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vol. 15 no. 6

60 CHP Generating Power at the Plant: CHP Boosts Efficiency Combined heat and power systems offer ethanol plants a way to produce electricity and steam with greater energy efficiency, reduce carbon emissions, and lower energy input costs. –By Susanne Retka Schill

68 PROFIT Doing the Math An Iowa State University sociologist has developed a tool to illustrate how corn and ethanol prices dictate the fate of the industry. –By Ryan C. Christianson

76 MARKET The Economics of Distillers Grains Ethanol production and, as a result, distillers grains production continues to increase despite an increasing number of ethanol facilities idling operations. EPM explores the market for distillers grains and its supply and demand factors.


–By Hope Deutscher

84 TECHNOLOGY Perfecting the DDGS Pellet Pelletizing 100 percent DDGS has been a challenge but one company says it has effectively manufactured a pellet die that will extrude a 100 percent DDGS pellet without additives or binders. –By Ryan C. Christiansen

features 44 USE The Push for E15 Ethanol industry representatives officially filed a petition with the U.S. EPA to allow the use of E15 and, while the approval process is quite lengthy, early hints of support from influential parties give hope to the industry. –By Erin Voegele 52 POLICY The Road to a Low Carbon Future The California Air Resources Board recently passed a Low Carbon Fuel Standard that includes requirements for biofuel producers to report indirect land use change. EPM examines the standard and discusses its details with a CARB official. –By Erin Voegele

92 STORAGE Wet Storage Strategies Demand for wet distillers grains (WDG) can dip during the summer months when feedlots are less active. Proper storage techniques can allow feedlot owners to take advantage of lower summer prices while at the same time allow ethanol producers to more easily sell WDG year-round. –By Ryan C. Christiansen

100 PROFILE The Forefront of Enzyme Production EPM visits with Novozymes, one of the world’s leading enzyme producers, to take a look at the future of enzyme production. –By Kris Bevill

106 CELLULOSE Cobs to Switchgrass to Gasoline Parity Partners in a venture taking shape in eastern Tennesee hope to realize the promise of cellulosic ethanol. –By Susanne Retka Schill


June 2009


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contents contributions

departments 9 Advertiser Index

112 ARMENIA Ethanol in Armenia A feasibility study to determine ethanol’s potential in Armenia found corn and Jerusalem artichoke to be viable potential feedstocks. –By Kendrick Wentzel and Areg Gharabegian


12 The Way I See It Cellulosic Industry has a Long Way to Go By Mike Bryan 16 Business & People 20 Commodities 22 View From the Hill The Language of Ethanol By Bob Dinneen 23 RFA Update 24 BIObytes 26 Industry News

119 FINANCE Project Financing in Difficult Capital Markets Many types of government assistance is available to assist future ethanol producers. –By Sue Wyka

38 Finance Open the Door to Banking Relationships By Peter Martin 40 Legal Perspectives Foreclosure Alternatives By David Meyer 42 eBIO Insider European Walls By Robert Vierhout


126 Events Calendar 128 Marketplace 122 SULFUR Protecting Distillers Grains from Sulfur Build-up Monitoring sulfur levels throughout the ethanol production process is necessary to prevent high levels of the nutrient from negatively affecting distillers grains. –By Tom Slunecka


Ethanol Producer Magazine: (USPS No. 023-974) June 2009, Vol. 15, Issue 6. Ethanol Producer Magazine is published monthly. Principal Office: 308 Second Ave. N., Suite 304, Grand Forks, ND 58203. Periodicals Postage Paid at Grand Forks, North Dakota and additional mailing offices. POSTMASTER: Send address changes to Ethanol Producer Magazine/ Subscriptions, 308 Second Ave. N., Suite 304, Grand Forks, North Dakota 58203. BPA Worldwide Membership Applied for October 2006


June 2009



36 2009 Atlantic Bioenergy Conference 82 2010 National Ethanol Conference 10 2010 International Fuel Ethanol Workshop & Expo 8 108 50 91 66 & 90 49 110 19 & 62 30 96 3 87 80 64 95 28 94 72 111 13 & 63 98 59 75 57 125 73 70 29 41 31 46 104 74 71 67 124

