to CHP Page 54

How Ethanol Plants are Reducing Their Carbon Footprints Page 60

MAY 2011 | VOLUME 5 | ISSUE 5


FEATURES 34 INTERNATIONAL Big Biomass The commissioning of the largest biomass combined-heat-and-power plant colocated with a paper mill in France could lead to other similar projects and help that country meet its renewable goals. By Lisa Gibson

40 PROJECT DEVELOPMENT Energy Center A hefty grant has propelled a Vermont community’s plan to expand and upgrade its district heating system to run totally on biomass. By Lisa Gibson

48 INNOVATION District Energy on Campus

54 DEPARTMENTS 04 EDITOR’S NOTE Prepping for World Dominance or at Least Healthy Growth By Rona Johnson

District energy systems definitely make economic sense for most college campuses but the physical set-up at every institution is different, making capital funding unattainable for some. By Anna Austin

54 COGENERATION CHP: Cutting It at Sawmills Combined-heat-and-power systems have helped some sawmills through the largest housing slump the U.S. has ever experienced, prompting others to take a closer look. By Anna Austin

60 EFFICIENCY Ethanol Producers Embrace Biomass Power and Thermal Several U.S. ethanol plants are switching from natural gas to biomass to avoid price spikes and reduce their carbon footprint. By Holly Jessen

06 INDUSTRY EVENTS 08 POWER PLATFORM EPA and Open-Loop Biomass: A Mixed Bag, with Cause for Cautious Optimism By Bob Cleaves

10 THERMAL DYNAMICS EPA, Biomass Boiler Industry Proposed Emissions Rules Aren’t Flying at the State Level By Scott Nichols

12 ENERGY REVIEW Standardized Analytical Methods for Biomass Fuel Characterization By Carolyn Nyberg

14 LEGAL PERSPECTIVE What’s My Strategy? By John Dolan and Matt Graham


CONTRIBUTIONS 70 SAFETY Safety Solutions Tailored to Biogas Plants Biogas plant managers may want to consider consulting experts to inspect and assess their operations to make sure their facilities are running safely and efficiently. By Johannes Steiglechner and Volker Schulz

72 INITIATIVE Missouri’s Cogeneration Powers Biomass Production Missouri has made major contributions to the movement toward cogeneration in the past five years, creating hundreds of jobs and opportunities for the region’s agricultural community. By Christopher Chung

74 POLICY Renewable Energy Certificates and Renewable Portfolio Standards Bioenergy producers need to keep up with the ever-changing myriad of policies and incentives that affect the industry on the national and state level. By Jonathan Dettmann, Andrew Ritten and Angela Snavely



Prepping Biomass for World Dominance or at Least Healthy Growth


I hope you are in St. Louis and reading this issue between panel sessions at the 2011 International Biomass Conference & Expo. As I prepare to leave for my trip to St. Louis, I can’t help thinking about all of the events that have happened in the past couple of years that should and have been prompting the world to take a closer look at biomass-based power, heat, fuel and chemicals. In my biomassriddled mind, we should be preparing to take over the world, but I realize that will take time and we should be satisfied that the industry is growing at a healthy pace. The two biggest events were, of course, the oil spill in the Gulf of Mexico and problems with the nuclear reactors in Japan, which according to recent news articles has nearly reached the threshold of the Chernobyl nuclear disaster. Those events coupled with the ridiculously high spikes in oil prices and unrest in the Middle East that could involve even more of our brave men and women in uniform, make me proud to be in an industry that is determined to make us more energy independent. But in our haste to cofire power plants with biomass and replace heating oil with biomass-based thermal energy and gasoline with cellulosic ethanol among many other things, we need to make sure that we operate in a safe and sustainable environment because the world is watching. Many biomass project developers have felt the sting of public resistance, which is usually based on misinformation and often fueled by irrational fears, and have had their plans delayed or even derailed. Although there is no one-size-fits-all solution to this problem, it would behoove us all to make sure we are sending out the right messages about our industry and showing people that biomass is truly a clean and renewable resource. We in the media also have a responsibility to make sure that the general public is as informed as possible. Although we won’t “green wash” companies in our stories, we will make an effort, where it’s applicable, to point out the environmental, economic and social benefits of using biomass over fossil fuels. It used to be difficult for trade journals to impact the opinions of those outside the industry, because we were preaching to the choir, so to speak. But now with social media, our news articles, columns and blogs are captured by a more diverse audience, making our jobs even more important. Enjoy the conference and if you happen to see me stop and say hello.

For more news, information and perspective, visit

Associate Editors


In her feature “CHP: Cutting It at Sawmills,” Associate Editor Anna Austin explores what it takes for sawmills to add combinedheat-and-power systems and the benefits they can reap. In “District Energy on Campus,” Austin discusses how two college campuses installed district energy systems and how that has impacted their bottom lines.



Associate Editor Lisa Gibson talked to biomass developers in the city of Montpelier, Vt., who received a hefty grant, enabling them to finally upgrade and expand their district energy system in her “Energy Center” feature. Gibson also wrote about the largest combined-heatand-power plant in France and how that could lead to similar projects.


ART ART DIRECTOR Jaci Satterlund GRAPHIC DESIGNER Elizabeth Burslie


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¦INDUSTRY EVENTS International Fuel Ethanol Workshop & Expo June 27-30, 2011 Indiana Convention Center Indianapolis, Indiana The FEW is the largest, longest-running ethanol conference in the world. Focused on production of grain and cellulosic ethanol, operational efficiencies, plant management, energy use and near-term research and development, the FEW will attract 2,500 attendees. (866) 746-8385

Pittsburgh to host Northeast Biomass Conference & Trade Show BBI International’s 2011 Northeast Biomass Conference & Trade Show will be held October 11-13 at the Westin Place Hotel in Pittsburgh. The U.S. Northeast with its heavy dependence on heating oil has been a leader in promoting biomass thermal energy. In fact, the Northeast Biomass Thermal Working Group, a coalition of biomass thermal advocates, developed Heating the Northeast with Renewable Biomass: A Bold Vision for 2025 calling for the six New England states and New York to meet 25 percent of their thermal energy requirements with renewable energy resources by 2025. The vision calls for an increase in the Northeast’s use of biomass for heating from 4.16 percent in 2010 to 18.5 percent in 2025, and a reduction in the use of heating oil from 29.23 percent in 2010 to 19 percent in 2025. Biomass thermal energy promises to be a hot topic at this year’s event along with other opportunities in biomass-based power, fuels and chemicals. The Northeast is also home to several biomass power plants that use byproducts from the region’s wood products industry, agricultural residues and forest residues that would typically be landfilled, openly burned or left in the forest to decay or as fuel for forest fires. Plenary sessions at last year’s conference tackled some tough issues including the sustainability of woody biomass and a controversial study released by the Manomet Center for Conservation Studies that questioned the carbon neutrality of woody biomass. The Northeast, as well as other areas of the country and world, continues to grapple with this issue and it is sure to come up at this year’s event. Although the conference is still five months away, it’s never too early to start preparing. Presentation abstracts are now being accepted through June 24 and may be submitted in one of four categories (tracks) including: • Electricity Generation (dedicated power) • Industrial Heat and Power (CHP, thermal energy) • Biorefining (advanced biofuels, chemicals) • Project Development and Finance BBI International is also looking for industry tour stops. If you would like to nominate your company as a tour destination, please contact Tim Portz, BBI International’s program director at The Northeast Conference & Trade Show is an offshoot of Biomass Power & Thermal and Biorefining Magazine’s International Biomass Conference & Expo. For more information or to register, go to



International Biorefining Conference & Trade Show September 14-16, 2011 Hilton Americas – Houston Houston, Texas The International Biorefining Conference & Trade Show brings together agricultural, forestry, waste and petrochemical professionals to explore the value-added opportunities awaiting them and their organizations within the quickly maturing biorefining industry. Speaker abstracts are now being accepted online. (866) 746-8385

Northeast Biomass Conference & Trade Show October 11-13, 2011 Westin Place Hotel Pittsburgh, Pennsylvania With an exclusive focus on biomass utilization in the Northeast—from Maryland to Maine—the Northeast Biomass Conference & Trade Show will connect current and future producers of biomass-derived electricity, industrial heat and power, and advanced biofuels, with waste generators, aggregators, growers, municipal leaders, utilities, technology providers, equipment manufacturers, investors and policymakers. Speaker abstracts are now being accepted online. (866) 746-8385

Algae Biomass Summit October 25-27, 2011 Hyatt Regency Minneapolis Minneapolis, Minnesota Organized by the Algal Biomass Organization and coproduced by BBI International, this event brings current and future producers of biobased products and energy together with algae crop growers, municipal leaders, technology providers, equipment manufacturers, project developers, investors and policy makers. It’s a true one-stop shop—the world’s premier educational and networking junction for all algae industries. (866) 746-8385

Way Beyond Don’t just let the chips fall where they may. Bring us on board for your next biomass project. All fuels. All technologies. All industries. All services. Together we will find your solution. Learn more at Visit us at booth #425 at the International Biomass Conference & Expo.


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EPA and Open-Loop Biomass: A Mixed Bag, with Cause for Cautious Optimism BY BOB CLEAVES

The good news is that the U.S. EPA is finally inching toward officially recognizing open-loop biomass (residues, byproducts and slash) as the reliable clean energy workhorse that we are. The not-so-good news is that we still have a long way to go until biomass receives incentives anywhere near those enjoyed by other renewable energy sources. In December, the agency issued guidance on the Greenhouse Gas Tailoring Rule and hinted that it would treat open-loop biomass favorably. Although the proposed rule defers a final decision for three years while the EPA studies the science of biomass carbon emissions, the agency is recommending that states recognize biomass, in the meantime, as a Best Available Control Technology. The fact that the EPA would encourage states to treat biomass in a similar fashion to other renewable energy sources before the results of its study are available—before, in fact, the study had even begun—indicates that EPA is starting to get the degree to which the nation relies on biomass as a reliable, job-providing, clean energy source. Three years, however, is a long time to wait for a final decision, particularly when we are experiencing plant closures at a fairly frequent rate, and when there is already abundant scientific evidence that open-loop biomass emits far fewer harmful gases than fossil fuels. In early April, I delivered testimony to the agency advocating for an expedited deferral period for open-loop biomass. In my remarks, I emphasized that the science behind the carbon profile of open-loop biomass is already available. With that in mind, why prolong the final decision when the EPA has already endorsed biomass in the form of recommending it as a Best Available Control Technology?


As we face a tough couple of years ahead with low electricity prices and stiff competition from natural gas, the biomass industry simply does not have three years to spare for an EPA study. The EPA also appears to have good intentions, but has not yet met the mark, when it comes to its Boiler Maximum Achievable Control Technology rule. While the proposed rule does give traditional biomass a break with regard to its boiler emissions standards, the rule places harsh regulations on several types of biomass materials commonly used by facilities across the country, and places a chilling effect on new projects. If the rule advances as proposed, it will present a challenge to both existing and new facilities. Luckily, there will be an opportunity for the biomass industry to provide commentary on the potential unintended effects of this ruling. Given the EPA’s recent positive acknowledgements of biomass, I am hopeful that the agency will reconsider its current position. In my opinion, the EPA’s actions in recent months add up to a net positive. While we still have a long way to go in achieving recognition and regulation on par with other renewable energy sources, it is encouraging to see that the EPA is making incremental steps toward regulations that will benefit the biomass industry in the long term. And the Biomass Power Association is doing everything in its power to keep the momentum going in the short term. Author: Bob Cleaves President and CEO, Biomass Power Association








EPA, Biomass Boiler Industry Proposed Emissions Rules Aren’t Flying at the State Level BY SCOTT NICHOLS

In 2007, responding to a need to reduce emissions from Outdoor Hydronic Heaters, then known as outdoor water stoves, EPA began a Voluntary Hydronic Heater Emission Testing Program. The EPA, states, industry and other parties came together to solve a burgeoning smoke problem. The program began with Phase I, which would certify units at a 70 percent cleaner emission level on average than industry had been providing before federal and state involvement. Phase II certified units would be approximately 90 percent cleaner than the average prevoluntary program products. Today EPA is transitioning from a voluntary hydronic heater testing program to a mandatory program. This program will include all indoor and outdoor biomass boilers. The process has been slow moving. Recently the EPA program stumbled. In early 2011, EPA abruptly removed from its Burn Wise website all efficiency numbers for Phase II approved hydronic heaters. With efficiency numbers for log wood hydronic heaters reported in the dubiously high, upper 90 percent range, regulators and others became suspicious of test accuracy. While there is speculation as to why the EPA-approved efficiency numbers were so high, a single smoking gun has not been found. Partially as a result of EPA testing problems, on March 15, Oregon declared a moratorium, among other enforcement actions, on all new installations of hydronic heaters and several other wood-burning appliances (see and search Heat Smart). All parties to the matter now find themselves in a scramble to not only find where the EPA test went wrong, but to also create an updated suite of tests that are relevant to a broader range of biomass boiler technology. The EPA has targeted June for publication of a draft Residential New Source Performance Standard for wood-burning appliances. As this target looms, Oregon’s action sends a clear signal to both EPA and industry that not only must they move quickly, but also move accurately. Behind the scenes EPA and industry, including members of the Biomass Thermal Energy Council are working feverishly through the ASTM process and other means to create test methods with an efficacy that 10 BIOMASS POWER & THERMAL | MAY 2011

all parties can agree to. Test methods are being debated and written, but there is little time or money to perform trial testing. What is clear is that even if methods are completed on paper, there will be little proof that new test methods are compatible and accurate with all appliances. It is uncertain whether test results that satisfy the likes of Oregon are possible in the foreseeable future. Industry, states and the EPA have dug a deep hole on the hydronic heater emission issue. Industry has dragged its feet. Manufacturers of outdoor water stoves have moved slowly to cleaner units. One result is that smoke-belching outdoor water stoves have become a symbol for wood heating in general. Meanwhile, many companies with cleaner technology that could have contributed to a solution stayed silently on the sidelines hoping for a favorable outcome. The New York State Energy Research and Development Authority has been actively pursuing solutions, but many states have been more reactive than constructive. The result is that as energy prices rise, especially heating oil prices, citizens of states like Oregon have fewer alternative heating options. Meanwhile, the EPA is not only learning about all of the technology available, but is also filtering and reconciling federal and state requirements with wants and needs of industry, environmentalists, health groups and others. The one-size-fits-none Oregonian approach is a clear sign that there is much work to do. The EPA plans to publish its final residential NSPS Rule in 2012 and has presented 2013 or 2014 as a final deadline for compliance. It is imperative that all sectors come together to solve the hydronic heater emission testing problem. The eventual result must be a sea change from the average type of hydronic heater that is sold today. Hydronic heaters sold in the future must be authentically highly efficient and must be sold with a test report that is easily understood and trusted by consumers. The era of selling wasteful hydronic heaters/biomass boilers is over. Oregon has helped make sure of that. Author: Scott Nichols Director, BTEC and President, BioHeatUSA

“The premiere organization for scientists, governments, and industry working in all aspects of algal biomass.”

Cultivate the

Algae Industry

Shay Simpson, Associate Director – Bioenergy Program at Texas AgriLife Research, a member of the Texas A&M University System

Attend the world’s leading algal industry conference.

2011 Algae Biomass Summit October 25 – 27, 2011 Minneapolis, MN

Attendees will gain the following: • Expertise from the leading algal industry players • Insight into where the algae industry is heading • Information on new opportunities created by the industry • Plans and strategies for your algae fuel venture • Knowledge on trends in external financing for algal projects • New cultivation and harvesting methods and techniques • A better understanding of the latest government policies

“One of the best biomass conferences I attended all year. The contacts and exposure have proven to be invaluable to our biomass program.” Richard Wilson, Marketing Manager, Applied Chemical Technology

More than 800 leaders will be in attendance: “This conference offered exceptional exposure, relationship building with the ability to cement meetings that were previously held by e-mail and phone only. The decision makers were there…” Victoria M. Kurtz, Fluid Imaging Technologies, Inc.