Afton Chemical Corp. Agra Industries Corp. Angel Yeast Co. LTD Ansul - Fire Solutions BBI International Engineering & Consulting BetaTec Hop Products Inc. Biofuels Automation Biomass Magazine Buckman Laboratories Inc. Buhler Inc. Burns & McDonnell California Pellet Mill / Roskamp Champion / Beta Raven Centrisys Corp. Cereal Process Technologies CGB Enterprises Inc. Check-All Valve Mfg. Co. Christianson & Associates PLLP Clifton Gunderson LLP Cloud/Sellers Cleaning Systems Crown Iron Works Co. Inc. dbc SMARTsoftware Inc. Delta-T Corp. Eisenmann Corp. Encore Business Solutions ETS Laboratories Fagen Inc. FCStone LLC Fermentis Flottweg Separation Technology Freez-it-Cleen Gamajet Cleaning Systems Inc. Gavilon GEA Barr-Rosin Inc. Genencor International Inc. Gusmer Enterprises Inc.


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2 4 14 & 15 32 116 34 55 43 89 6 115 114 81 39 88 109 79 56 99 48 105 51 136 58 33 121 97 47 117 135 65 120 123 35 54 78 83 103 102 86 37

Hydro-Klean Inc. ICM Inc. Inbicon Indeck Power Equipment Co. Interstates Co. Intersystems Kennedy & Coe LLC Lallemand Ethanol Technology Louis Dreyfus MAC Equipment Martrex Inc. McC Inc. Midwest Towers Inc. MOR Technology LLC Nalco Co. Natwick Associates Appraisal Services Nexen Marketing USA Inc. North American Safety Valve Novozymes Perten Instruments Inc. Peters Machine PhibroChem Poet LLC Premium Plant Services Primafuel Pro-Environmental R&R Contracting Inc. Resonant BioSciences LLC Rev Tech LC Robert-James Sales Inc. Ronning Engineering Salco Products Inc. SGS North America Inc. Spraying Systems Co. Sulzer Process Pumps U.S. Tsubaki Vaperma Inc. Vogelbusch USA Inc. W. Soule & Co. Wabash Power Equipment Co. WINBCO



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June 2009


The Way I See It Cellulosic Industry has a Long Way to Go I found the plant construction information in the April issue of EPM most interesting and, despite my years in the ethanol industry, somewhat alarming. It has always been assumed that there would be a gap between grain-based ethanol and cellulosic ethanol. The gap appears to be growing, not shrinking. In March, I attended a U.S. DOE-sponsored review of cellulose-based biofuels projects that have received DOE funding. Let me repeat myself — the gap between grain-based ethanol and cellulosic ethanol is big. But it’s certainly not for lack of effort, innovative ideas, or, in some cases, money to move forward. The fact is some basic questions still need to be addressed. Feedstock remains a major issue. From municipal solid waste to corn stover to various forms of wood, the harvesting, collection and storage of huge quantities of cellulosic feedstock is problematic. Is it unsolvable? No, but it remains an issue that will not easily be resolved. In addition to the physical handling of the feedstock, I believe price is a core factor. Cellulosic feedstocks are projected to be between $45 and $55 per ton by the proponents of the biofuels plants. A farmer who spoke at the Canadian Renewable Energy Workshop held recently in Regina, Saskatchewan, told potential cellulose-based ethanol producers, “By the way, the biomass in my field is $100 per ton. Get used to it.” Is this the prevailing attitude of the farming community? It’s hard to tell at this early juncture, but we all know that price will follow demand. I could not help but wonder if the feedstock prices being used in these DOE presentations were based on what the produc-

tion facility needs to create a reasonable bottom line, or if that is actually what the farmer, forester or community will sell the feedstock for in the long term? Finally, it seemed that with the exception of a couple of presenters, none of the companies that participated in the DOE meeting had secured the funding to complete pilot projects. Some have been put on hold; numerous others are still seeking funding. The DOE is sincerely trying to foster the creation of a robust cellulosic industry, but there are significant technical and financial hurdles that remain to be solved. Look, I believe in the future of cellulosic biofuels, and I’m confident that we will get there. At the same time, it should be of great concern to all of us that there are those who are turning their backs on grainbased biofuels and literally burning the bridge that got us to where we are today. Grain-based ethanol works! It has worked well for the past 30 years and will continue to do so for many years to come. We need to remain committed to the growth of the grain-based industry while we work out the last remaining issues of the cellulose-to-ethanol technology. That’s the way I see it.

Mike Bryan Publisher & CEO



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Business&People Ethanol Industry Briefs

 T h e Biotechnology Industry Organization recognized Sen. Chuck Grassley, D-Iowa, as a BIO LegislaGrassley tor of the Year during its annual Wasthington D.C. lobby trip. Grassley received the honor for his work in supporting the development of renewable fuels. BIO president and CEO Jim Greenwood said Grassley has played an instrumental role in renewable fuels development, particularly in the area of corn-based ethanol.

National Farmers Union delegates elected North Dakota Agriculture Commissioner Roger Johnson as president of the organization during its annual convention in Johnson March. Johnson is replacing Tom Buis, who earlier this year accepted the CEO position of ethanol industry group Growth Energy. Johnson, a third-generation North Dakota farmer, is a lifelong Farmers Union participant and said he plans to make the organization’s 2009 policy positions a priority on Capitol Hill.


The U.S. EPA awarded the Missouri Joint Municipal Electric Utility Commission an Energy Star combined heat and power award for a combustion turbine-based system at the Poet Biorefining-Laddonia, Mo. ethanol plant. The system became operational in September 2007 and is estimated to reduce carbon dioxide emissions by 31,000 tons annually. Waste heat recovered from the turbine exhaust is used to produce up to 63,000 pounds of steam per hour to support ethanol production.

Montreal-basedEnerkem Inc. plans to build and operate its first U.S. cellulosic ethanol facility in Pontotoc, Miss.. The 20 MMgy production plant will utilize locally obtained forest wood residue, MSW, construction and demolition debris and treated wood as feedstocks. Plans for the property also include an upstream MSW recycling and pre-treatment center. Total costs are expected to reach $250 million. The company currently operates a pilot-scale facility in Quebec and is in the start-up phase on its first commercial-scale facility, also located in Quebec. Construction is also expected to begin soon for an additional facility in Alberta.

Dry fractionation specialist Cereal Process Technologies Inc. has introduced a new application to its dry milling technology that allows ethanol producers to capture up to 96 percent of corn kernel starch. The company said its adjustable MarketFlex system enables producers to capture more starch and produce more ethanol when corn oil prices are low and increase corn oil production when prices rise. Renew Energy was the first production facility to install the system and used it at its 130 MMgy Jefferson, Miss. facility for more than one year.

Indiana-based bioengineering firm Xylogenics Inc. recently named two officers to its board of directors. Butch Mercer, CEO of biotechnology consulting firm BioMark, was named chairman of the board, and Nick Mathioudakis will serve as legal and business advisor. The company acquired a patent in February for technology to use yeast strains to boost fermentation yields in the production of ethanol. Xylogenics CEO. Mike Neibler said the technology can be used by cellulosic producers as well as traditional corn ethanol producers.

Colorado-based PureVision Technology Inc. is scaling up its fractionation technology

with an eye towards future collocation at ethanol production facilities. The company plans to deploy a 20-ton per day fractionation reactor at a research facility next year and predicts it will be capable of installing a reactor at a demonstration-scale ethanol facility in 2011. PureVision is testing various feedstocks to be used in its reactors including corn residues and wood.

Omaha, N e b. - b a s e d Green Plains Renewable Energy Inc. has appointed WayneHoovestol as its Chief Hoovestol Strategy Officer. Hoovestal joined GPRE in 2006 as the company’s director and chairman of the board and has also served as the chief operating officer and CEO. Current CEO Todd Becker said Hoovestol’s experience and industry knowledge is invaluable and he will assist in driving strategic initiatives across the company. In addition to the new strategy position, Hoovestol will also retain his seat as chairman of the company’s board.

Nearly $6 million in equity was put forth by Show Me Ethanol LLC stakeholders after the company announced it needed an influx of cash to avoid de-


Sponsored by

faulting on loans. In March, the company said that with the help of necessary additional capital from stakeholders, additional cash flow would be sufficient to comply with debt notes. Cash problems likely stemmed from an extensive amount of corn supply contracts entered into last summer with the company’s sole corn supplier, Ray-Carroll Country Grain Growers Inc. The two companies have since reorganized their supply agreement, fixing the rate at which outstanding contracts will be honored.