• Algae experts and leaders who are shaping the industry • The top algae biomass producers in the world • Companies in algae-related industries and businesses with synergistic operations • Entrepreneurs planning to start a venture in the algal industry • Venture capital, finance & investment companies exploring investments in this domain • The biofuels and other biofuel products research community • End-users who are purchasing and utilizing the energy created

Register Today! Questions? Call us at 866-746-8385 Follow us:


Standardized Analytical Methods for Biomass Fuel Characterization BY CAROLYN NYBERG

As the U.S. power industry prepares to comply with potential regulations for greenhouse gas (GHG) emissions, many are considering biomass fuels as an option to reduce carbon dioxide (CO2) or to meet renewable fuel mandates. In some circumstances, biomass is considered a carbonneutral fuel, and the industry would be eligible for CO2 credits on the basis of displacement of CO2 emissions associated with fossil fuel-based electricity. Another advantage of incorporating biomass as a fuel source for electric utilities is that it has the potential to reduce the overall emission of hazardous air pollutants from power plants. This renewed interest in biomass as a fuel source has led to the need for proper characterization. The U.S. lacks consistency regarding the use of testing methods for biomass when combustion and fuel quality parameters are evaluated, however. Many laboratories are relying on methods that have been developed and validated for fossil fuels, which may not be suitable for biomass fuels. Biomass materials vary greatly in composition, and the concentrations of some constituents are well outside the range of what is typically found in fossil fuels. Concentrations of sulfur and trace metals are usually much lower in biomass fuels than in fossil fuels; however, some minor and major constituents such as phosphorus and potassium can be an order of magnitude higher. Many European countries have been utilizing biomass as a fuel for decades and have utilized test methods developed by the European Committee for Standardization (CEN), which has a technical committee (CEN/TC 335) solely dedicated to solid biofuels. The U.S. must collaborate with European and international standards organizations to help establish the use of the most appropriate test methods for biomass. By establishing consistent, reliable methods for biomass characterization, the biomass industry will be able to compare fuel quality results among different fuels analyzed by different laboratories and have confidence that the results can be accurately compared. As part of a current project sponsored by the U.S. DOE-Center for Biomass Utilization Program, the North Dakota Industrial Commission Renewable Energy 12 BIOMASS POWER & THERMAL | MAY 2011

Program, Metso Power, and the Electric Power Research Institute, the Energy & Environmental Research Center is reviewing biomass test methods from national, European and other international standards organizations. The International Organization for Standardization (ISO) now has a solid biofuels technical committee, ISO/TC 238, which is working to publish biomass standards that are similar to the European CEN standards. The EERC is involved with this committee and is working with other research and industry participants who share the same interest in establishing standardized test methods for biomass characterization. After a thorough review of the test methods deemed most appropriate for biomass characterization, this project will apply these methods to determine fuel combustion characteristics for a variety of biomass feedstocks produced in the U.S. The fuels currently enumerated for evaluation include switchgrass, corn stover, wheat straw and a variety of different woody biomass materials. Other fuels may be added as appropriate. The testing parameters will include those that are typically determined when fossil fuels are evaluated, such as moisture and ash content, heating value, volatiles, carbon, hydrogen, nitrogen, oxygen, sulfur, halogens, major ash chemistry, and a full suite of minor and trace elements. In addition to the aforementioned test parameters, the fuels will also be evaluated for potential slagging and fouling behavior in a utility boiler by performing computer simulations to predict the properties of ash in a boiler that might signify potential heat-transfer issues. Various biomass/coal blends will be examined. As a result of this work, standardized test methods will be established, implemented, and promoted for use throughout the U.S. biomass industry to provide the industry additional confidence when comparing fuels. Author: Carolyn Nyberg Manager, EERC Analytical Research Laboratory (701) 777-5057





Your company has valuable intellectual property. How do you create value and protect these ideas from your competitors? You must consider the business objectives for your intellectual property and then decide the answer to this question: “Do I patent a technology or keep it as a trade secret?” A patent is a grant of exclusive rights from a government that excludes others from making or using the invention. Advantages include the ability to force a competitor to stop exploiting the invention and the possibility of generating revenue from licensing arrangements or damages for infringement. Disadvantages include considerable upfront costs in obtaining the patent, complete public disclosure of the invention, and a limited term before the exclusive rights expire. A trade secret, by contrast, is something that confers a business advantage, is not generally known, and that the owner of which takes steps to maintain as a trade secret. Examples of steps to maintain a trade secret include restricting access to the information and having anyone that comes in contact with the trade secret sign a nondisclosure agreement. Trade secret protection allows you to stop an employee or party to a nondisclosure agreement from publicly disclosing the information, or to seek damages from such parties if the information is disclosed. Advantages of trade secrets include keeping the information secret and not revealed to the public or to your competitors. The protection lasts as long as the trade secret is not publicly revealed, and potentially has an infinite term, think about the formula for Coca-Cola. Trade secrets do not require upfront registration costs, however, there may be large and continuing costs related to keeping the information secret. Disadvantages of trade secrets include risks that if the secret is embodied in a product released into the market, a competitor can inspect the product and discover the secret. If the secret is discovered in this manner the competitor can proceed to exploit the secret. Once it has been made public, anyone may have access to a trade secret and use it. If a competitor were to independently invent the substance of the trade secret, it could possibly obtain a patent and stop you from continuing to exploit your former trade secret.


So, what should you do, patent or trade secret? By considering the underlying business objective, a strategy to patent a technology or keep it as a trade secret is easier to determine. For example, if your business generates revenue by inventing, or if you are attempting to position for acquisition or financing, patents will likely provide the most competitive advantage. However, if your business thrives in a mature market by improving in-house production techniques or the technology is difficult to reverse engineer, trade secrets might provide more value. For example, your company has invented a refining process for the extraction of valuable chemicals from biomass. The new refining process would be easily recognized and implemented if released to the public. Furthermore, the identification of competitors using this process may be difficult to ascertain by just looking at the finished products. Since the invention can be easily implemented and would be difficult to identify when in use by a competitor, keeping this information as a trade secret would likely provide a significant competitive advantage to your business. On the other hand, say your company has invented a unique chemical compound derived from biomass that can be used as a drop-in component in a large number of products presently commercialized. The chemical compound is easily identified in the final commercialized products and can be produced using off-the-shelf raw materials and simple processes that are easily derived by combining a few common techniques already known in the industry. Since the invention is a chemical compound that can be easily identified by examination of the final products and the compound is easily produced by a combination of offthe-shelf components and processes already known in the industry, a patent may provide a larger competitive advantage than a trade secret. Deciding your company’s intellectual property strategy can be complex. For best results, consult with your patent attorney to provide guidance regarding patents versus trade secrets. Authors: John Dolan and Matt Graham Shareholders, Fredrikson & Byron’s Intellectual Property Group (612) 492-7000


needed equipment. In response to the current trend toward leasing over purchasing, Dust Control Technology has announced an expansion of its program. The company now has 30 to 40 DustBoss machines in its fleet at any given time, ensuring ready availability. With a variety of differentsized machines available for short- or longterm lease, the company has units to suit virtually any project size.


Contractors offer rentals for dust suppression

CLEARING THE AIR: Companies requiring dust suppression can lease machines instead of purchasing them.

At a time when contractors and bulk material handlers are finding capital equipment budgets squeezed, many companies requiring high-performance dust suppression are turning to rental options to obtain

Martin Engineering to open business unit in India Martin Engineering plans to open a business unit in Pune, India. The company has been active in the Indian market since 2004, establishing a solid presence through its licensee, Thejo, to distribute and support select bulk material handling technologies. Already incorporated in India, Martin Engineering completed a market study and entry strategy in 2010, finding huge potential in further developing its business there. The company expects to have full operating capabilities by the second quarter of 2011. In addition to the Pune facility, Martin Engineering will have sales and service offices and staff in three other areas of India: Calcutta, Delhi and Chennai. HRE forms Homeland Biogas Energy Homeland Renewable Energy, the agricultural-waste-to-energy specialist, announced the establishment of its new division Homeland Biogas Energy, which is focused on turning animal agriculture waste and other organic waste streams into usable energy for America. The new division develops, owns and operates anaerobic digestion plants capable of producing various forms of renewable energy. HB Energy has an initial pipeline of eight projects, with an estimated total capital cost of over $150 million.


New software available for trigeneration, district cooling The energyPRO V4.1 software package from EMD has been expanded with new features allowing users to prepare detailed techno-economic modeling of trigeneration projects. These types of projects have so far been difficult for engineers to model precisely due to their complexity. With the newest energyPRO V4.1 software release, modeling of trigeneration projects can now be made on an hourly basis throughout the year. Based on the inputs, energyPRO can produce a full feasibility study for the proposed project for its whole project period. The software package allows users to include the benefits of using thermal energy storage when modeling cogeneration, trigeneration or integrated energy schemes. For information about energyPRO V4.1 and to download a demo version, go to NEF to supply miscanthus rhizomes to North American farmers


Biomass project earns Storey employee of the year title Years of extensive work on a biomass combined-heat-andpower plant project have earned Brett Storey, project manager for Placer County, Calif., the District 3 County Brett Story was Employee of the Year named District 3 County Employee title. The 2-megawatt of the Year because plant on the north end of his work on of Lake Tahoe will use a biomass CHP forest residues to heat project. schools, businesses and other structures in a 30mile radius. Besides providing clean energy, it will also be an effective solution to the catastrophic wildfires the region has experienced. Storey was hired in 2006 to help develop a solution to that problem and came up with the biomass plant proposal within one year. If all goes well, the facility could be operational by 2013.

GREAT GRASS: New Energy Farms supplies miscanthus rhizomes for growers in the U.S. and Canada.

New Energy Farms announced the opening of two large-scale facilities to supply miscanthus rhizomes in Canada and the U.S. From these sites NEF has the capability to produce tens of thousands of acres of miscanthus rhizomes from 2011 onward. The U.S. NEF site is in Tifton, Ga., and the Canadian site is in Ontario. NEF, which has more than 10 years experience


consultancy that is headquartered in Rotterdam, The Netherlands. The CKade office in Kuala Lumpur reinforces existing relations with parties in the region and provides detailed insight in local market developments.

Mott MacDonald expands renewable energy presence Mott MacDonald, a global management, engineering and development consultancy, is expanding its renewable energy presence in North America with the opening of a dedicated office in Boston, and the appointment of Tremain Tanner, an Tanner Tremain has international renewbeen hired by Mott able energy and utility MacDonald to help develop renewable infrastructure project energy projects. adviser. Tremain has been appointed vice president, renewable energy, and brings a wealth of experience in the development of private-sector renewable energy projects in wind, hydro, wave and tidal, biomass and landfill gas. He also has a successful track record in strategic consultancy in the North American power sector, and has extensive project-based transaction experience closing investments valued at more than $5 billion.

Bioprocess Control launches AMPTS II Sweden-based Bioprocess Control AB originally launched AMPTS I in 2009 and sold it to customers in more than 25 countries. AMPTS is used by universities, private research institutes and biogas operators around the world interested in understanding how much methane gas or energy different raw materials contain, and how the gas is produced in a digester. Building on the success of the firstgeneration model, the AMPTS II provides users with improved stability and functionalities such as built-in pressure and temperature sensors, integrated embedded data acquisition, and a new embedded Web server allowing for, among other things, automatic real-time pressure and temperature compensation, real-time gas flow and volume normalization, the possibility of multiplexing and remote access.

CKade expands to Southeast Asia CKade BV has opened an office in Kuala Lumpur, Malaysia, to establish a direct connection between the biomass markets in Southeast Asia and Europe, and to strengthen the development of secure and sustainable biomass supply chains. Security of supply of renewable raw materials is of critical importance for a new economy that will be less dependent on crude oil. CKade is an expert

Jansen hires LeBel as senior consultant Jansen Combustion and Boiler Technologies Inc. announced that Mark P. LeBel has joined the company. LeBel will be working in the Atlanta area as a senior consultant. He has had a long career with Combustion Engineering/ABB/Alstom Power Inc., most recently as manager of boiler engineering services. He has broad experience in design and operation of power, waste-to-energy and chemical recovery boilers as well biomass-fired circulating and bubbling fluidized bed boilers.

Morbark Introduces 3800XL Horizontal Grinder


in the supply of propagation material, also operates an affiliate program, providing technical support for growers, to support on-farm propagation to establish miscanthus for $500 per acre excluding Biomass Crop Assistance Program support.

DAILY GRIND: Morbark has released its new 3800XL Horizontal Grinder with improved feeding technology and efficiencies.

After more than a year of design review and in-field testing, Morbark released its new 3800XL Horizontal Grinder to the market. The new grinder contains significant changes and improvements in feeding technology, which increase production capacity and operating efficiency. The primary difference between this unit and others is its redesigned reverse-pivot feed system which minimizes space between the feed wheel and the hammermill. There is no place for material to hide in this unit, which keeps debris moving forward with uninterrupted, steady production. PCI newest Bandit dealer in the Northwest Bandit Industries of Remus, Mich., has added PCI Waste & Recycling Equipment of Portland, Ore., to its family of dealers. Serving the entire Pacific Northwest including Washington, Oregon and Idaho, PCI’s full line of industrial refuse and recycling equipment will be home to Bandit’s comprehensive offering of chippers and stump grinders. SHARE YOUR INDUSTRY NEWS: To be included in the Business Briefs, send information (including photos and logos, if available) to Industry Briefs, Biomass Power & Thermal, 308 Second Ave. N., Suite 304, Grand Forks, ND 58203. You may also e-mail information to Please include your name and telephone number in all correspondence.


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Beating Up on Biomass Opposition groups in Massachusetts petition for a three-year moratorium on biomass power.

Ever the biomass bullies, opposition groups in Massachusetts are continuing their organized efforts to stymie development in the commonwealth, this time asking for a three-year moratorium on biopower. The language of the petition circulating in and outside of the communities with biomass power proposals pinpoints a continuance of the December 2009 moratorium on new Statements of Qualification for biomass under the renewable portfolio standard (RPS), as well as a moratorium on approval of biomass air permits, until Dec. 31, 2013. In addition, the petition asks the Commissioner of the State Department of Public Health to issue a policy against biomass electricity. A number of opposition groups collaborated on the petition including Concerned Citizens of Franklin County and Concerned Citizens of Russell, but inquiries about the petition went unanswered by both groups. The petition itself says signed copies can be delivered to Massachusetts Forest Watch, but founder Chris Matera declined to comment on it. The moratorium request on the Statements of Qualification specifies the Dec. 31, 2013 date, but goes on to say “… or until such time as U.S. EPA concludes rulemaking on biomass energy greenhouse gas emissions under the Clean Air Act …” In January, the EPA announced a three-year deferment of compliance for biogenic emissions under its Tailoring Rule. All sources not exempt began compliance efforts in January, and the EPA says it will use the three years to further analyze the science behind biogenic emissions. “Agency determinations are normally made that a certain application does or does not comply with regulations and requirements,” says Stephen Kaiser, who describes himself as a mechanical engineer, as well as a technical resource for the opposition groups and expert witness. He says his opposition to biomass differs from others’ in Massachusetts, however, as he only opposes large plants and leaves open a use for small, dry-cooled biomass power plants to handle forest thinnings. “If 20 BIOMASS POWER & THERMAL | MAY 2011

EPA makes a determination that a power plant complies with requirements, I would not recommend concurrence by any group until the basis for EPA's decision could be reviewed for accuracy and credibility,” Kaiser continues, saying that in his experience, air pollution modeling is fraught with error and manipulation, even on the state level. But to some developers, the overall goal of the petition effort might be unclear. “There’s no process,” says Vic Gatto, principal and chief operating officer of biomass power developer Caletta Renewable Energy. “They’re just trying to get some petitions signed and trying to figure out what they could do. It could go on the ballot, but that’s a lengthy process, so that wouldn’t impact us.” Caletta is developing the 35-megawatt (MW) Palmer Renewable Energy Center in Springfield, Mass., scheduled for operation in 2013 with an appetite of 1,200 tons of wood chips per day. “We wouldn’t expect, given we’ve already been given the draft permit, that we would fall under [the moratorium]. It’s a long way away from being started and we will have received our final air permit by then, so it might hurt other people, but we wouldn’t expect it to hurt us.” Even taking the petition out of the equation still leaves a sketchy policy environment, as the Massachusetts Department of Energy Resources (DOER) is months overdue in releasing its final RPS qualification standards, having released a draft in September that was exceptionally damaging for biomass development. The rules are the basis for determining which projects qualify for the state’s 20 percent by 2025 RPS and receive renewable energy certificates (RECs). Among other things, the proposal stipulates that a biomass power plant will only be eligible if it achieves 40 percent efficiency, and still would only receive half an REC. Under the proposal, that would be ratcheted up to one full REC upon reaching 60 percent efficiency. But from a developer’s perspective, even 40 percent can be a daunting hurdle. “The notion that anybody is going to get those levels of efficiency

FIREDUP¦ is humorous,” Gatto says. “It wouldn’t make sense that they would keep those efficiency numbers there, but that doesn’t mean that they won’t. At this point, we’ll just have to wait and see what they come up with, and we’re content to move forward regardless of what they decide to do.”

In the Beginning It all started in December 2009, when the state commissioned a study by the Manomet Center for Conservation Sciences to evaluate the carbon neutrality of biomass for energy, after heavy fire from biomass opposition groups. At that time, a moratorium on RPS qualification for biomass projects was implemented and was to remain in effect until the study was concluded and any appropriate subsequent measures were taken. It remains in effect now, awaiting the release of the final RPS qualifications. The findings of the study, released in June 2010, explain a debt-then-dividend carbon analysis of woody biomass, saying it initially releases more carbon dioxide than coal per unit of energy, but pays off its carbon debt as forests regrow and that carbon is resequestered. But the study has raised arguments from the biomass industry in numerous aspects, perhaps most notably its evaluation of whole tree feedstock. It does take slash and forest residue into account, but only alongside whole logs. Still, then Massachusetts Executive Office of Energy and Environmental Affairs Secretary Ian Bowles wrote a letter to the DOER on July 7 ordering a swift change to the RPS qualification standards, in light of the “deeper understanding” of the greenhouse gas impacts of biomass

energy communicated in the Manomet study. Bowles has since been replaced by Richard Sullivan, but Gatto says he doubts the position comes with much clout in the hot debate. “I don’t think they’re much in control of the Massachusetts environment,” he says. “They’re doing their job and trying to follow the rules. There are lots of people on both sides of the issues.” Interestingly, Bowles’ letter was issued two days before the public comment period on the Manomet findings was up, and subsequently, a ballot initiative being pushed heavily by the state’s biomass foes was taken off the table. Grassroots group Stop Spewing Carbon announced it would no longer push for its ballot initiative limiting biomass power emissions to 250 pounds per megawatt hour, as it considered Bowles’ letter a sign of its victory. “With regard to the new grassroots petition, I don’t know if biomass opponents will go to the same lengths that they did on the ballot initiative on which they spent, according to state records, $307,526.74,” says John Bos, public information officer for Russell Biomass LLC, which is developing a 50-MW plant in Russell, Mass. “The fact is that the environmental clock is ticking while the potential for renewable energy development in Massachusetts has been slowed to a snail’s pace because of opposition to large-scale biomass, large-scale wind and, more recently, all sizes of on-shore wind,” Bos says. “Without large-scale biomass-fueled electric power using clean, nonforest waste wood fuel, the commonwealth will not meet [its renewable goals].” —Lisa Gibson

Easy MACT Dixon Environmental launches free online tool to simplify compliance with EPA rules.

Instead of wading through pages and pages of complex criteria and compliance requirements, facilities affected by the U.S. EPA’s Maximum Achievable Control Technology rules can opt to use, a free online applicability tool that outlines compliance requirements for specific boilers and facilities. Requiring only simple data inputs and unit information, clearly states whether a unit is affected by the rules and if so, what compliance requirements it will fall under. The final MACT rules, released in February, include standards for four source categories—major source industrial, commercial and institutional boilers and process heaters; area source industrial, commercial and institutional boilers; commercial and industrial solid waste incinerators; and sewage sludge incinerators—as well as an updated definition of solid waste. With around 30 users so far, feedback about the tool has been positive, according to its creator Dixon Environmental, a compliance management solutions provider. Users have reported it’s easy to use and intuitive, according to Mike Dixon, president of Dixon Environmental. No biomass-fueled units have been registered yet, but Dixon expects that to change soon. “We think it’s a pretty cool thing to offer,” Dixon said, adding that the program has already found additional areas of compliance for unit operators who thought they had figured it all out for themselves.

With input from the American Coatings Association, the Society of Chemical Manufacturers & Affiliates, and the National Association of Printing Ink Manufacturers, Dixon has conducted a soft rollout for the program that began in March. The company will continue gathering feedback from those trade organizations and hold an open webinar May 10 that will incorporate feedback from all users willing to offer it. The program will continue to evolve, as well, with the addition of a template for the report for initial notification. Affected facilities will be required to submit the notice in September, and Dixon said the template will simplify that requirement. The EPA estimates its MACT rules will affect nearly 200,000 facilities, and many will undoubtedly be looking for help, as some have not been previously affected by hazardous air pollutant regulations, Dixon said. “When you look at the numbers, there’s got to be a lot of people who need help with it,” he said. Smaller companies operating boilers subject to the new rules may not have official programs in place to account for such compliance like some larger facilities do, he added. Dixon said the program will also help his company get its name out in the effected industries as a solutions provider. “It has worked,” he said. “A lot of people are registering that we haven’t heard of before.” —Lisa Gibson MAY 2011 | BIOMASS POWER & THERMAL 21


Genetic Engineering Hang-Up ArborGen Inc.’s genetically engineered freeze-tolerant eucalyptus tree has been shown to withstand temperatures as low as 15 degrees Fahrenheit, enabling its planting in some Southern U.S. areas. But the USDA has been sued by a group of conservation organizations who argue that the non-native tree is invasive and could displace native wildlife and plants, increasing wildfire risk. The Dogwood Alliance, the Sierra Club, the Center for Biological Diversity, the International Center for Technology Assessment, the Center for Food Safety, and the Global Justice Ecology Project together allege that allowing the tests along the Gulf Coast and into South Carolina would be a disaster and lead to a loss of native forests and biodiversity. The tests could also lead to groundwater depletion, the group contends, and worsened climate change. In addition, the organizations have raised concerns about ArborGen’s petition for deregulation of the tree, which would allow commercialization and cultivation without restrictions or permits. ArborGen declined to comment on the ongoing lawsuit, but Karen Batra, director of communications for the Biotechnology Industry Organization, says the deregulation petition is a standard aspect of the biotechnology process and accounts for any environmental impacts. The petition includes reams and reams of paperwork including results of multiple studies such as environmental assessments, impact assessments, and field tests among others. The insect-resistant corn widely grown today went through the same procedure, she explains. “As part of the research and development process, as well as the process to petition for deregulation, you would have to look at the environmental impacts of these products and if there was any danger to the environment, you would not have a petition for deregulation,” she says. “The company would go back and look at what that impact was and would address it in the field trial stage or in the research and development stage. And that’s certainly not the case here.”


Lawsuit highlights a barrier to biotechnology advancements in the U.S.

BIOTECHNOLOGY BARRIER: The USDA is under fire for approving field tests of ArborGen's genetically engineered eucalyptus trees.

ArborGen’s deregulation petition has been pending with the USDA for nearly 2½ years now, a long but standard wait for such a request. The wait time has increased by 700 percent since 1995, Batra says. “At that time when the technology was new, we could get these through in less than a year,” she says. “Now that the technology is about 20 years old and we’ve got scientists that are reviewing these applications and know more about the technology, it’s taking two and three and four years. It is what we would call unreasonable, but unfortunately, it’s become typical.” Currently, 23 deregulation petitions, including ArborGen’s, are pending with the USDA. Lawsuits like the one involving the genetically engineered eucalyptus trees have become a hindrance to biomass development, as they discourage investment. “Obviously, the litigious environment we have seen in the past couple years is representing a tremendous deterrent to investment in [biotechnology], especially on the biomass side, where a lot of them are start-up companies.” Batra says. “It’s making it very hard to get investments and to see their way through what could be five and 10 years in development of a product, if when you finally do get to a point where you’re close to commercialization, you’re going to have to deal with litigation. It is creating a huge barrier.” —Lisa Gibson



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Sustainability in Europe The EC is revisiting its biomass sustainability criteria after changes in the international policy context on biomass.

In its February 2010 report on sustainability requirements for the use of solid and gaseous biomass sources in electricity, heating and cooling, the European Commission concluded that binding sustainability criteria on the European Union level was unnecessary. Instead, it outlined a number of areas it deemed important, recommending EU member states develop or update their own sustainability programs. Drawing from the public consultation held before the report, the EC found worth and necessity in addressing sustainability in production; land use, land use change and forestry accounting; life-cycle greenhouse gas (GHG) performance; and energy conversion efficiency. Further, the report recommends that in member states’ sustainability programs, the GHG performance criteria need not be applied to wastes. To stimulate higher energy conversion efficiency, member states should differentiate in favor of installations that achieve high energy conversion efficiencies, the report adds. It also includes recommended scope of application of the criteria, and requirements for reporting and monitoring. The EC promised in the report to return to the issue and release another report by Dec. 31, examining whether national sustainability schemes have sufficiently and appropriately addressed the issues, and whether EU-level criteria are now necessary. So another consultation period was held Feb. 1 to March 29, welcoming comments from within and outside the EU. The consultation document outlines three areas the EC seeks input from stakeholders on: the extent to which recent developments in the bioenergy sector reflect significant changes compared with the conclusions drawn in the February 2010 report; the extent to which other new policy developments related to the use of biomass have contributed to the sustainable production and consumption of biomass; and the development of sustainability criteria for solid and gaseous biomass at national and/or regional levels and their impacts.

Since the initial report, the European  ON THE WEB and international policy context on biomass continues to evolve, the consultation states, LexUriServ/LexUriServ. including in the areas of illegal logging regu- do?uri=COM:2010:0011: lation, wood mobilization, forest protection, FIN:EN:PDF reducing emissions from deforestation and forest degradation. But besides that, biomass use has been increasing in the EU and further growth is anticipated. Bioenergy will play an important role in reaching the EU’s 20 percent by 2020 renewable energy target, the consultation says, and about 10 percent of the total gross final energy consumption in the EU is expected to come from biomass. It adds that in 2020, biomass would contribute to around 6.5 percent of final electricity consumption, 17.5 percent of the heating and cooling consumption, and 9.5 percent of the final transportation consumption. That would more than double bioenergy consumption between 2005 and 2020, with heating and cooling holding the most important rankings. More than 160 comments were submitted during the 2011 consultation, according to the EC. EU countries with the most comments were the U.K., Belgium, Austria, Germany, Netherlands and Sweden. More than 120 of those comments indicated that imports, mostly of wood chips and pellets from North America and Russia, will increase. The comments will be crucial in the development of the December report. “If appropriate, this document will discuss the option of adoption of additional measures, including binding EU sustainability criteria,� says Giulio Volpi, of the EC's Renewable Energy Policy office. “The public consultation helps inform the commission’s view on this matter.� —Lisa Gibson

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Cooperating for Biomass Concerned about the liability posed by piles of sawdust at their operations, six sawmills near Thorne Bay on Prince of Wales Island in southeast Alaska have formed a cooperative and proposed a wood pellet and biobrick facility that would use their wood waste. The Prince of Wales Biofuels Cooperative is currently developing a business plan to present to the Alaska Industrial Development and Export Authority, hoping to receive $4 million to $5 million for the project, according to Ralph Porter, co-op member and owner/ operator of Porter Lumber. The exact cost and timeline for operation has not been nailed down, he adds. “We’d like to be operational right now, but we’re still trying to find financing for the whole thing. When the money comes, I think within about nine months we’ll be in operation.” The cooperative was formally incorporated at the end of July 2009. Criteria stipulate that members must be a wood fiber producer and an Alaska business owner, according to Karen Petersen, University of Alaska Extension Program assistant. The university helped form the co-op on multiple levels, assisting with research and answering questions from the potential members before its inception.


Sawmills on Prince of Wales Island in Alaska formed a co-op and plan to build a pellet and biobrick mill.

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PRINCE OF WALES BIOFUELS COOPERATIVE MEMBERS H&L Salvage, Thorne Bay Last Chance Enterprises, Thorne Bay Porter Lumber, Thorne Bay Thuja Plicata, Thorne Bay Port St. Nick Forest Products, Craig Out on A Limb, Thorne Bay

If approved for funding, the biomass plant will be located on a nine-acre site leased from the city of Thorne Bay. The plant will need about 24,000 green tons of biomass annually and may also use residue from forest management, depending on agreements with the U.S. Forest Service, Petersen says. “Right now, nothing happens with biomass here,” she says, adding that the Forest Service and the co-op are looking into logistics of residue harvesting together. “There’s been a big education step up here for everyone and they’re probably looking more toward doing a stewardship contract and collecting debris off of the ground.” About onethird of the biomass will be burned on-site to heat the plant and dry the material.

And with the rest of that wood, the biomass plant would produce 8,000 tons of solid biomass fuel, half pellets and half biobricks, according to the current business plan. “There’s definitely a market for both,” Porter says. The U.S. Coast Guard has plans to install biomass district heating systems at its Alaskan bases in Ketchikan and Sitka, and will need at least 4,000 tons of pellets, he says. In addition, the U.S. Forest Service is installing two biomass boilers in its Ketchikan location, as well as one in Sitka. The biobricks will most likely be used in residential appliances, as they are cheaper than firewood and ease the need for wood chopping and hauling. “I don’t think we’re going to have any problems selling all the pellets we can possibly produce,” Porter says. Down the road, the co-op could contact the remaining six or seven sawmills on Prince of Wales Island and negotiate terms for the use of their wood waste, too, he says, adding that the model is great for any area with a number of wood processing facilities dealing with on-site waste. “The reason I think this is going to work well is all of these sawmill operations are really small,” Petersen says. They all saw less than 1 million board feet and are not producing enough sawdust to operate their own pellet facilities, she adds. “Unifying it, now they’ve got enough to make it worth their while.” —Lisa Gibson


A Biomass Marathon In February 2009, Marathon Pulp Inc. closed its pulp and paper mill in the northern Ontario, Canada, community of Marathon. The closure cost about 250 jobs, but a majority of that workforce is in line for reemployment at a proposed biomass center that would occupy the same structure. Protocol Biomass Corp., an affiliate of Protocol Energy International Inc., has plans to turn that shuttered mill into an involved and multifaceted biomass facility that would include a torrefied black pellet mill; a 17-megawatt power plant with added heat output for commercial users; and the Protocol Sustainable Bioeconomy Satellite Campus, a research and development operation. The cost will climb north of $100 million, according to Protocol. All aspects of the project are scheduled for completion in 2012, starting with the pellet mill. Initially upon start-up in the first quarter, the mill will serve as a pilot facility and produce about 50,000 metric tons for testing in coal-fired power plants in Europe and Canada, according to Protocol Biomass Chairman and CEO Thomas Logan. “That’s where we’ll shake everything down,” he says. Successful pilot demonstrations will lead to a capacity of 300,000 to 600,000 metric tons of pellets in the third or fourth quarter of 2012. The cogeneration plant, subject to government approvals, should be operational in the fourth quarter of 2012, along with the research facility. The project’s host facility was built in the 1940s, Logan says, and is in excellent shape. An interesting fact he adds, is that it’s the only paper mill in Canada that didn’t encounter work stoppage due to labor disputes. That wood savvy, competent and eager workforce is one of the main benefits of establishing the facility at the shuttered mill, he says. Other benefits include the reusable infrastructure and its proximity to a rich wood basket and excellent transportation



Protocol Biomass has a proposal that could serve as a model for shuttered pulp and paper mills.

REPURPOSING PULP AND PAPER: Marathon Pulp in Marathon, Ontario, which closed in 2009, could soon be transformed into a biomass energy center.

infrastructure. In addition, the project has outstanding support from the community of Marathon and clear provincial support to salvage as many jobs as possible. “Our appetite is to bring back half of the workforce,” Logan says, adding that the figure maps well with the availability of employees because some are close to retirement. When asked if Protocol’s strategy is a good model for other closed paper mills, Logan responded with a strong, “Absolutely.” He added that there is plenty of room at the forest industry table for biomass. “There are a number of closed not just pulp and paper mills, but sawmills,” he says. As long as there is a decent and underutilized wood basket nearby, any such facility could thrive as a woody biomass operation, he says. —Lisa Gibson


Power on Wheels Utilizing a design pioneered by downdraft gasification system developer Community Power Corp., Montana researcher Brian Kerns has developed a mobile biomass gasifier, after collaborating with the company to integrate their design with his own ideas. So far, his work has resulted in a 25-kilowatt per hour system that can easily be transported to areas where there is a need to manage woody biomass waste, such as pine beetle-killed wood. “Instead of gathering the biomass materials and bringing them to a centralized plant, which is the norm, we wanted to do the opposite,” Kerns says. That strategy provides several benefits, including avoiding feedstock transportation and storage costs. The system, which is enclosed on a semi-trailer platform, can be set up and running within an hour. “It’s a quick, nimble and flexible system,” Kerns says. And though it sounds simple, actual development wasn’t easy. “Even though CPC has been building these things for 15 years, it was a significant challenge to modify and condense it so it fits adequately, and so that the weights and balances were such that it could easily move down the road.” In a recent demonstration, Kerns gasified pine beetle wood, which is a growing problem in some Western states such as Montana and Colorado, as well as in areas north into British Columbia and Alberta, Canada. “While some of the pine beetle wood is useful as logs, a lot of it is smaller in diameter and is wasted,” Kerns says. Before the feedstock is fed into the system, it must be chipped. “During our last demonstration, we had a chipper set up and a conduit from the chipper into the enclosed trailer,” Kerns says. Pine beetle-killed wood is typically dry, around 35 to 40 percent moisture, Kerns says. The material must be at about 10 percent moisture to be gasified, but drying doesn’t have to be done separately. The ambient air in the system that cools the producer gas also dries


Montana researcher develops a mobile biomass gasifier.

GASIFIER ON THE GO: Kern's 25-kilowatt per hour gasifier is enclosed on a semi-trailer platform so it can go where the feedstock is available.

the feedstock before it undergoes the gasification process. “The CHP (combined-heat-and-power) system recovers the waste heat and uses it to dry the feedstock as it’s running,” Kerns explains. After the gasification process, the power produced is plugged directly into the grid. Kern’s next goal is to scale the system up to an economical level. “We’d like to try to figure out the parameters that would make it pencil out,” he said. “It would probably need to be of a size somewhere north of 200 kilowatts.” Bringing the system up to that scale while keeping it mobile could prove to be a challenge, he notes. “As you start upsizing, you’re talking about more weight and larger pieces of equipment, so it’s a difficult balancing act. It would have to be able to process a lot of wood fairly quickly while producing a lot of electricity, and relatively cheaply.” Kerns is now seeking a second round of funding from federal or state agencies in order to keep the project going, and to figure out what the next stage is to make the mobile gasifier a commercial reality. —Anna Austin



Survey Says … USDA’s first national on-farm renewable energy survey finds 121 farms with 140 on-site digesters.

The USDA has released its 2009 On-Farm Renewable Energy Survey results, a follow-up to the 2007 Census of Agriculture survey. This is the first on-farm renewable energy production survey conducted on a national level by the USDA National Agricultural Statistics Service, and besides methane digesters includes information on energy produced by wind turbines and solar panels that were in operation on farms in 2009. All farms that reported using methane digesters on the 2007 Census of Agriculture, plus all farms on the U.S. EPA’s AgSTAR list were included in the survey to ensure better coverage. Data for the report was acquired through confidential surveys and only takes into account those who reported information. The survey also included installation cost, percent of cost from outside funding, year installed and total amount of utility savings from the use of on-farm renewable energy production. Though the use of digesters is small compared to wind and solar, the USDA points out that it is growing. Seventy-two percent of the digesters in use today were installed from 2005 to 2009. Results of the survey showed that there are 121 farms with 140 on-site digesters (some farms have more than one digester) owned and operated by the farm operation. Wisconsin has the most, with 25 digesters on 21 farms. On average, the farms that reported digesters produce about 30.5 million Btu per cubic feet of methane, and the average cost

Average per methane digester Number of digesters

Methane produced (cubic foot)

Installation cost (dollars)

United States
















New York
















Other States




(D) Withheld to avoid disclosing data for individual farms. SOURCE: USDA

of installation was about $1.7 million. The industry growth could be a result of more state offices providing significant funding for the installation of anaerobic digesters. For example, funding has come from the California Energy Commission, the Iowa Office of Energy Independence and the New York State Energy Research and Development Authority. —Anna Austin


Pelleting Plants for the Recycling Industry Domestic Waste: Pellets or Fluff

Wood: Pellets

Biomass: Pellets

Waste Tyres: Granulate

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Connecting the Dots Wisconsin network connects people to grassland bioenergy info and resources.