Houston-based alternative energy technology developer Gulf Ethanol Corp. has changed its name to Gulf Alternative Energy Corp. The company said the change was made to reflect its efforts to advance biomass processing technology beyond the ethanol industry. The company has been developing a system that processes biomass into a fine powder that can then be used to produce cellulosic ethanol.

Potential cellulosic ethanol producer AE Biofuels Inc. has partnered with engineering firm Merrick & Co. to commercially implement AE Biofuels’ technology through the

design of new facilities or the conversion of existing biofuels facilities. Merrick most recently led the process design and construction support at NREL’s cellulosic ethanol research and development facility in Golden, Colo. AE Biofuels is working to commercialize its patent-pending cellulosic ethanol technology. Its subsidiary, Universal Biofuels, owns a 50 MMgy biodiesel facility in India.

Merrick& Co. has expanded its fuels and energy group with the addition of two senior technical specialists. Bart Carpenter Carpenter was most recently employed with ConocoPhillips in Houston and has more than 25 years of engineering and management experience in the downstream petroleum industry. Greg Heuer has worked for 28 years in the biofuels industry. Prior to joining Merrick, Heuer served as vice president of process engineering for Cilion Inc. and was a process consultant to the ethanol industry.

Qteros, formerly SunEthanol Inc., has moved its headquarters from Hadley, Mass. to Marlborough, Mass. According to company CEO Bill Frey, the company relocated to take


advantage of local industrial facilities that will be required for Qteros’ expansion plans. The company has been working to commercialize its QMicrobe technology for cellulosic ethanol production and plans to begin operating a pilot plant in Springfield, Mass. in 2010.

The South Dakota Corn Utilization Council elected its officers for 2009 during a March 19 board meeting. David Fremark was elected president of the council. He has been a SDCUC board member since 2006 and also serves as a public policy action team member for the National Corn Growers Assoc. Keith Alverson was elected to a second term as the council’s vice president. He also serves on the NCGA Ethanol Committee.

British Petroleum plc chief scientist Dr. Steven Koonin has been nominated by President Barack Obama to serve as Under Secretary for Science at the U.S. DOE. Koonin joined BP after working as professor of theoretical physics at the California Institute of Technology for 29 years. Cathy Zoi has been nominated by the president to serve as the assistant secretary for energy efficiency and renewable energy

at the DOE. Zoi served as chief of staff in the White House office on environmental policy during the Clinton administration.

Massachusetts-based Verenium Corp. has consolidated its research and development organization. Operations will now be led by Gregory Powers, executive vice president of R&D. The company said its new organizational structure provides a unique set of R&D assets from the laboratory through its demonstration-scale facility in Jennings, La. and will allow for more efficient development, implementation and testing of its cellulosic ethanol technologies. In addition to the organization changes, Verenium announced that John Malloy, executive vice president of biofuels, has left the company to pursue other opportunities.

Stabilized chlorine dioxide manufacturer Bio-Cide International Inc. has appointed Bob Picek to be the company’s special projects manager for the ethanol industry. Picek has more than 30 years of experience developing fluid purification and treatment programs and will apply his experience toward assisting ethanol producers to increase their product yield and maintain biological control through the


Business&People Ethanol Industry Briefs

application of fermentation, propagation technology.

David Blume’s bestselling book, “Alcohol Can Be A Gas,” has been selected as course text for a biofuels program at Richland Community College in Decatur, Ill. The college launched a new biofuels course for the spring semester as a way to retrain and supplement victims of recent area industrial market layoffs. Richland’s biofuels course currently consists of three lectures and two lab classes and provides course graduates with three credits toward their elected degree program and a certification of completion.

Illinois-based biofuels technology developer Coskata Inc. plans to begin working on projects in Australia and Thailand to utilize its flexible feedstock technology for the production of cellulosic ethanol. Negotiations are also pending between Coskata and Floridabased U.S. Sugar for an agreement which would ultimately result in a 100 MMgy cellulosic ethanol production facility in Clewiston, Fla. Before an agreement can be reached with Coskata, U.S. 20

Sugar must complete a land sale and use agreement with the state of Florida. The state proposed purchasing more than 72,000 acres from the company for an Everglades restoration project.