The University of Wisconsin’s Agricultural Ecosystems Research Group has launched a new network devoted to opportunities and challenges in bioenergy development in Wisconsin, while protecting environmental and ecological resources. The Wisconsin Grassland Bioenergy Network is an information and connectivity resource linking people—farmers, researchers, project managers and others— to information, resources and other people involved in grassland/agriculture-based bioenergy in the state, while focusing on perennial herbaceous plants. It took nearly a year and a great deal of effort and collaboration to develop the network, according to coordinator Carol Williams, who is a professor in UW’s Department of Agronomy. The website offers visitors access to biomass resource atlases, bioenergy policy information, upcoming events, federal and state programs, grants, jobs and internships related to the industry, and an industry directory with contact information for individuals representing various biomass industry trade organizations, companies and projects. While some general information is available, most of the resources on the website have particular relevance to Wisconsin. For example, under the website’s atlas tab, the Biomass Resource Regions of Wisconsin atlas divides the state into five regions—northern, northeastern, southeastern, south central and west central—and allows users to


click on a region of choice. It then provides a geographical description of the region, dominant tree species and vegetation, key biomass resources and biomass projects in the region, including forums, harvest, research and utility projects. The website also hosts a spotlight feature on a particular individual in the state and explains what he or she is doing in the bioenergy industry. For example, Matthew Dornbush of BIOMASS FINDER: The University the University of Wisconsin-Green of Wisconsin has developed a bioenergy network. Bay was recently featured for leading an effort to evaluate the economic and environmental outcomes of converting poorly drained, marginal agricultural areas into perennial, biomass-yielding grasslands for electricity and heat generation in Wisconsin. —Anna Austin


Pellet Projects

The University of Montana is making biomass energy happen.

Developers plan to build two pellet mills in Virginia.

The University of Montana in Missoula is forging ahead with a biomass gasification combined-heat-and-power project that will replace 80 percent of its natural gas consumption. UM has been carefully evaluating biomass for about a year and a half, according to Bob Duringer, UM’s vice president for administration and finance. Wind and solar aren’t feasible energy options given the college’s location, he says, and because Missoula is in a heavily forested area, biomass made sense. On top of that, a fiberboard company in the area closed about two years ago. “So we knew there was a huge amount of marketable slash and other forest residuals out there,” Duringer says. The system would utilize 20,000 tons of wood waste per year to generate 34,000 pounds of steam per hour. Due diligence work with some wood chip and pulp firms within a 75-mile radius of the college has given UM a clear picture of fuel costs, according to Duringer. Feasibility studies completed by McKinstry, a Seattle engineering and construction firm, which will be UM’s performance contractor, and Nexterra Inc., the equipment provider, confirmed the viability of the project.


Breaking Away

GASIFICATION ON CAMPUS: The University of Montana plans to build a biomass gasification system that will replace 80 percent of its natural gas use.

Total cost for project construction/ system installation will be $16 million. The Montana Department of Environmental Quality has provided a $180,000 grant toward the project, and the rest will be paid with monies saved from reducing natural gas costs. “We’ll divert that money to pay for the debt service on the plant, as well as the plant’s operations,” Duringer says. UM already applied for an air permit, an economic assessment should be completed within a month and UM will take the project to the Montana Board of Regents for approval on May 19. “We anticipate that it will be approved, and then we’ll set the engineers loose to complete the design,” Duringer says. The goal is to have the system running by April of 2012. —Anna Austin


Wood Fuel Developers LLC, an affiliate of Industrial TurnAround Corp., is developing two wood pellet facilities in Virginia, having received multiple grants. The company announced its plans for Greensville County in January of 2010, armed with more than $3.5 million in federal and state funds, and planning to invest $18.7 million itself, according to ITAC. The company reported that the project received $1 million from the American Recovery and Reinvestment Act, along with $2.3 million from the Greensville County Industrial Development Authority for construction of the plant and site improvements and infrastructure, $175,000 from the Governors Opportunity Fund and $175,000 from Tobacco Region Opportunity Funds. Also, in January, Virginia Gov. Bob McDonnell announced a new $8.6 million pellet mill undertaking for Wood Fuel Developers in Sussex County, with another $185,000 in state funds from the governor’s office and Tobacco Region Opportunity Funds. Wood Bioenergy US, a Forisk Consulting report, said the company will convert a former particleboard plant in the Sussex County town of Waverly into a pellet plant. —Lisa Gibson


Development Deterrent Washington County biomass moratorium quashes project.

In late December, the board of commissioners in Thurston County, Wash., adopted a one-year moratorium on permitting new biomass power facilities to give them time to investigate environmental concerns surrounding biomass energy. In particular, the sustainability of sourcing wood debris and airborne emission levels from the conversion process. The decision was influenced by local opposition groups who were protesting area biomass projects, including Evergreen State College’s biomass gasification plant and Adage LLC’s 55-megawatt (MW) power plant in Mason County. Adage’s project was cancelled, but not because of opposition or permitting challenges, according to the company. However, Evergreen’s project was derailed largely because of the moratorium. Evergreen, which already purchases all of its electricity from renewable resources, still uses natural gas for heat. Several years ago, to meet its goal of achieving carbon neutrality by 2020, the college began exploring options to replace natural gas. After investigating several renewable options, it was determined that biomass gasification had the best potential to meet the desired criteria. In the fall of 2010, Evergreen’s Sustainability Task Force began conducting a feasibility study. Though the study has yet to be com-

pleted, the project is off the table. In a letter to the college administration, the university’s Sustainability Council Chair Steve Trotter reported that the project would decline a $3.7 million grant from the Washington Department of Commerce, and withdraw a capital grant request from the state budget process. Trotter says the task force declined the grant because the moratorium leaves the project unable to proceed for nearly a year, and also leaves the status of future codes and permitting related to biomass too uncertain. “The decision is not based on the merits of the project itself,” Trotter writes. “We have not yet completed our report, but I can say that our preliminary findings from more than a year of work indicate that the project could meet many of the environmental, operational and economic criteria the college established for a replacement of natural gas for campus heating.” The project feasibility report (expected to be completed in late April) will not answer every question about biomass gasification, but it should provide a valuable resource to others or to the college should it decide to revisit this proposal in the future, Trotter says. The moratorium shouldn’t prompt neighboring counties to adopt similar mea-

sures, according Tim Sheldon, a Washington state senator and one of three Mason County commissioners, who says he doesn’t think it will affect Mason County, which is just north of Thurston County, at all. “Mason has about one-fifth of the population of Thurston, and only one incorporated city,” he says. “Green Diamond Resources owns about a third of the timberland in Mason County, with the federal government owning the other third and the rest privately owned. It’s got a long wood products history, several large sawmills, and existing biomass [facilities].” Even though the Adage project had its opponents, they were a small minority, Sheldon says. “The Simpson Timber Co. is planning an expanded biomass project at its mill (the company operates a 31-MW biomass cogeneration plant at its pulp and paper mill in Tacoma, Wash.) and it has already received a determination of nonsignificance by the city of Shelton on its environmental application. I’m hopeful it moves forward, and that it brings new jobs and technology to our timber-dependent county,” he says. —Anna Austin

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POWERFUL PLANT: Dalkia has built a CHP plant capable of producing 50 megawatts of power and 260 metric tons of steam at the Smurfit Kappa Cellulose du Pin paper mill in Fracture, France.



Big Biomass European energy provider Dalkia recently commissioned the largest biomass combined-heat-andpower plant in France. Its co-location with a paper mill provides a number of beneficial exchanges between the two operations. BY LISA GIBSON





n September, European energy giant Dalkia commissioned the largest woody biomass-fueled, combined-heat-and-power (CHP) plant in all of France. And it’s a monster. With an output of 50 megawatts of electricity and 260 metric tons (286 tons) of steam per hour, the plant dwarves the country’s existing biomass power plants, which on average produce 3 MW, according to Dalkia. It shares a site with the existing Smurfit Kappa Cellulose du Pin paper mill in the small southwestern town of Facture, significantly simplifying the transmission of steam and electricity to the mill’s operations. All the steam and some of the power produced at the CHP plant is sold to Smurfit Kappa and used on-site. “As the power plant is connected to the French grid through the mill connection, in fact, all the electricity is delivered to the mill,” says Mario Kuczynski, project manager for Dalkia. The excess power not used in the mill’s operations is sold to the national grid through Électricité de France. “This means that the pulp and paper mill is autonomous.” That autonomous mill will now receive a guaranteed flow of steam for its operations with a contracted price 15 percent lower than the present internal cost, Kuczynski adds. The 20-year contract between the two partners will guarantee long-term efficien-

ON-SITE OFF-TAKE: Smurfit Kappa's paper mill will use the steam and some of the power produced by Dalkia's CHP plant, located within the mill's complex.

cy and economic performance of Smurfit Kappa’s mill, not to mention almost half of Dalkia’s feedstock needs in bark and wood dust supplied by the mill. “It’s a wonderful win-win project for all parties,” he says.

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ogy company serving the pulp and paper industries, with its hands in seemingly all the industries’ projects. At the heart of the operation is a bubbling fluidized-bed boiler, which is fed screened, chipped feedstock by a conveyor belt running from the 15,000-cubic-meter storage facility capable of holding up to three days worth of wood, according to Jouni Kinni, sales manager for Metso. “Thanks to a reclaimer of 17 meters long located at the bottom of the shelter, the biomass is continuously extracted and transferred to the boiler,” Kuczynski says. “It needs 300 meters of belt conveyors and two temporary silos in order to be 24/7 on full load capacity of the boiler.” The biomass—either delivered already chipped or chipped on-site—burns on a bed of sand in the boiler, he explains, comparing it to a hot tub, but with a scalding temperature of 850 degrees Celsius (1,562 degrees Fahrenheit). The basic flue-gas-cleaning backhouse includes three rotating cylindrical modules. The conventional backhouse system allows the paper mill to also combust waste from the recycled cardboard it uses to make its products, Kinni says, citing it as the main reason the backhouse design was chosen for the application. Smurfit Kappa Cellulose du Pin provides the CHP plant with 220,000 metric tons per year of its bark and wood dust, and another of the company’s paper mill locations, Comptoir du Pin, supplies 250,000 metric tons of branches and stumps, according to André Champarnaud, Cellulose du Pin mill manager. Another 80,000 metric tons will come from other sources such as construction sites and sawmills. In addition, debris from the Klaus storm that ripped through France in January 2009 will provide about 250,000 metric tons of wood feedstock for the system, offsetting its normal fuel needs, according to Dalkia. Besides supplying wood waste for the biomass processes, Smurfit Kappa Cellulose du Pin also contributes its highpressure steam to be converted into megawatts, Champarnaud says. “We sell bark and high-pressure steam and we buy medi-

um- and low-pressure steam,” he explains, adding that the steam the mill buys back is used for drying paper and digesting the wood, and satisfies all of the mill’s steam needs. “All the steam we use in the paper mill is from Dalkia, so the cost of energy for the next 20 years is quite stable.” Clearly, the setup results in a number of benefits, not the least of which are increased efficiency and reduced operating costs. The facility as a whole, including both paper and biomass processes, will be operating to optimum efficiency levels of 70 percent. But besides that and stable energy costs, Champarnaud says Smurfit Kappa no longer burns natural gas to produce its steam, which comes with a substantial savings in carbon dioxide regulation compliance. In addition, the mill is no longer bothered with updating an existing biomass boiler and two turbines it had



BUBBLING BIOMASS: The Dalkia plant will use Metso's bubbling fluidized bed boiler.



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Production from: - coal - oil - gas - biomass - waste - nuclear - hydro* - geothermal - solar PV - solar thermal - wind - tide - other sources Total production Imports Exports Domestic supply Statistical differences Transformation** Electricity plants Heat plants*** Energy industry own use**** Losses Final consumption Industry Transport Residential Commercial and public services Agriculture/forestry Fishing Other nonspecified

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Heat Unit: Terajoules

27,231 5,825 21,884 2,116 3,776 439,468 68,325 0 41 0 5,689 513 0 574,868 10,683 -58,689 526,862 0 0 0 0 60,465 32,916 433,481 141,206 13,279 155,608 108,282 3,832 123 11,151

14,863 23,335 97,970 0 21,336 0 0 0 0 0 0 157,504 0 0 157,504 0 0 0 0 0 157,504 0 0 0 0 0 0 157,504

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previously operated. “If we didn’t do this contract with Dalkia, we’d have to update again,” he says. Those updates, he adds in a thick French acccent, are a substantial investment for the company, “but we have stopped them and we have [no need] to renew them.” The local community of Facture is not left out of the benefit circle, as the CHP plant brings tax revenue and about 90 jobs. The country of France itself will benefit from the project through the high-voltage green electricity and its contribution to reduce global climate change, Kuczynski

says. Needless to say, all parties involved believe the enormous project will help realize significant benefits all through their 20year contract.

Biomass in France Smurfit Kappa Cellulose du Pin produces 500,000 tons per year of kraft liner and white top kraft liner. The facility is the only possible local industrial consumer for Dalkia’s plant, thus the decision to plot it within the mill’s existing infrastructure, Kuczynski says, emphasizing that the plant is located as close as possible to the paper process.

INTERNATIONAL¦ Use of such biomass CHP systems in France’s pulp and paper industry is beginning to expand, Champarnaud says, citing regulation from the European Commission. “We cannot say it is common, but it is developing.” France has national renewable goals, too, and in 2009 committed to an overall objective of 23 percent of renewable electricity by 2020 within the context of the EU Climate Change Package. While the French incentives of tax amortization and preferential electricity purchase rates have attracted significant attention to the development of solar- and wind-powered energy, biomass is increasingly perceived as a more reliable and efficient alternative source, according to Jones Day, a law firm with an office in Paris. France is targeting an overall biomass power capacity of 2,300 MW by 2020, in order to increase its yearly biomass electricity production by a factor of five compared with its 2006 level. A generating capacity of 2,300 MW, running at an impossible 100 percent efficiency and 24/7 maintenancefree schedule, would generate more than 20,000 gigawatt hours (GWh) per year. In 2008, 2,116 GWh of electricity were produced from biomass in France, with another 3,776 GWh from waste (separate from the biomass category), according to the International Energy Agency. Heat production from biomass that year was nonexistent, but 21,336 terajoules (TJ) were produced from waste. The most power that year was produced from nuclear sources at about 440,000 GWh, and the most heat came from gas at nearly 98,000 TJ. Wind produced more than 3,000 more GWh of power than biomass in 2008, and hydropower tipped the scales at more than 68,000 GWh. Neither source, however, was used to produce any heat that year, according to the IEA. And as more biomass plants are established within the pulp and paper industries in France, those biomass figures will continue to grow. Projects similar in size to the Facture plant have been erected in Denmark, Finland and Sweden, but remain few in France, according to Gwen Jacobs, of the Energy Information Administration’s Country Energy Profiles Team. Smurfit Kappa does employ a similar system at a

mill location in Sweden, but like both Kuczynski and Kinni, Champarnaud is quick to point out the massive and uncommon size of the Facture plant. “This is a very big project we have in Facture,” he says. “Because it’s linked with a big mill, it is a project with the right return, and it is unique to have a paper mill with high conception of steam.” Dalkia, which invested about €130 million ($186 million) in the Facture application, is looking into

the development of several other projects in France, but all will be substantially smaller, at around 7.5 MW, Kuczynski says. “This project of Facture really is a huge [and unique] one,” he says. “So as project manager I sincerely had a great pleasure to lead this power plant construction.” Author: Lisa Gibson Associate Editor, Biomass Power &Thermal (701) 738-4952

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Energy Center A necessary upgrade to a centuries-old district heating system in Montpelier, Vt., represents an opportunity for a cleaner technology and an expanded distribution system. BY LISA GIBSON


ince the 1940s, Vermont has employed a steam plant to heat its capital complex in downtown Montpelier. Initially coal-fired, the facility was retrofitted for a 60-40 oil-biomass blend in the 1970s. Now, with necessary upgrades and improvements overdue, the next logical step seems to be a complete conversion to biomass feedstock. So after nearly two decades of discussion and planning, the city and state governments have formally partnered in the small capital city of 8,000 to replace the antiquated state-owned plant with a new, wood chip-fueled facility. In addition, the development plan includes an expansion of the distribution loop to include a number of city buildings, and eventually private commercial and residential structures. “We’ve had incremental support over the years, but we’ve understood that the state’s plant didn’t have enough capacity to serve the downtown,” says Montpelier City Manager Bill Fraser. “So here’s an opportunity for them to do their efficiency improvements and expand capacity.” And the impetus that finally got the wheels turning on the idea more quickly? Why, a hefty federal grant, of course. “It just really accelerated all our planning once we had a sense that, boy, this is going to be financially feasible,” says Gwendolyn Hallsmith, director of Montpelier’s Department of Planning and Community Development.


ÂŚPROJECT DEVELOPMENT Shooting Distance In January 2010, with major feasibility studies in progress, the project received an $8 million American Recovery and Reinvestment Act grant that propelled it into a new realm of possibility. “Even though it is very worthwhile and all the project feasibility studies have shown that it is worthwhile, it’s hard for a public entity to come up with the kind of capital you need to do it,â€? Hallsmith says. “And now with the subsidy from the federal government, we finally are within shooting distance of a project that’s economically feasible.â€?

The project cost is estimated to be between $18 million and $23 million, but will depend on design decisions that will be made as the plans are rolled out. Although deep into the approval process, the development plans have a ways to go before they are finalized at the city and state levels, including some lingering legislative and budget approvals. If all goes well, however, work on the expanded distribution system could begin this fall, with construction of the new plant after next year’s heating season and operation by 2013, according to Harold Garabedian, project management contractor from Montpelier-based firm Energy & Environmental Analytics.

Timeline and History of District Energy in Montpelier 1994 (approximately)—First District Energy Committee convenes.

2001—Feasibility study completed. Conclusion: Biomass district energy would reduce the biomass fuel costs of the state of Vermont from $4.1 per MMBtu to $3 to $3.5 per MMBtu. The mix of higher capital costs and lower fuel costs would balance out for the city and the downtown buildings, but their heating costs would be stabilized in a volatile fossil fuel market.

2003—City of Montpelier passes a $250,000 bond to pay for the pipes needed to connect the city hall complex with the state heat plant.

2004—Capitol complex thermal energy study completed. Conclusions: Current heating load exceeds plant capacity. Replacement or expansion of plant is overdue. Biomass is the preferred fuel source. Recommended strategies: • Install a new four-boiler (two oil, two wood) 1600-Bhp-system, as soon as feasible. The boilers should be selected to provide the maximum flexibility relative to potential conversion for future use for combined heat and power. Installing the boilers in the current boiler plant is the most cost-effective alternative. There are, however, considerations related to the boiler plant’s location in the flood plain and fuel deliveries as well as community concerns about river access, truck traffic and aesthetics that could impact site selection. • Use hot water distribution in any new building expansion. Over the next 15 years, systematically convert those buildings within the complex that still rely on steam distribution of heat within the building to hot water distribution. • By 2020, convert the steam and condensate mains in the distribution system to a hot water system. To the degree that it is viable and consistent with this timeline, collaborate with the city of Montpelier and National Life in the development of a citywide district energy system. This may include: • Bearing a proportional cost of the development of the distribution infrastructure needed for this system as it relates directly to the state's needs. • Assisting in the development of a collaborative partnership with the stakeholders defining and resolving governance issues of an expanded district heating system.




PROJECT DEVELOPMENT¦ The new biomass district heating plant will occupy the same space that the current plant does: smack dab in the middle of the downtown historic district and across the street from the state capital complex. The current steam distribution system heating the 17 capital complex buildings will remain operational, but a new hot water distribution loop will connect the new plant with the city’s buildings, including fire and police stations, on the opposite end of the relatively small downtown district. “If you’re building today, hot water is the way to go,” Garabedian says. “However, that state steam system is in place and it’s in good condition, so it’s not economically justifiable at this point to replace it.”

2007—City of Montpelier holds energy town meeting. District energy is identified as a high priority. Committee reconvenes.

January 2010—U.S. DOE ARRA grant awarded to the city of Montpelier to build a renewable district energy system.

2009—City hires Veolia Energy to conduct feasibility study. Early in the process, it recommends a partnership with the state of Vermont to make the plant economically viable.

Subsequently, the hot water distribution system will branch out and enable a number of commercial and residential structures in between the two government complexes to hook up to the new loop as well. Eventually, the system will produce up to 41 MMBtu of heat and Garabedian says the expectation is it will heat 1.8 million square feet of the community. It is also possible that the facility could produce a small amount of power, but that aspect of the design is still an open-ended question, Fraser says. Ownership structure plans for the project dictate that the state will own and operate the new plant as it has the old one, and the

June 2010—Capital bill passed with language directing the state of Vermont Commissioner of Buildings and General Services to sign a letter of intent with the city of Montpelier and fully explore the economics of the plant renovation.

March 2010—Veolia feasibility study complete. Conclusion: A district energy system for the state of Vermont and the city of Montpelier could be economically viable without private building owners. Flaws: The report oversizes the demand for the state of Vermont.

October 2010—Bids received for design build from Pizzagalli, DEW, and MacMillin.

November 2010—Carr & Copp economic study complete. Conclusions: $2 million net present value of accelerated replacement of heating plant.

November 2010—Vote to establish Clean Energy Assessment District and change city charter for district energy project passes by close to an 80 percent margin in Montpelier.

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¦PROJECT DEVELOPMENT city will own the new hot water distribution network that will loop through downtown.

Essential Alliance The partnership between the state of Vermont and the city of Montpelier is natural, as the two government bodies cross paths on a daily basis as a result of their close proximity in the small community. “We have an ongoing relationship with the state government,” Fraser says. “They are a

major presence in our town and we interact with them regularly.” That existing interaction, cooperation and trust is crucial to a partnership meant to facilitate such a project, Fraser emphasizes, adding that the city and the state Department of Buildings and General Services discussed the plans on numerous occasions before the pivotal grant was awarded. The city had approached the state with the proposition of applying for an ARRA


grant to push the project along, after years of mutual discussion and planning hit common road bumps including financing and logistics, Fraser recalls. “We thought, ‘This might be the time to finally do this distributed energy project we’ve been talking about for a long time,’” he says. “I think [the federal government] found the city-state partnership intriguing.” Garabedian touts the project as the first district heating endeavor in Vermont to marry state and city governments into one combined effort. “I think the partnership is essential,” Fraser says. The Biomass Energy Resource Center, a national organization, has also lent a helping hand in the development process. Needless to say, the new plant and distribution loop will bring a plethora of benefits to both city and state governmental agencies and the community of Montpelier. Besides the fact that the update will more than double the heat output and allow more advanced emission controls, it also will help reduce the number of oil-burning furnaces in the downtown district, offering a cleaner and local energy alternative. “We believe that will stabilize our fuel prices over time,” Fraser says. Garabedian agrees and sites analyses that show the price of oil fluctuates much more erratically than that of local woody biomass. In addition, the new system will mean less maintenance for connected structures and a savings of 10 to 20 percent on heating bills, Hallsmith says. That money also will go to the local economy instead of foreign oil producers. “It’s got all these elements people are looking for in projects,” Garabedian says. While biomass energy projects across the country have struggled with local opposition recently and Vermont is no exception, the Montpelier district heating plant has had tremendous support from the community. In fact, three citizen votes on the project all passed overwhelmingly, the most recent by 80 percent, Hallsmith says. “Every vote has passed by wide margins.” She attributes that support partially to the fact that the system is not entirely new, but a replacement to an existing one. The

PROJECT DEVELOPMENT¦ welcoming reception from citizens is good Montpelier’s long-awaited biomass district of how does a small community look to the news for the project because a city bond heating system. future and make its contribution to energy vote is required for final approval, Fraser “There are a lot of people who would independence, sustainability. If the project says. really like to see this happen,” he says, add- can move forward here successfully, I think ing that the community project is advancing it’ll be a great model for a lot of other comThe Model in a state that already employs a few univer- munities throughout the country.” In determining the best-suited tech- sity campus district heating systems. The Author: Lisa Gibson nology for its new district heating plant, time is right, in the midst of energy policy Associate Editor, Biomass Power & Thermal the partners flip-flopped between innova- struggles, to move up to community systems (701) 738-4952 tive processes and common, proven ones. and the project is a step in the right direcSuspension biomass-burning technologies tion, he adds. “[We’re] looking at it in terms were considered and almost chosen, but were bumped out of the plans by a simple combustion technology thought to be a better and more reliable fit for this particular project, Garabedian says. “[Suspension Maximize value from your raw materials. For perfect biomass and wood combustion] is a very intriguing technolproducts the entire production system must work together flawlessly. ogy, but we decided we probably aren’t the Buhler Inc. and Buhler Aeroglide enable total process control with a best people to try that,” he says. Suspension complete equipment package that includes drying, grinding, pelleting, combustion is used in Sweden, he explains, cooling, bagging and loading. This, combined with Buhler’s integrated but is usually paired with wood processing automation system, unrivaled after sale support and training provides a operations that generate large amounts of seamless solution to biomass and wood processors. wood dust. “A more proven, more mainstay technology probably serves what we’re doSee for yourself by visiting us at the International Biomass Conference & Expo, May 2-5, 2011. ing given our size and location,” Garabedian Buhler Booth: # 319. explains, adding that because Vermont is “off the beaten path” and not well-traveled, Buhler Inc., 13105 12th Ave N., Plymouth, MN 55441, 763-847-9900, concerns were raised about servicing a new Buhler Aeroglide, 100 Aeroglide Drive, Cary, NC 27511, 919-851-2000, technology. If the system is approved and developed, it will consume between 10,000 and 15,000 tons of wood chips per year, depending again on final design decisions. Oil boilers will also be in place as a backup. No agreements are in place for the biofuel feedstock at the new plant, but the existing blended feedstock plant does have some current contracts for its wood chips, Garabedian says. The developers envision bids and fuel contracts with third-party sustainability verification, and regular deliveries by truck about twice a day with up to five or six per day during peak heat use. The feedstock will be delivered already chipped and the facility will have the capacity to store up to five days worth to cover any delivery disruptions caused by wet weather or other factors. Fortunately, an infrastructure for a wood chip supply chain is quickly evolving in Vermont, Garabedian says, further confirming that the time is now to develop Innovations for a better world.



PICTURE PERFECT: Vermont's Middlebury College has cut its fuel oil use in half and is saving nearly $1 million a year, depending on the price of oil, with its biomass gasification system. PHOTO: MIDDLEBURY COLLEGE



District Energy on


Biomass district heating and cooling could save most college campuses lots of money and it fits well with green initiatives, but these projects require rigorous planning and up-front capital costs are high. BY ANNA AUSTIN




udgets are tight at most colleges and universities across North America and unfortunately, saving money long term often means spending money up-front, which is particularly true when it comes to energy system upgrades. On top of reducing energy costs, these upgrades—switching from fossil fuel heating/power to renewable energy—are perhaps the most obvious and significant ways universities can achieve long-term greening plans. Setting carbon reduction goals and increasing environmental friendliness has become a trend at educational intuitions. Despite high initial capital costs, some colleges are still managing to make these projects pencil out. For example, the University of Northern British Columbia recently completed the installation of a biomass gasification heating system that will displace up to 85 percent of the university's natural gas consumption, contributing to an energy cost savings of approximately $500,000 per year. Middlebury College in Middlebury, Vt., completed its biomass gasification

district heating system in 2009, and since then has cut its oil use in half, saving the college about $1 million per year. UNBC was fortunate to receive a substantial amount of financial help from the government, but since most projects won’t have that luxury, all grants, financial assistance and outside partnership avenues should be explored. Kamalesh Doshi, senior program director at the Biomass Energy Resource Center, says that the average-sized 20 million Btu-per-hour campus district heating system costs about $25 million, including the system itself and installation costs, and that’s cash most colleges don’t have on hand to spend. When approaching a project, debating whether a biomass heating system will work isn’t the right initial question to ask, according to Doshi. Rather, it’s what setup is best for each campus.

Exploring Options “There is rarely a case where a biomass heating system doesn’t make sense on a campus,” he says. “Rather than just

saying whether it will work or not, the university has to choose the option that is best for them.” One of the first things to determine is where the biomass generator could be located. A large building or land area that is in a centralized location is the most ideal scenario. “Each campus will be very specific in its layout, so buildings will vary,” Doshi says. “The larger the building, the farther the pipelines can go. If it’s a smaller building, then the cost of the pipeline becomes prohibitive.” The cost of laying pipe is different for each project, and a big influence on that cost is the condition of the soil and whether it is soft or hard. “With soft soil, piping can be installed for longer distances at a lower cost,” Doshi says. Once the space for the biomass boiler is determined, another important factor is whether the school already has a steam or hot water distribution system. Hot water is definitely better, according to Doshi. “In fact, in a lot of cases, it makes sense to remove the steam distribution system

INNOVATIONÂŚ and replace it with a hot water distribution system because it is much more efficient, with lower maintenance and operating costs.â&#x20AC;? There are projects where a steam distribution system will make sense such as at Middlebury College, which has a boiler that is also capable of running on oil when needed. Typically, a university will spend the minimum for redesign of a hot water system. In some cases, the campus may not even have a centralized heating system to begin with, as some have separate, unconnected systems in each building. Perhaps the most important consideration when installing biomass district heat is the availability of the fuel or biomass source, Doshi says. â&#x20AC;&#x153;First they need to look at the vicinity where they could possibly get it from. Normally, we recommend a radius within about 50 miles; the lower it is the better.â&#x20AC;? Another issue that should be considered is the quality of the available biomass. â&#x20AC;&#x153;The boiler system and design will

depend on that quality,â&#x20AC;? Doshi says. â&#x20AC;&#x153;This is the opposite of other fuel sourcesâ&#x20AC;&#x201D;if someone buys an oil boiler, they can purchase it and then look for the oil dealer. With biomass, that process is in reverse; first they determine where theyâ&#x20AC;&#x2122;ll get it and how, because that influences many other things, including the type of storage system and how much it can hold.â&#x20AC;? The biggest challenge in implementing biomass district heat on campus is most often capital costs, Doshi says. Financing options vary, but a number of projects have opted to engage in energy service contracts. â&#x20AC;&#x153;This is where a private developer puts in the investment, and sells heat to the university,â&#x20AC;? Doshi says. â&#x20AC;&#x153;They buy the Btus, just paying for what they consume.â&#x20AC;? Some colleges have already set-aside funding for green initiatives, others utilize reserve funds, donations or other internal sources of funding, or borrow the money. Although the typical return on investment for an average-sized system is about eight to 10 years, savings begin right away.

Ideas to Reality Middlebury College finished the installation of its biomass gasification district heating system in 2009. Four boilers generate high-pressure steam that is sent through turbines before it leaves the central plant, producing 20 percent of the campusâ&#x20AC;&#x2122;s electricity. Then, itâ&#x20AC;&#x2122;s sent around campus as lowpressure steam to provide heat, or is run through chillers in the summer for cooling. â&#x20AC;&#x153;When we built the biomass system, we built onto our existing central system, adding another segment to the building where we put in the biomass gasifier, boiler and related equipment, and connected it into the steam system,â&#x20AC;? says Jack Byrne, director of Middleburyâ&#x20AC;&#x2122;s Sustainability Integration Office. The system runs on biomass as its baseload fuel, and if more steam is needed, oil can be used, as that was what it originally ran on. â&#x20AC;&#x153;Weâ&#x20AC;&#x2122;re at a point now where we have cut our use of fuel oil in half, from 2 million to 1 million gallons a year,â&#x20AC;? Byrne says. â&#x20AC;&#x153;Thatâ&#x20AC;&#x2122;s saving us, depending on the price of oil, just under $1 million per year.â&#x20AC;?


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FEEDING THE MACHINE: Middlebury College's district energy system runs on byproducts from milling and forest management practices.

Utilizing biomass also provides a considerable economic benefit for the region, as the college sources woody biomass within 75 miles of campus. “We’re spending somewhere around $800,000 per year, which is going to loggers, truckers, millers and foresters,” he says. “The most important thing to look hard at is whether there is a reliable supply of wood and how it’s being produced. We source 20 percent as byproducts from milling, and the remainder from forest management practices.” Byrne says the two biggest challenges they faced when developing the district energy project were siting and maintaining a fuel supply. “We decided to add on to our existing plant because a high-pressure steam line like we have costs about $1,000 a foot,” he says. “We built onto the existing steam system, and connected into it. Also, we would have had to build a new smokestack, which could have raised issues if it were in an area where people didn’t want that in their neighborhood.” Adding onto the existing system came with its own set of challenges—one of which was storage for wood chips. “We didn’t have much room for them, not even

for a 10-day supply, so we had to make sure we could get the chips when we needed them,” Byrne says. The college’s solution was to hire a broker to ensure a steady supply of fuel, and stockpile a 20-day supply, in the form of round wood, about 15 miles from the site. The college borrowed money to finance the $12 million project, Byrne says. “When we did the financial modeling, the most important variables were the price of wood and oil, so we were very conservative projecting out over the future.” At that time, the financial modeling showed a 12-year payback on the 25-year life of the plant. “If you took the price of oil and wood today, we’d be looking at something like an eight-year payback,” he says. Once the plant was built, there was a year-long learning curve to understand how to make it run optimally. “We’ve got it running really well now, even better than the manufacturer’s specs in terms of the steam we can produce,” Byrne says. “It took that long to really figure out how to dial it in.”


ENERGY CONNECTIONS: District energy made sense for UNBC's Prince George campus because the infrastructure for heating and cooling was already in place. SOURCE: UNBC

UNBC is working on doing just that, with the recent completion of its own biomass gasification district heating system.

Setting an Example UNBC’s Prince George campus opened in 1994, and has utilized natural gas as a fuel until now. Biomass district heat made sense for several reasons, the most obvious being the infrastructure for heating and cooling that was already in place—buildings already connected to a power plant (see diagram). Also, federal policy in Canada favors biomass projects. “B.C. has implemented both a carbon tax and a $25 per metric ton greenhouse gas emission fee,” says Robert Van Adrichem, UNBC’s vice president of external relations. “In other words, we pay at the pump and at the stack, so this provided some incentive. Even more important, this region is the largest wood products producer in the country, and though we’ve been huge in supply we often don’t showcase the use of these products ourselves; we’re an export-oriented region.” Sawmill residue from Lakeland Mills of Prince George is delivered to the plant’s fuel storage area, which can hold up to 60 metric tons of material. In a typical year, the UNBC plant will consume about 6,000 dry metric tons of fuel, equivalent

to about one or two truckloads each day. When UNCB made the decision to go green, it issued a request for expressions of interest from companies that wanted to work with the college. It was bioenergy companies that responded, and Nexterra Corp. ended up being the supplier of the system, which will save the school from $600,000 to $800,000 per year in fuel costs. Perhaps because the project is the first of its kind in Canada, the entire $15.2 million capital cost of constructing the 15 MMBtu per hour bioenergy plant has been covered by the provincial and federal governments through various grant programs. The university is seeking additional funds through donations from private and public sources to develop the research opportunity more fully and attract students and faculty through new scholarships and grants, according to Van Adrichem. “It’s a competitive marketplace for universities, and we felt this might be something that would help to position UNBC and distinguish us.” Author: Anna Austin Associate Editor, Biomass Power & Thermal (701) 738-4968





CHP: Cutting

It at Sawmills A cogeneration plant can make a world of difference when paired with a struggling saw mill, but several things must be in place for a project to pan out economically. BY ANNA AUSTIN


hen Aaron Jones founded Seneca Sawmill Co. in 1953, he was prepared to lead the company through the good times and the bad. Although he is no longer involved in the daily operations of the company, over the past half century Jones inspired his employees to continue to persevere during challenging times. And they have, even during the worst slump the U.S. housing market has ever experienced. In fact, Eugene, Ore.-based Seneca has faced the trying economy head on, with the recent completion of a $90 million cogeneration (combined-heat-andpower) plant, without the help of any state or federal grants. “The way that [Jones] has run his business, and what he has always taught people like me, is to be prepared for the worst case scenario,” says Rick Re, general manager and senior vice president of the company. “We’ve been able to get through this downturn because we were always prepared for the worst.”