The National Ethanol Vehicle Coalition has formed a foundation to increase awareness of the benefits of using ethanol as a form of transportation fuel. The NEVC is seeking donations for the National Ethanol Vehicle Foundation; all contributions are tax deductible and can be made through the NEVC’s website at www. The NEVC was created in 1996 as a nonprofit organization to serve as the nation’s primary advocacy group promoting the use of E85 as a fuel source. The coalition is comprised of individuals and organizations who have pledged to ensure that E85 has a place in America’s fuel supply.

Phibro Animal Health Corp. has filed a petition with the U.S. Food and Drug Administration to approve its trade-

Sponsored by

marked brand of the antibiotic virginiamycin as an animal feed additive. Phibro’s Ethanol Performance Group has been marketing its version of virginiamycin, Lactrol, to ethanol producers for years but because the FDA now holds jurisdiction over the production of ethanol, petitions must be filed for any antibiotics that could remain in distillers grains after ethanol is produced.

Purdue University professor Michael Ladisch received the Charles Scott award at the 2009 Symposium on Biotechnology for Fuels and Chemicals held in San Francisco in May. The professor of agricultural, biological and biomedical engineering was acknowledged for his work in the use of biotechnology to produce fuels and chemicals. Ladisch is the director of Purdue’s Laboratory of Renewable Resources Engineering and is currently focused on the conversion of wood to ethanol.

Cellulosic ethanol producer Mascoma Corp. has announced plans to relocate its company headquarters from Boston to Lebanon, N.H. in August. The company currently operates a research and development facility in Lebanon and the majority of its employees are also based in Lebanon. The

company said the move will allow R&D, engineering and commercial development staff to work together under one roof and will provide for the smooth transfer of technology from the lab to operating facilities.

Poet Biorefining-Preston, Minn., production facility has received a “Meritorious Achievement” honor from the Minnesota Safety Council for having a low injury incidence. The council grants Governor’s Safety Awards such as the meritorious honor to businesses that have above average performance in incident rates. Award applicants are required to submit injury information, which is compared with state and national data. Ongoing safety programs and activities are also considered. As of April 16, the Preston facility had gone 1,124 days without a lost time accident. EP

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Biomass Magazine is a trade journal serving companies that use and/or produce power, fuels and chemical feedstocks derived from biomass. Collectively, these biomass utilization industries are positioned to replace nearly every product made from fossil fuels with those derived from plant or waste material. The publication covers a wide array of issues on the leading edge of biomass utilization technologies, from biorefining, dedicated energy crops and cellulosic ethanol to decentralized power, anaerobic digestion and gasification. Itâ&#x20AC;&#x2122;s all here.

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COMMODITIES REPORT Natural Gas Report By Casey Whelan, U.S. Energy Services Inc.

Carbon Legislation and Natural Gas Prices April 21 - Natural gas prices have been relatively low for several months and there doesn’t appear to be any supply or demand shocks that will change the situation for some time to come. However, climate change legislation currently being considered by Congress may impact natural gas prices. There are two potential impacts on natural gas prices related to the legislation – direct and indirect. The direct cost is relatively easy to assess since the carbon content of natural gas is known (117 lbs/ MMBtu). Under the bill, consumers will be required to have an “allowance” for each MMBtu combusted. The indirect impacts are much more uncertain and difficult to measure. The indirect impacts in some cases lead to higher prices and in other cases lead to lower prices. First, natural gas demand for electric generation will likely increase significantly as coal costs (higher carbon content) increase dramatically. Higher demand, all else being equal, leads to higher prices. Second, on the supply side, producers will get less of the “retail price” as more dollars are directed to the government through the carbon auction. This will likely result in less supply than would be the case if more of the retail price went to natural gas producers. Less supply tends to lead to higher prices. Finally, natural gas demand may be tempered somewhat as revenues generated from the carbon auction are funneled to alternative energy technologies and

projects. To the extent these technologies find replacements for natural gas or result in more efficient use of natural gas, this could lead to lower prices. While no strong conclusion can be drawn, natural gas prices will potentially increase due to indirect impacts since natural gas has a relatively low emissions profile and is a very reliable source for electric generation. EP Casey Whelan, vice president of strategic initiatives, can be contacted at