Having gone into full operations in midMarch, Re says he’s glad that Seneca began the cogeneration project when it did, which was in 2008 with the permitting process; construction began in 2009. “It’s a challenging environment right now,” he says. Well-financed with a large asset base, Seneca owns three sawmills all located on the same site, as well as 150,000 acres of timberland. Though the company had been evaluating cogeneration for roughly the past 12 years, it never seemed to quite pencil out, says Re, who has been working for Seneca since 1973. That is, until demand for kiln-dried wood significantly increased. “We manufacture green lumber, and we have a couple of dry kilns, so we got into drying a small portion of our volume,” Re says. “Over the period of a decade, the marketplace shifted more toward dry lumber, and we recognized we would have to start doing more of that.” Seneca had been running its dry kilns with natural gas, but realized that it was no longer the best option with increased dry-



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COGENERATION CONSTRUCTION: The Seneca Sawmill recently completed construction of a $90 million cogeneration plant to reduce its fuel costs.

ing activity. “Then we started looking at a biomass boiler,” Re says. “Because of fuel costs, there was some value in that.” Perhaps the most beneficial aspect of building a cogeneration plant at the site of Seneca’s sawmills is the fact that the company is able to supply the plant with all of its fuel demands, which is sometimes the case with similar projects. That’s actually how Seneca gauged the size of the plant—by how much fuel the company could supply using just in-house materials. “That was one of the big issues when we began looking at the project,” Re says. “We wanted to build based on the resources that we control from our own holdings—timberland slash and byproducts of manufacturing. We figured out that we could justify a plant that would produce 20 megawatts (MW).” That equates to about 130,000 bonedry tons of wood fuel a year. Some CHP projects have difficulty producing power for the grid because they are remotely located or they can’t get a suf-

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¦COGENERATION ficient price for their power. In Seneca’s case, it was largely a matter of luck. “Fortunately, we have two different BPA [Bonneville Power Administration] lines right next to us as well as two local utilities, so we had access,” Re says. In some states such as Montana, these issues have kept sawmills from implementing cogeneration projects. Two years ago, the Montana Department of Commerce provided funding for feasibility studies to look at cogeneration at seven saw mills within the state, to determine what the obstacles are and how they could be overcome.

Determining Feasibility Craig Rawlings of the Montana Community Development Corp., a leader in the project, says the final feasibility report found that cogeneration plants are doable for the seven mills, a prototypical plant being sized at about 18.8 MW and costing $55 million.

As a result of the study’s findings, all of the plants are working on developing cogeneration plants but at different paces, he says. “Some are trying to get power purchase agreements in place, and some are working on energy audits so they can be competitive for the Rural Energy for American Program low-interest loans and grants.” Some have also applied for the U.S. Forest Service’s woody biomass grant program. Though a total cost of $55 million per plant is a large financial investment according to Montana standards, with the help of these numerous state and federal programs, the MCDC report finds that the daunting task of financing is possible with the right financial packaging expertise. “Also from a financing perspective, although they can burn their mill residues—they already have the intent to do that—they can also use the mill byproducts as collateral when they go to a financing institution,” Rawlings says.


If the sawmill can run a cogeneration plant on its own fuel alone, like Seneca does, that will also result in significant cost savings. In western Montana, for every $1 increase in the average daily cost to deliver one bone-dry ton of fuel to a mill site, the required power sale price increases by about 88 cents. “For a stand-alone power plant, you’ve got to go outside and bring all of your material in, whereas these mills already have a stream of byproducts that they could use if they need to,” Rawlings says. “They need to be motivated to go outside of that. In Montana, we’ve got some real forest health issues with the beetle-killed pine.” Out of the seven Montana mills, four are actively pursuing the projects. “There is still a challenge with energy prices being so low in the Midwest, and they’re predicted to stay relatively low,” Rawlings says. A financial analysis revealed that a cogeneration plant in Montana would have to sell power at a rate of $88 per megawatt hour (MWh) to provide the owner a 12 percent return on investment (ROI). That amount could be as low as $78 per MWh, however, and still achieve the same ROI, if the project can take advantage of available financing and grant programs in a given location. While that cost is higher than other available sources of power in the state, the development of a network of CHP plants at sawmills may provide a number of social, environmental and electric system benefits that would justify the higher cost. Also, if a plant in a state with low power prices is located near the border of a state with higher power prices, selling the power across the border may be an option, which is the case for Iberdrola Renewables and Collins Co.’s cogeneration plant, Lakeview Cogeneration LLC, under construction at its Lake County, Ore., sawmill. Just 15 miles from the California border, that state is the logical market for power produced at the plant because of the significant difference in power prices. “Right now you can buy industrial power in Oregon for about 4.5 cents per kilowatt, and the same in California goes for about 11.5 cents,” says Wade Mosby, senior vice president of Collins Co. “It costs about 8.5 cents to operate a cogeneration plant, so you’re probably not going to sell it in Oregon.”

COGENERATION¦ Partnering Up For Collins, a project partner was a must. The company teamed up with renewable energy giant Iberdrola for a number of reasons, including financials. “The problem with cogeneration is that the prices are astronomical,” Mosby says. “Lakeview is a $90 million investment and we’ve had several tough years. We’re a profitable company, but we don’t have that kind of cash lying around.” The sawmill business has been tough especially with the depressed housing market. “It’s all tied to the housing market,” he says. The 26.8-MW cogeneration plant currently under construction will change the landscape a bit for the Fremont sawmill. It will use mill byproducts to generate all the steam for the mill as well as power for the grid, and Collins is responsible for supplying the plant with its fuel needs. Overall, the project is expected to have many positive economic impacts on the county, which has seen four sawmill closures in the past couple of decades. Utilizing wood resources in western Oregon has been a complicated and contentious issue over the past 15 years, Mosby says. Beginning in the early 1990s, the government put strict harvest regulations on federal forestland, which constitutes about 78 percent of the forestland in Lake County, and they are still in effect today, according to Mosby. “The environmental community has made it pretty tough to harvest any timber,” he says. Then it became apparent that there was a need for forest health management in the region. “We’ve had some huge fires,” Mosby says. “In 2001, we had a 100,000-acre fire and people started to realize we had a huge problem. If we didn’t ever harvest timber, we were going to perpetually have these fires coming through, generally started by lightening.” The solution was to build a sawmill in a remote location in Lake County, which is where Collins entered the picture. Not owning quite enough forestland in the region, Collins was able to work out a 10-year forest stewardship agreement with the government, with a 20-year memorandum of understand-

ing. “They guaranteed us 5,000 acres, and we decided to build a mill there, which opened at the end of 2007,” Mosby says. Realizing that there would be a substantial amount of biomass resulting from the mill’s operations, regional stakeholders decided that a nearby cogeneration plant seemed to make sense. After the project changed hands a few times, Iberdrola took it over and moved forward. “We’ll shut down our boiler when it’s complete in 2012,” Mosby says. Financially, what has made the large project investment attractive is the federal 1603 Program investment tax credit. “A $90 million facility with a 30 percent grant, they [Iberdrola] will get $27 million back, and up to $10 million back under a state plan,” Mosby says. “Those kinds of incentives make it attractive to bigger players.” Mosby advises sawmills considering similar projects to be patient, as a good project takes considerable time to develop. “The

whole idea of our cogeneration project was formed in 2004, and it won’t be operational until 2012,” he says. Because it has been in the cogeneration business since 1985, operating a 12-MW plant at its sawmill in western California, Collins has a good understanding of it. ”You need fuel, financing and a PPA (power purchase agreement) that makes sense,” Mosby says. “A lot of communities are interested in this type of a project, but realistically the stars have to align.” Choose a project partner with knowhow and access to capital, he says. “A lot of developers have big ideas, but they don’t have very deep pockets.” Author: Anna Austin Associate Editor, Biomass Power & Thermal (701) 738-4968

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DIGESTING IT ALL: The United Ethanol plant in Milton, Wis., is installing an anaerobic digester to reduce the plants carbon footprint and increase ethanol production. PHOTO: UNITED ETHANOL



Ethanol Producers Embrace

Biomass Power Thermal and

With an eye toward both energy costs and environmental concerns, ethanol producers are embarking on innovative energy projects. BY HOLLY JESSEN


lthough natural gas is king of power generation at ethanol plants, there’s increasing interest in renewable energy technologies that could help ethanol plants someday produce a domestically grown fuel without using fossil fuels. A handful ethanol plants, for example, are working to reduce fossil fuel use through innovation. Whether producing power from a biomass boiler, gasifier or anaerobic digester, or installing heat exchangers to utilize waste heat, it’s all about reducing the amount of natural gas used per gallon of ethanol produced. Second only to feedstock costs, energy costs can have a major impact on an ethanol plant’s bottom line. In 2010, energy expenses made up 9 percent of the total costs at an ethanol plant, including electricity, according to Christianson & Associates in its Biofuels Benchmarking Annual Report. Energy can also be a volatile expense for ethanol producers. In 2009-’10, the industry average cost for energy ranged from 15 to 21 cents per gallon of ethanol produced, according to Christianson & Associates. Energy prices were an even bigger piece of the pie in 2008, when natural gas prices dramatically shot up. According to U.S. Energy Information Administration records, commercial natural gas prices hit $11.99 per million Btu (MMBtu) in 2008, before dropping

to $9.66 per MMBtu in 2009 and $9.04 per MMBtu last year. Natural gas prices aren’t likely to get anywhere near the highs of 2008 for decades, according to the EIA. The agency predicts a slight increase in prices this year followed by a slow but fairly steady decline until 2014. After that, natural gas prices are expected to slowly climb, hitting the $10 mark in 2027 and reaching $11.10 per MMBtu by 2035. Several ethanol producers are skeptical, however. The CEO of North West Bio-Energy Ltd. in Unity, Saskatchewan, is preparing for higherthan-expected prices. “Our impression of the world is that, over time, natural gas prices will go up, the way all energy prices are going up,” says Jason Skinner. Vincent Copa, a process engineer at Minnesota’s Chippewa Valley Ethanol Co. LLLP, also thinks it’s possible that natural gas prices could climb higher than predicted. Since natural gas is a relatively inexpensive fuel today, it’s likely to be tapped by more and more users in the future. That demand would push the price up. Then there are the environmental motivations for pursuing alternative forms of energy for process heat at an ethanol plant. In the future, plants that install advanced technologies may have an edge, depending on the direction the U.S. goes with its energy policies. Unit-


ed Ethanol LLC in Milton, Wis., has its eye on the possibility that the U.S. EPA could someday qualify its fuel as an advanced biofuel because the corn-to-ethanol plant installed new, more efficient technologies and reduced its greenhouse gas emissions, says Alan Jentz, vice president of grain operations and risk management. More near term, some ethanol producers are looking to California, where low-carbon ethanol could command a premium price. That state is moving toward sustainability requirements that would push for advanced technologies, such as biomass power generation, and where California goes, other states are likely to follow, Copa says. On the other hand, if there aren’t economic reasons for transitioning an ethanol plant to more environmentally friendly technologies, ethanol producers won’t be able to do it simply because it’s green. An ethanol plant is a business and, more than the color green, its owners are concerned more with the black and red on financial reports. “Our shareholders care about the bottom line and if being green is not going to pay, we can’t afford to make that kind of a [public relations] move,” Copa says.



BIOMASS GAS: CVEC in Benson, Minn., completed construction on its gasifier in 2008, when natural gas prices were high.

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EFFICIENCY¦ Power in Chaff North West Bio-Energy, a 25 MMly (6.6 MMgy) ethanol plant, is well-situated for feedstock delivery. It is co-located with the company’s grain terminal, which handles about 425,000 metric tons of commodities annually—including the feed wheat it uses to make ethanol. Another co-location perk is a ready feedstock for the ethanol plant’s newly installed biomass boiler. Chaff, previously a problem for the grain terminal, will be burned to replace some or all of its natural gas use, depending on prices. The company spent $1.5 million, without the aid of grants or other assistance, to install a firebox unit with a reciprocating grate to burn biomass for power generation, Skinner says. With natural gas prices relatively low right now, the company isn’t in a big rush to get the project wrapped up, he says. The boiler installation took place over about two years and likely won’t be ready for full use until sometime this summer. “We’re setting this system up so, if we see times when natural gas prices go up quite a bit, then we would be able to use biomass as an alternative fuel,” he says.

In late March, North West Bio-Energy was paying about $3.50 per gigajoule (GJ) for natural gas—but the company has seen prices as high as $12 per GJ in the past. The cost of chaff is estimated at $2.50 per GJ, which could mean some real savings for the plant if natural gas prices increase, something the company fully expects to happen. “The neat part about the biomass that’s available in our part of the world is that the price tends not to go up to the same extent—so it’s a more stable cost,” he says. In Canada, grain is cleaned before it is exported. The company pays the farmer for the grain, with the weight of the dockage—weed seeds, broken kernels and chaff—deducted, although not always. “Currently, we pay the farmer $10 per metric ton for the dockage because we are able to sell things like broken seeds to offset this cost,” he says. “We use the payment for dockage as a competitive tool to buy grain.” Unlike broken seeds, chaff has little to no value today. A nearby feed mill sometimes buys the chaff, but in the summer months there’s no market at all. In addition, it’s so light it’s difficult to transport. “It’s a problem

getting rid of the material,” Skinner says. The solution is the biomass boiler. The company will actually start encouraging farmers to leave more dockage in their grain by increasing payments, he says. The dust and chaff collected from wheat, barley, canola and peas can then be used as a fuel to offset natural gas use. This is going to require a mindset change for farmers, who don’t want to pay freight to have it hauled to the grain terminal, for one. “As a rule, farmers have grown up wanting the least amount of chaff in the grain, so they try to keep it very clean,” he says. “But we’re trying to do the opposite thing.” If natural gas prices go up, however, burning chaff in the biomass boiler won’t just save the ethanol plant money. “We’re a shareholder-owned company so a lot of the farmers in our region own our company,” he says. “Being able to buy their chaff or their dockage from them when they bring it to the elevator would give them another revenue stream coming off their land.” The company estimates that if farmers leave between 5 and 7 percent dockage in their grain, it would provide enough chaff to power the ethanol plant all year. In that scenario the company would

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More Innovators Other ethanol producers are working to reduce their consumption of fossil fuels. Some notable projects include: • Didion Ethanol LLC, a 50 MMgy plant in Courtland, Wis., received $5.5 million in U.S. DOE funding to cut back its energy use. The $11 million project, which kicked off in 2010, has the goal of reducing energy use by 25 percent while producing 5 percent more ethanol from the same amount of corn. • Lincolnway Energy LLC was awarded $1.9 million in USDA funding in 2010 to help the company modify a coal-fired boiler to burn biomass. The 50 MMgy ethanol plant in Nevada, Iowa, qualified for the funding through the USDA's Repowering Assistance Program, set up by the 2008 Farm Bill to encourage the use of biomass as a replacement fuel source for fossil fuels.

• Archer Daniels Midland Co. completed construction in 2010 at two dry-mill ethanol plants in Columbus, Neb., and Cedar Rapids, Iowa. Both plants are co-located with existing wet mill ethanol plants as well as new cogeneration facilities that use steam to power turbines to generate electricity and reduce energy costs. The power facility supplements the existing gas-fired boiler, says Beth Chandler, company spokesperson. It burns low-sulfur, high-moisture coal and up to 20 percent biomass. "The coal-fired cogeneration facility provides a cost advantage when natural gas prices are significantly higher," Chandler says. • Poet LLC is one of 25 ethanol producers that submitted information to the California Air Resources Board in an effort to reduce the carbon intensity rating of its fuel. One of the modified pathways it presented was utilization of waste heat from electrical generation. Another pathway

utilized more than 26 percent energy from landfill gas, waste wood, field waste and thin stillage, with the remainder coming from electricity and natural gas. The highest percentage of alternative power came from a pathway in which the primary process fuel was 88 percent biogas. • Corn Plus LLLP, a 49 MMgy ethanol plant located near Winnebago, Minn., was recognized last spring as an Energy Champion by the DOE. To qualify, Corn Plus achieved more than 250,000 Btu, or more than 15 percent, energy savings. The ethanol plant can burn its distillers dried grains syrup in its first-of-its-kind, fluidized bed system, and in 2011 the company will receive about $12 million through the federal Alternative Fuel Mixture Tax Credit. In addition, the company installed two wind turbines in 2007, which can generate up to 30 percent of the plant’s electrical needs.

increase its dockage payments to $50 a metric ton. “That’s a real win-win for us and our shareholder farmer customers,” he says. The plant will have the flexibility to switch between biomass and natural gas, depending on availability and price. Over time, Skinner believes the biomass boiler will pay for itself. And, although Canada is further behind than the U.S. on the push to make ethanol plants more environmentally friendly, he believes the project will also benefit the plant in that arena.