Corn Report By Jason Sagebiel, FCStone

Acreage projections stabilize basis levels April 20 - Corn volatility is tamer today with acres now projected at 84.986 million acres. While this is down 996,000 acres from a year ago, it is still higher than the trade had expected. Iowa, Minnesota and North Dakota are expected to see a decrease in corn plantings. South Dakota, Missouri and Illinois are expected to see increases with Missouri expected to have the largest increase from a year ago. Soybean acres are expected to increase 75.718 million acres, up 306,000 acres from the previous year. Milo acres were reduced by 1.324 million acres and this could have an impact on ethanol plants within the lower Plains. As plantings have begun, weather will be the key focus going forward through the growing and pollination period, possibly boosting volatility. The other major caveat for this corn market will be any bullish news in the soybean market. The soybean market will still focus on demand from China and a lack of soybeans in the southern hemisphere – sure to keep both the grain and oilseed markets volatile this summer. Basis levels throughout the Midwest have been rather strong versus historical basis levels up through the time of this writing. Planting season should keep corn basis levels fairly narrow; howev22

er, overall flat price will determine the overall producer movement. This tighter basis level continues to have a negative impact on the crush margin. EP ETHANOL PRODUCER MAGAZINE • June 2009

COMMODITIES REPORT DDGS Report By Sean Broderick, CHS Inc.

Market demand is tough to define April 14 - The distillers grains market was difficult to define until mid- to late-April. Export business out of the Gulf of Mexico has been steady, but not overwhelming. It is an odd time of the year that usually pulls prices in two distinct directions. On the one hand, animals begin to eat less with the warmer weather and cattle moves out to pasture, leading to less demand, and lower prices. The alternative is that planting issues can pull grain futures, and consequently, DDGS, higher. This year, poor ethanol margins have led to plant slowdowns and shutdowns, which led to tightness in distillers supply and upward pressure on prices. But there are several

plants that are starting up, and several others that are temporarily shut down but still in “hot idle,” which speaks to the possibility of additional plants running, potentially loosening supply for the summer months. The feeding sectors are still facing negative margins, but there is improving profitability going ahead, especially in the dairy sector, which had been hit exceptionally hard in the past couple of quarters. Worldwide demand is still adequate, in spite of the dollar strength. Available credit is constantly a challenge, but there is hope that terms will alleviate as the summer progresses. EP

Regional Ethanol Prices ($/gallon as of April 17)




West Coast






East Coast


1.8256 SOURCE: DTN

Regional Gasoline Prices ($/gallon as of April 17)




West Coast






East Coast


1.5611 SOURCE: DTN

DDGS Prices ($/ton) LOCATION

APRIL 2009

MARCH 2009

APRIL 2008













Buffalo, N.Y.




Central Florida




Corn Futures Prices DATE

Ethanol Report


*Central Valley

(May corn, $/bushel)




April 20, 2009

3.80 1/4


3.78 3/4

March 20, 2009

4.08 1/4

4.05 1/2




5.93 3/4

April 21, 2008


By Rick Kment, DTN Biofuels Analyst

Ethanol market holds steady April 17 - Ethanol prices have been in a holding pattern over the past couple months with overall choppy buying activity in the futures, spot and rack markets. Moves in each of these markets have remained narrow as spring progresses, with overall buying interests seemingly moving back and forth between moves in corn prices and energy markets. Gasoline prices moved moderately higher from March to April. This buying support in the gasoline market is expected every summer as increased driving is expected. Overall demand for gasoline, however, is expected to remain limited by the poor economy and lack of driving as consumers continue to cut back spending. The expectations of tighter supplies are likely to push gasoline prices

moderately higher through the summer months, but the sharp moves seen in previous years are not nearly as likely. This could keep prices trading in a range-bound fashion through much of the summer. If gasoline prices remain range bound, overall buying activity in the ethanol market is likely to remain subdued as many feel that the current production level of ethanol is enough to handle the current and expected demand. This may keep overall markets soft with a very limited upward potential, although the overall corn price currently is the main driver in ethanol future price moves. Ethanol plant margins remain weak, which may cause additional plant and ethanol company shut downs. EP