It’s a Gas Although the gasifier at CVEC hasn’t operated for about a year, that doesn’t mean the Benson, Minn., ethanol plant has abandoned the project. In fact, the company is hard at work obtaining Minnesota Pollution Control Agency permits for additional types of biomass to use in the gasifier, should natural gas prices go up and it becomes economical again, Copa says. CVEC’s gasifier was completed in the spring of 2008, in the midst of the high natural gas prices that prompted the project. It can provide 90 percent of the ethanol plant’s power needs by burning primarily waste wood chips and corncobs. A gasifier thermally breaks 64 BIOMASS POWER & THERMAL | MAY 2011

down dry biomass at the molecular level in temperatures greater than 1,500 degrees, producing carbon monoxide and hydrogen, Copa explains. An air-blown system, like the one at CVEC, produces gas containing 150 Btu per cubic foot (cu ft) because the gas is diluted with nitrogen from the air. In comparison, an oxygen-blown system produces gas with about 600 Btu per cu ft. Pipeline-quality natural gas has an energy content of 1,000 Btu per cu ft. In an aerobic digester, bacteria breaks down wet biomass emitting methane (natural gas), CO2 and water, and has an energy content of 600 Btu per cu ft. CVEC’s gasifier can use a variety of feedstocks, such as sunflower hulls, as experimental feedstocks, as long as they are used in limited quantities for short periods of time, he said. The company received permit approval for wood chips for normal production use in its gasifier when it was constructed, and is now working through the permitting process to use corncobs and glycerin from biodiesel production. As part of the permitting process, the company has conducted emissions testing for wood chips and corncobs. Both feedstocks have acceptable emissions characteristics, much lower than the emissions from coal and similar to or lower than natural gas emissions. Carbon monoxide or other volatile organic compound emissions are slightly lower, and dioxins, furans and mercury—the sort of emissions that really scare pollution control agencies—are virtually nondetectable. On the other hand, as expected, levels of nitrogen oxides (NOx) were slightly higher than NOx emissions from natural gas. In the future, Copa hopes the MPCA won’t require emissions testing for each new type of biomass. “We were able to show that the expected emissions characteristics are about the same for each biomass that we tested,” he says. “Hopefully, after we test a couple more types of biomass they’ll get the hint.” Carbon is a big buzz word right now. CVEC’s gasifier participates in the carbon cycle by combusting carbon that living plants pulled from the air, unlike natural gas. “That carbon has been sequestered in the ground for millions of years, so burning it is adding a net addition to what’s already in the atmosphere,” Copa says.



WASTE TO POWER: An anaerobic digester will utilize thin stillage for power generation at United Ethanol, which is expected to go on line by year's end.


¦EFFICIENCY As much as CVEC is convinced that the gasifier is environmentally the right decision, the company won’t run it again unless natural gas prices go up enough to make it economical. At current prices, CVEC could find reliable supplies of biomass at about $6.50 per MMBtu, or $60 to $65 a ton. With natural gas prices today, biomass would be competitive at about $5 MMBtu, but just barely, he says. At that rate, the company would have to watch its biomass prices carefully to make even a tiny dent in the payoff of the investment.

These barriers won’t completely stop CVEC from working on projects such as the gasifier, however. The company, which is also known for producing alcohol that goes into Shakers Vodka and industrial uses, is always working on innovative things, Copa says. In the past there have been complaints that some side projects were more effort than they were worth for the small amount of income they brought the company. However, it was those projects that brought CVEC through difficult financial times in 2008, when other ethanol plants didn’t make it, he adds.


Good Digestion At United Ethanol, installing an anaerobic digester is about reducing the plant’s carbon footprint while, at the same time, increasing ethanol production through increased efficiency. “It’s a way to extract more value out of our inputs, the corn, and make the plant greener and more energy efficient,” says Dave Cramer, president and CEO of United Ethanol. The 50 MMgy year ethanol plant planned to break ground on the $6.75 million project in April and hopes to have it completed by the end of this year, Jentz says. To assist in installing the digester, the company received a $2.25 million low-interest loan from Wisconsin’s Energy Program, which is funded through the American Recovery and Reinvestment Act of 2009. The air permit for the project was approved in early March. United Ethanol is working with Eisenmann Corp., which will install its Biogas-TS system at the plant. It will utilize a portion of the plant’s thin stillage to create methane in the digester and ultimately reduce the plant’s natural gas use by up to 25 percent, Jentz says. Current estimates show the project should have about a four-year payback. The major elements of the system include three 1 million-gallon digesters and a biogas-fired boiler to augment the two existing natural gas-fired boilers, says Howard Hohl, sales manager for Eisenmann. Using the thin stillage for power generation will have several efficiency perks for United Ethanol. Primarily, it will reduce the amount of nonfermentables produced at the plant, help cut back on evaporator bottlenecks and alleviate water balance issues. Thin stillage contains fine solids, proteins and other organic materials that are digestible, Hohl says, but not fermentable. By using it for power generation, the overall organic load of the plant’s backset will be reduced by 95 percent. Reducing nonfermentables will, in turn, reduce the load on the driers, which means reduced energy requirements for producing dried distillers grains, Jentz adds. United Ethanol also recently added corn-oil extraction at the plant, another technology that helps reduce energy use. Some anaerobic digesters utilize thick stillage or syrup, which contains from 32 to 35 percent solids, Hohl adds. Thin stillage, which

EFFICIENCYÂŚ United Ethanol will use, contains only about 10 percent solids. â&#x20AC;&#x153;Either one of those methods could work,â&#x20AC;? he says. â&#x20AC;&#x153;We will potentially augment the digester with syrup to maintain our solids at a certain level, to ensure that we get the right amount of biogas generation.â&#x20AC;? Using thick stillage or syrup for biogas production results in additional coproducts and waste streams. The solids, or sludge, produced must be disposed of, recycled or sold into the fertilizer market. Biogas production from thin stillage, however, results in a closed-loop system with no blowdown or loss of solids. â&#x20AC;&#x153;It all goes back to the plant,â&#x20AC;? Hohl says. Eisenmann can guarantee two things about the anaerobic digester: First, it will reduce natural gas use and the plantâ&#x20AC;&#x2122;s carbon footprint. Second, the company expects the ethanol plant will see a 2 to 2.5 percent increase in ethanol production, because the system will reduce recycling of nonfermentable solids. There are likely to be other benefits to the system as well, but since this will be the first full-scale installation of an anaerobic digester for Eisenmann, the company isnâ&#x20AC;&#x2122;t revealing details yet. â&#x20AC;&#x153;There are a number of other soft benefits that we expect United will gain with this installation and weâ&#x20AC;&#x2122;ll share those with you as the project progresses,â&#x20AC;? Hohl says.

An RTO is a pollution control device that cleans the emissions from grain drying by heating it up from about 300 to 1,650 degrees, Kemmet explains. Although most of that heat is reused in the system, the RTO still exhausts vapor at 350 degrees. Installing heat exchangers will capture that heat. â&#x20AC;&#x153;Thereâ&#x20AC;&#x2122;s a lot of hot, moist air, so weâ&#x20AC;&#x2122;re going to cool that hot, moist air from 350 degrees down to about 220 degrees,â&#x20AC;? he says. The reclaimed heat will be used for process heat, reducing the amount of natural gas needed to power the plant. Ace estimates the $1 million heat exchange project

will reduce its natural gas use by 3.5 percent. â&#x20AC;&#x153;Even with the reduced natural gas cost, the project is still expected to have a payback that is right about three years,â&#x20AC;? he says. CVEC is still adding up the total cost of its project, Copa says, but he calls it a multimillion dollar project with an acceptable payback of two to three years. Author:Holly Jessen Associate Editor, Ethanol Producer Magazine (701) 738-4946

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Safety Solutions Tailored to Biogas Plants While the complexity of biogas plants tends to be underestimated, operators have sole responsibility for ensuring the safety and health of employees and the general public. What options and aspects must operators and investors take into account when planning, constructing and operating biogas facilities to ensure safe, environmental compatible and profitable energy generation? BY JOHANNES STEIGLECHNER AND VOLKER SCHULZ


In late 2009, a study carried out by the Commission for Plant Safety of the German Federal Environment Ministry revealed critical defects in more than 60 percent of biogas facilities inspected. The study inspectors, which also included TÜV SÜD experts, detected weaknesses not only in the gas and ventilation systems, and regarding explosion protection, but also in component design, structural engineering and organizational measures. This result confirms that stakeholders in practice still tend to underestimate the scope of required safety measures. Ensuring the safe operation of biogas facilities requires consideration of questions related to the gas, the electrical and the pressure systems. Other significant issues are related to fire safety and lightning protection, and to the layout and planning of

escape routes and emergency response plans. Potential hazards to health and the environment also need to be limited.

Responsibility Rests with the Operator Biogas plants process large quantities of combustible and toxic gases which pose increased fire, explosion or suffocation hazards in case of faults in design, materials or control. In the event of an incident at the plant, people may be injured, property damaged and the environment (air and water) polluted. In this context, the operators of biogas plants have a high level of responsibility: Their duties include conducting the necessary inspections, ensuring safety and health documentation of sufficient explosion protection and expert training of employees. Operators violat-

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ing these duties risk that the operation of their plants is no longer in compliance with the law, which may result in a shutdown of the plant and in restriction or even loss of insurance coverage.

Targeted Safety Assessment Generally, agricultural biogas plants comprise a reception pit for collecting and preparing the slurry, a fermenter in which the biogas is produced, a final digestate storage tank and a combined-heat-and-power (CHP) unit in which the biogas is converted into electricity. Biogas consists of methane (50 to 80 percent), carbon dioxide (20 to 50 percent), hydrogen sulphide (0.01 to 0.4 percent) and traces of ammonia, hydrogen, nitrogen and carbon monoxide. The constituents of ammonium and hydrogen sulphide are two aggressive chemicals that are constantly in contact with

SAFETY¦ the tank walls, pipes and valves. Given this, the materials used for these components need to be highly resistant to chemicals and maintain this resistance over long periods. The lower explosion limit (LEL) of methane is 4.4 percent, the upper explosion limit 16.5 percent. In combination with the oxygen in the air, methane concentration in this range can produce an explosive gas mixture. These explosions can cause severe ecological damage, serious injuries to people and damage to property. To ensure effective explosion protection, the gas sensors in the plant should be adjusted to 20 percent of the LEL, equivalent to methane concentration of 0.88 percent. Carbon dioxide causes dizziness in concentrations between 1 and 5 percent, and rapidly leads to suffocation in concentrations of over 9 percent. People should not be exposed to concentrations higher than 30 to 100 parts per million. Hydrogen sulphide is particularly hazardous. It is perceived as disagreeable at a concentration of 50 milligrams per cubic meter (mg/m3). Concentrations of 150 mg/m3 cause irritation of mucous membranes. And at levels over 500 mg/m3, hydrogen sulphide causes olfactory paralysis and is fatal within minutes. Apart from suffocation, fire and explosion hazards, leakage of fermentation substrates into water as a result of an incident in a biogas plant may cause severe environmental pollution. In view of the fact that the composition of liquid substrates is hard to control, operators face the challenge of having to dispose of the liquid digestate cost-effectively while also ensuring groundwater protection. As the digestate contains large quantities of water, transportation over long distances does not make good economic sense. Instead, local disposal should be given preference wherever possible.

Individual Assessment The following applies to agriculture in particular: no two biogas plants are the same. As the responsibility rests with the operators, they must have precise knowledge of the specific requirements applying to their plants and must be able to assess possible hazards in accordance with the applicable laws, which in Germany include the Ordinance on Industrial Safety and Health, the Occupational Health and Safety Act and the Hazardous Substances Ordinance. Operators must ensure systematic implementation of these occupational health and

safety measures. The plant operators must also create an explosion protection document which comprehensively assesses the explosion hazards. An important factor in this context is that the room in which the plant is installed is considered an explosion hazard zone, unless the gas-carrying parts of the plant, including the gas extraction elements and the CHP unit, are permanently technically leak proof in service. Gas storage tanks with flexible membrane roofs or storage bags must undergo direct leak testing. The pressure applied in this test should be at least 1.5 times the maximum operating pressure or equivalent to the preset value at which the pressure-relief valve opens, whichever of the two values is the higher. It is important that the gas storage tank is appropriately gastight and resistant to pressure, chemical media, ultraviolet radiation, temperature and weather influences. Protection equipment (suitability, wiring) and the planning of the structure and technical systems (material selection and design) must be customized to the specific plant and inspected at regular intervals. Extraction systems, also those installed outside the biogas plant, reliably prevent incidents such as leaking of toxic gases.

Safety and Efficiency Frequently, comprehensive hazard assessment also helps to uncover hidden potential for savings in the operation of a biogas plant. The objective is to realize the best possible plant design within the framework defined by ordinances, standards and technical rules. By doing so, operators can assess the efficiency and competitiveness of their existing plants more precisely on the one hand, while gaining valuable information for possible future extensions or modernizations on the other. In this type of systematic assessment, organizational measures are increasingly joining aspects of technical safety in the focus of attention. However, in agricultural biogas plants, organizational measures have frequently not yet been given sufficient emphasis. In the case of an incident at the plant, weaknesses in escape and rescue routes and in the emergency preparedness and response plans of the plant in particular may jeopardize human life. Emergency response plans first include basic rules on how to behave in the case of a

fire (publicly displayed notice). Second, they must establish concrete instructions for all employees on site, addressing measures such as fire prevention and what to do in the case of a fire. To ensure an effective alarm system, the sensors of automatic gas and fire detectors must be correctly positioned, calibrated, wired and serviced. Practical tests of the alarm systems and emergency drills with staff are imperative in this context. Ensuring that the alarm signals will actually reach all people on the premises is critical in this context. When planning escape and rescue routes, special attention must be paid to the transition areas between rooms and buildings. Lockable doors in escape routes must be equipped with a specific mechanism ensuring that the door can be opened from the inside even if locked. Manually operated doors must always open in the direction of escape. In addition, steps must be taken to ensure that emergency lighting is both independent from the main supply and explosion-proof (in line with the relevant ATEX zone) and that emergency routes are sign-posted throughout. Discussing and coordinating the rescue and escape plans with the local fire service is also highly advisable. During plant operation it is imperative that the escape routes are kept free from blockage by objects. This applies all the more as all material stored there may increase the fire loads.

Conclusion In addition to a detailed and comprehensive occupational health and safety program, the operators of biogas plants must also increasingly focus on system-related and organizational safety measures. The task at hand is to find the ideal plant solution in terms of safety and costeffectiveness, while ensuring compliance with ordinances, laws and regulations. TÜV SÜD's experts have long-standing experience in the assessment and inspection of biogas plants and advise operators on plant optimization. Authors: Johannes Steiglechner Combustion Systems and Heat Engineering, TÜV SÜD Industrie Service GmbH Volker Schulz Biogas Centre of Competence, TÜV SÜD Industrie Service GmbH +49 (0) 89 5190-1027





Missouri’s Cogeneration Powers Biomass Production Just 10 years after Thomas Edison introduced the first energy recycling program to the U.S. in 1882, the University of Missouri-Columbia began operating a combined-heat-and-power plant—much like Edison’s at Pearl Street Station. BY CHRISTOPHER CHUNG


he power station that got its start in 1892 now provides cooling, heating and energy for a 13 million-squarefoot area that includes three hospitals and several research facilities. The University of Missouri-Columbia's (UM) plant produces 66 megawatts of electricity and 1.1 million pounds of steam per hour using gas, coal, tirederived fuel and biomass, which most often is plant matter used specifically for the generation of electricity and heat. This type of power is known as combined heat and power or cogeneration.

Cogeneration uses a power station or heat engine to simultaneously produce electricity and useful heat. Initially this type of electricity was deemed impractical, because it had to be located close to a load and therefore lost great amounts of voltage. Instead, alternating current caught on and became the electricity of choice for more than 100 years. This type of power centered on the transformer and its effective

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transmission of electricity. But as environmental concerns continue to grow, combined heat and power is taking center stage once again. Universities are popular settings to house combined-heatand-power plants. More than 150 universities in the United States and Christopher Chung, CEO of the Missouri Canada that have some form of a Partnership, cogeneration facility on campus. In says Missouri's Missouri, both MU and Southeast contributions to Missouri State (SEMO) have the cogeneration movement are tapped into the technology. Built substantial. in 1972, SEMO’s combined-heatand-power plant has the capacity to produce 6.2 megawatts per hour.


And the power from these university plants is clean. MU’s plant uses 38 percent less fuel than a conventional plant of comparable size, because it mixes on-site thermal generation with purchased electricity. But the real benefit is in the emissions. MU has lowered emissions of carbon dioxide by 107,000 tons, the equivalent of almost 18,000 passenger vehicles. Further, it has reduced energy use by 10 percent and greenhouse emissions by 12 percent since 1990, which translates into a savings of $6.6 million a year for the university. While MU uses a steam turbine, other cogeneration plants in Missouri, including SEMO, Anheuser-Busch, Missouri State Hospital and Laclede Gas, contain an array of different sources. These sources include combined cycle, combustion turbine and reciprocating engine. The total capacity of cogeneration plants in the state is 226,000 kilowatts of power. Steam turbines, which extract thermal energy from pressurized steam, make up the majority of this power with nearly 140,000 kilowatts. Missouri’s contributions to the cogeneration movement are substantial. In the past five years, the state’s combined-heat-andpower plants have received Energy Star CHP Awards from the U.S. EPA. These facilities include: MU, the Missouri Joint Municipal Electric Utility Commission cogeneration system (on behalf of an ethanol plant in Laddonia, Mo.) and Macon Energy Center combined-heat-and-power project (Macon, Mo.). The MU plant currently uses 10 percent woody biomass—trees and woody plants such as limbs, tops, needles and leaves—but it plans to replace one of its coal-burning boilers with one that uses 100 percent biomass by next year. The new boiler will use 100,000 tons of biomass from in-state sources including woody biomass, grasses, waste papers and agriculture residue. MU will be able to use these sources through bubbling fluidized bed technology. This measure undertaken by the university is partially in response to the city of Columbia’s self-imposed mandate to increase use of renewables to 15 percent by 2022. Columbia’s renewable portfolio standard is


Cleaning Up the Air

RENEWABLE RESULTS: Cogeneration has lowered MU's carbon dioxide emissions by 107,000 tons and reduced its energy use by 10 percent and greenhouse gas emissions by 12 percent since 1990.

one of just a few initiatives in the country imposed at a local level. Columbia’s message is not lost on surrounding communities and companies. MFA Oil, a Missouri oil company, launched a new division in February: MFA Oil Biomass. This division, which is expected to create up to 2,700 jobs, will use farmer-grown crops to produce renewable energy. As part of the venture—one of the largest in the country— more than 200 farmers will grow a perennial grass hybrid called Miscanthus giganteus. The farmers will receive root stock used to grow the crop at the outset of the project along with information about the crop from those who have studied it. Miscanthus giganteus is an ideal biomass crop because it’s noninvasive, drought resistant (requiring only 24 inches of rain per year) and pest resistant. It’s also hardy, requiring less fertilizer than food crops. Miscanthus giganteus is a stabilizing plant, returning water and nutrients to the soil. Once harvested, it is converted into pellets for electrical generation and for use in other energy products, such as ethanol. The growing of Miscanthus giganteus does not interfere with normal yields of corn and soybeans. Further, it can be planted on marginal grounds, such as hillsides and/or pasture lands. Another benefit to farmers is the effect on

their bottom line—those participating in the project will earn additional dollars on the land they farm. But beyond its business benefits, Miscanthus giganteus promises to do wonders for Missouri’s carbon footprint. The plant sequesters 55 times the amount of carbon it takes to plant and harvest, so at its worst, it is a carbon-neutral fuel. It also produces three times more gallons of ethanol per acre of corn, thus meeting the renewable fuels standard requirement. The MFA Oil Biomass division will help meet the energy needs of participating farmers, power companies and even the new MU power plant by processing 600,000 tons of biomass per year. The launch of this project is being embraced by a state that is ready for change. Missouri clearly wants clean energy. Voters approved the state’s RPS by a comfortable margin in 2008, requiring that 15 percent of all power must come from renewable sources by the year 2021. Thomas Edison’s cogeneration, asleep for decades, will be a big part of the push to fulfill that requirement. And biomass will keep the fire burning. Author: Christopher Chung Chief Executive Officer, Missouri Partnership



Renewable Energy Certificates and Renewable Portfolio Standards To participate in the Renewable Energy Certificate market, one must be able to navigate differing state standards and to adjust to still-evolving state, regional and federal initiatives. BY JONATHAN DETTMANN, ANDREW RITTEN AND ANGELA SNAVELY


n recent years, Renewable Energy Certificates have surfaced as one of the more viable of several environmental entitlements supporting a shift to cleaner energy. This is due at least in part to the fact that the regulatory mechanisms supporting these certificates—most notably, renewable portfolio standards (RPSs)—have emerged more quickly than mechanisms supporting other types of entitlements such as cap-and-trade systems giving rise to markets for carbon credits or offsets. In this article we will describe

the regulatory landscape for RECs and what opportunities and challenges they afford. An REC, sometimes called a Renewable Energy Credit or a Green Tag, is a tradable commodity that represents the right to the environmental, social and other nonpower qualities of renewable energy generation. One REC can be created for every 1 megawatt hour of renewable energy generated. The REC can either be sold bundled with or unbundled from the renewable energy itself. If sold

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separately, however, the energy itself is no longer considered renewable because that attribute is now bound up in the REC. RECs were created as tools for measuring and monitoring a utility’s compliance with any applicable RPS, which is a regulatory mechanism for incentivizing the development of renewable energy. Today, RECs continue to be used to satisfy these compliance requirements, but they also can be used for voluntary renewable energy targets that certain organizations might have. Once the REC is used for

POLICY¦ either compliance or voluntary purposes, it cannot be used or sold again. Instead the REC must be retired in order to prevent double counting of the renewable energy. Two mechanisms are used to facilitate the REC trading market: contracts and regional tracking facilities. Of the two, REC tracking facilities, described in more detail below, provide greater transparency when tracking RECs from their point of creation to their point of final use. This article reviews the various aspects of state RPSs, focusing in particular on standards applicable in California, Colorado, Minnesota, North Dakota and South Dakota. In addition, we will provide a brief description of two regional REC tracking facilities, the Midwest Renewable Energy Tracking System (M-RETS) and the Western Renewable Energy Generation Information System. Finally, given ongoing interest in enacting a federal renewable or clean energy standard, we will provide a description of the various elements of those proposed standards.

State RPS Programs Among other things, RECs can be used toward compliance with an RPS, also called a renewable electricity standard (RES). An RPS is a target for renewable energy set as a percentage of overall power consumption, with targets gradually increasing over a period of time. Roughly 30 states have now established RPSs, with RECs counting towards compliance goals. In addition, seven states have enacted renewable portfolio goals. A renewable portfolio goal differs from an RPS in that compliance with the objective is voluntary and there are no penalties or sanctions for a retail provider of electricity that fails to meet the objective. For example, both North Dakota and South Dakota have established voluntary renewable goals of 10 percent by 2015. The renewable energy sources that count for compliance purposes are consistent in both states and include the following: solar, wind, hydroelectric,

biomass, geothermal, hydrogen produced from certain resources, and recycled energy producing electricity from unused waste heat resulting from combustion. Both North Dakota and South Dakota allow a portion or all of the renewable energy objective to be met by the purchase and retirement of RECs that represent renewable energy produced from those sources. While state RPSs have helped encourage the development of the REC market, one problem is that the requirements for the various RPS programs can vary significantly—not only in terms of the percentage goals, but also in terms of the types of RECs that count toward compliance. For example, states can differ in terms of what renewable sources they allow (hydropower), and even the geographic proximity of the generation source can matter. The result has been an increasingly fractured market for RECs, with wide differentiation in pricing. Following is a brief comparison of the RPS standards for California, Colorado and Minnesota. California: California’s RPS was originally established by the California legislature in 2002 and is collaboratively implemented by the California Public Utility Commission and the California Energy Commission. Under the RPS, California’s retail sellers of electricity were required to have 20 percent of their retail sales per year derived from eligible renewable energy resources by Dec. 31. The following renewable energy sources are permitted to satisfy the California RPS: solar thermal electric, solar photovoltaics, landfill gas, wind, biomass, geothermal, municipal solid waste, digester gas, hydroelectricity if produced by certain facilities, tidal energy, wave energy, ocean thermal, biodiesel and fuel cells using renewable fuels. Pursuant to Executive Order S-1408 signed on Nov. 17, 2008, the RPS requirement is increased to 33 percent by 2020 and applies to all utilities. Also,

Executive Order S-21-09 signed on Sept. 15, 2009 directed the California Air Resources Board to adopt regulations for the 33 percent requirement. On Sept. 23, the CARB approved regulations for implementing what is now called the RES. Pursuant to this order, in California, the air resources board is to work with the utility and energy commissions to harmonize the 2010 standard with the 2002 portfolio standard. Furthermore, as discussed in more detail below, the CARB is to monitor the CPUC decision-making process as it relates to the use of RECs for compliance purposes (however, in the RES context they will be called RES certificates). Currently, RECs and the energy procured together as a bundled commodity are eligible for the California RPS. In a March 2010 order, the CPUC ruled that unbundled RECs (or TRECs or REC-only as used in the order), subject to certain restrictions, may be used for compliance with the RPS. In addition, the March 2010 decision provided that a TREC may be traded for three calendar years from the year the electricity associated with the TREC was generated before it must be retired for RPS compliance. The use of TRECs for compliance with the RPS was stayed in May 2010, however. On Jan. 13, the CPUC lifted the stay that was issued in May 2010. In addition, the Jan. 13 order extended the sunset date to Dec. 31, 2013, for the following items included in the March 2010 order: the 25 percent temporary cap imposed on large investor-owned utilities and electric service providers for the amount of TRECs that can be used for RPS compliance purposes and the temporary limit on the price investor-owned utilities are allowed to pay for the TRECs used for RPS compliance purposes to $50 or less per TREC. Colorado: Colorado’s RPS requires each qualifying retail electric service provider to provide specific percentages of renewable energy and/or recycled energy for retail electricity sales in Colorado



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according to the following schedule: • 3 percent for 2007. • 5 percent for 2008-’10. • 12 percent for 2011-’14. • 20 percent for 2015-’19. • 30 percent for 2020 and for each following year. Colorado's RPS also requires all electric cooperatives and each municipal utility serving more than 40,000 customers to provide specific percentages of renewable energy and/or recycled energy for retail electricity sales in Colorado according to the following schedule: • 1 percent for 2008-’10. • 3 percent for 2011-’14. • 6 percent for 2015-’19. • 10 percent for 2020 and each following year. Colorado allows the following renewable sources to be used for satisfying the above thresholds: solar radiation, wind, biomass, hydroelectricity from resources with a nameplate rating of either 30 or 10 megawatts or less depending on when the facility came into existence, geothermal, recycled energy and fuel cells using renewable fuels. Recycled energy is energy produced by a generation unit with a nameplate capacity of not more than 15 megawatts that converts the otherwise lost energy from the heat from exhaust stacks or pipes to electricity and that does not combust additional fossil fuel. Colorado applies a multiplier to certain types of renewable energy. For example, each kilowatt-hour of eligible energy generated in Colorado is counted as 1.25 kilowatt hours for complying with the Colorado RPS. The multipliers also apply to RECs representing electricity generated by applicable renewable energy sources. Colorado requires that all post-regulation contracts for RECs clearly specify who owns the RECs associated with the energy generated by the facility. In addition, Colorado also has specific regulations regarding provisions that are required for renewable energy supply contracts (bundled REC agreements) and renewable energy credit contracts (unbundled REC agreements). The eligibility to use RECs for compliance expires at the end of the fifth calendar year, following the calendar year during which they were generated. While there is not a specific dollar cap on the amount a utility can pay for an REC, the Colorado regulations limit the net retail rate impact of actions taken by an investor-owned utility to comply with the RPS to 2 percent of the total electric bill annually for each customer of that utility. Minnesota: Minnesota’s nuclear utilities are required to meet the following schedule for RPS compliance: • 15 percent by Dec. 31, 2010. • 18 percent by Dec. 31, 2012. • 25 percent by Dec. 31, 2016. • 30 percent by Dec. 31, 2020. Of the 30 percent that must be generated by 2020, at least

POLICY¦ 25 percent must be generated by solar energy or wind energy, with no more than 1 percent of the 25 percent requirement being generated by solar energy. The standard for other Minnesota utilities requires that eligible renewable electricity account for the following percentages of retail electricity sales to retail customers: • 12 percent by Dec. 31, 2012. • 17 percent by Dec. 31, 2016. • 20 percent by Dec. 31, 2020. • 25 percent by Dec. 31, 2025. The following renewable sources are permitted to comply with the Minnesota program: solar, wind, biomass, hydroelectricity produced by facilities with capacity under 100 megawatts, and hydrogen generated from certain resources. The program treats all eligible renewables equally and may not ascribe more or less credit to energy based on the state in which the energy was generated or the technology used to generate the energy. RECs are eligible for use for RPS purposes in the year of generation and for four years following the year of generation (all credits generated during 2008, regardless of the month, will expire at the end of 2012). Notably, Minnesota’s nuclear utilities may not sell RECs to other Minnesota utilities for RPScompliance purposes until 2021. On Sept. 9, the Minnesota Public Utilities Commission issued an order determining ownership of RECs for power purchase agreements made pursuant to the 1994 Minnesota Wind and Biomass Statutes and the 1978 federal Public Utility Regulatory Policy Act. The MPUC determined that the utility owns the REC received pursuant to power purchase agreements entered into under the Wind and Biomass Statutes, unless the generator can demonstrate that the power purchase agreement is not silent as to REC ownership and explicitly provides otherwise. Essentially, the REC ownership goes to the utility in this instance because the utility likely paid a premium for the renewable energy so that it could claim the energy to fulfill its renewable energy obligations arising under the Wind and Biomass Statutes. For RECs received pursuant to power purchase agreements entered into under PURPA, the generators own the RECs absent contractual provisions to the contrary because the power purchased by utilities pursuant to PURPA was purchased to meet statutory demands entirely different from those imposed by the Wind and Biomass Statutes.

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Attempts to Standardize: M-RETS and WREGIS A tracking facility is an electronic database that is used to track the ownership of RECs, much like an online bank account. The M-RETS and WREGIS are examples of two regional tracking facilities that are in operation today. A tracking facility provides the following services for the REC market: • Issues a uniquely numbered electronic certificate for each megawatt-hour of electricity generated by a generation facility

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¦POLICY registered in the system. • Tracks the ownership of certificates as they are traded. • Retires the certificates once they are used or claims are made based on their attributes or characteristics. Because each megawatt hour has a unique identification number and can only be in one owner’s account at any time, this reduces ownership disputes and the potential for double counting. Essentially, any person or entity interested in participating in the REC market can establish an account on the M-RETS and/or WREGIS systems to facilitate the participation in the REC market. According to the California RES, the price of RECs sold for compliance purposes ranged from $10 to $40 per megawatt hour. However, RECs in

voluntary markets have sold for as low as $1.50 per megawatt-hour. Furthermore, according to the California RES, in 2009 there were more than 35 million active WREGIS certificates generated that are certified for use in California. The price of an REC will vary depending on when it was purchased, the type of resource underlying the REC, the jurisdiction, and whether it was used for compliance of voluntary purposes.

The Proposed Federal RPS On Sept. 21, Sen. Jeff Bingaman, D-N.M., and 23 other senators introduced the Renewable Electricity Promotion Act of 2010, S. 3813, which proposed to establish a combined renewable energy and energy efficiency standard nationwide. While the bill has lost momentum in 2011, it is nevertheless

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instructive in terms of what we could expect to see at the federal level if political support for such a measure resumes. The bill defines renewable energy to include most generally accepted forms, as well as some emerging forms, including energy generated from solar, wind, geothermal, biomass, landfill gas, marine and hydrokinetic, coal-mined methane, and certain qualified hydropower and waste to energy. The bill also leaves the door open for the secretary of energy to add additional sources of qualifying renewable sources based on innovative technology. The bill further gives at least some credit to other kinds of electricity by excluding that electricity from the base quantity to which the required renewable percentage is applied. This excluded power includes certain hydroelectric power, fossil fuelgenerated power to the extent the greenhouse gas emissions from its generation are sequestered, and additional nuclear power placed in service in the future. In terms of the renewable standards themselves, the bill requires minimum annual percentages as follows: • 3 percent from 2012-’13. • 6 percent from 2014-’16. • 9 percent from 2017-’18. • 12 percent from 2019-’20. • 15 percent from 2021-’39. Electric utilities selling more than 4 million megawatt hours of electricity can meet these compliance obligations through one or a combination of the following options: • RECs. • Energy efficiency credits (for up to 26.67 percent of the compliance obligation). • Alternative compliance payments of 2.1 cents per kilowatt hour, adjusted for inflation. The alternative price payment would effectively put a price limit on RECs of $21 a credit. All credits are tradable, but not all credits are created equally. The bill allows double credits for facilities on Indian land, and triple credits for both small renewable distributed generators less than 1 megawatt and facilities that generate energy from algae.

POLICYÂŚ Importantly, the federal bill leaves all state programs in place, merely requiring the secretary to facilitate coordination between the federal and state programs, and to promulgate regulations that would effectively give utilities credit toward meeting federal compliance obligations to the extent the utilities are simultaneously meeting state compliance obligations. The bill issues a number of additional requirements to the secretary, including that the secretary make interest-friendly loans available to electric utilities for purposes of carrying out approved, qualified projects for meeting compliance obligations. It requires the secretary to monitor the costs and benefits of the program and to submit recommendations to Congress for whether the compliance obligations should be increased or relaxed. And it requires the secretary to implement regulations establishing the program within one year of enactment. More recently, talk at the federal level has shifted towards a clean energy portfolio standard (CEPS). In general, a CEPS would broaden the types of energy that could be used for compliance purposes to include nuclear power and clean coalâ&#x20AC;&#x201D;namely, coal-fired plants using carbon capture and sequestration. It would also allow for more state and regional control in deciding what types of energy will satisfy compliance obligations, which some view as more politically palatable given notable regional variability in the types of clean energy that are available. President Obama recently supported the adoption of a nationwide clean energy standard (CES) in his State of the Union address. He proposed a CES requiring that 80 percent of the nationâ&#x20AC;&#x2122;s electricity come from clean energy technologies by 2035. On March 21, Sens. Bingaman and Lisa Murkowski, R-Alaska, acting on behalf of the Senate Energy and Natural Resources Committee, issued a white paper to solicit ideas on whether and how a federal CES might be implemented. At the same time, Sens. Tom Udall, D-N.M., and Mark Udall, D-Colo., have reintroduced

legislation proposing an RES standard of 25 percent by 2025, 10 percent higher than the Bingaman RES bill.

Conclusion Given the increasing RESs at the state level and ongoing debate at the federal level, RECs will remain important to both utility companies and renewable energy generators. The ability to use certain RECs for compliance purposes and the market for RECs varies by jurisdiction. The parties involved in the REC market must be able to navigate differing state standards and to adjust to still-evolving state, regional and federal initiatives. Even if some form of national standard develops, it is not likely to supersede or eliminate many if any of the initiatives occurring at the lower levels, at least not in the short term.

In addition, participation in the REC market involves many legal considerations, including the ownership of the RECs, assessment of compliance standards, contract negotiations for REC transactions, and the flexibility to account for changing conditions. For anyone participating in the REC market at any significant level, consultation with counsel knowledgeable with the RECs and the various RPS standards is encouraged. Authors: Jonathan Dettmann Partner, Faegre & Benson LLP Andrew Ritten Partner, Faegre & Benson LLP Angela Snavely Associate, Faegre & Benson LLP



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