Cash Sorghum Prices ($/bushel) APR. 17, 2009 MAR. 31, 2009 APR. 17, 2008 Superior, Neb. Beatrice, Neb. Sublette, Kan. Salina, Kan. Triangle, Texas Gulf, Texas

3.16 3.11 2.92 3.24 2.94 3.81

3.40 3.37 3.21 3.59 3.17 4.15

5.46 5.50 5.49 5.61 5.56 6.24 SOURCE: Sorghum Synergies

Natural Gas Prices


APRIL 2009

MARCH 2009

APRIL 2008





N. Ventura




Calif. Border




SOURCE: U.S. Energy Services Inc.

U.S. Ethanol Production Output January 2009


December 2008


January 2008



SOURCE: U.S. Energy Information Administration




The Language of Ethanol To be successful in today’s economy, industries must capture the imagination of the public. Your wireless network must be 3G, your iPod must be “touch,” your coal must be clean, and your renewable fuel must be next-generation. But what passes for next-generation? Must it be technologies that use feedstocks other than starch or sugar? What about technologies that make already operational technologies more efficient and productive? In Washington, the focus on the direction of the nation’s renewable fuels industry is almost exclusively on advanced and cellulosic production technologies. While that focus is important, it too often crowds out the innovation that defines America’s existing ethanol industry. At ethanol biorefineries across the country, the language of ethanol technology is changing rapidly. Fractionation is replacing grinding, separating the components of corn kernels so as to improve ethanol and distillers grains yields while reducing energy needs. Gasification and fluidized bed reactions are taking the place of boilers and natural gas in powering biorefineries. Displacing the need for fossil fuels to power ethanol production reduces greenhouse gas emissions and improves the bottom line by removing some of the exposure to volatile energy markets. Graywater is being substituted for groundwater. Utilizing recycled water instead of drawing up groundwater further improves ethanol’s environmen-

tally sustainable profile and reduces costs associated with the purchase of water rights. And of course, cellulose is joining corn, sorghum, and sugar cane as a feedstock for ethanol production. Technologies such as acid hydrolysis and thermochemical conversion are turning a wide range of feedstocks such as corn cobs, wood chips and garbage into a renewable alternative to petroleum. Ethanol 2.0 or next-generation biofuels or whatever label you wish to put on the future of American ethanol production is coming. But these technologies are not likely to be the revolutionary, pie-inthe-sky stuff that are glorified in science fiction lore. Rather, these technologies are best described as evolutionary. Converting corn cobs, switchgrass, and wood chips into ethanol is the natural next step for American ethanol production. The technologies that will be deployed are the logical outcropping of the successful and still evolving technologies in use at nearly 200 locations across the country. While the names of the technologies ethanol producers are developing every day may not be as catchy as those in the cell phone business, they are no less exciting or important. Policy makers in Washington and critics of ethanol the world over would do well to learn the language of ethanol technology and appreciate the rapidly innovation nature of this industry. The next generation of ethanol technologies is already here.

Bob Dinneen President and CEO Renewable Fuels Association




w w w. e t h a n o l R FA . o r g

Minnesota water usage study not accurate A study from the University of Minnesota claims that ethanol production is resulting in a dramatic increase in water use, larger than was previously thought. However, by looking at water use in isolation, the report fails to take into account numerous factors that must be part of the water use discussion. “Expansion of America’s renewable fuels industry is occurring with the most efficient use of natural resources like water in mind,” said Renewable Fuels Association President Bob Dinneen. “Ethanol producers are investing in new technologies that reduce water use, improve efficiency, and employ feedstocks in addition to grain for ethanol production. It is important that these worst-case scenarios offered by the University of Minnesota are not allowed to overshadow the improvements being made in farming and renewable fuel technologies.” The paper failed to note statistics from the National Renewable Energy Laboratory showing that 96 percent of all the corn used in ethanol production comes from non-irrigated acres. Less than 15 percent of the total corn crop is irrigated. The report makes much of its suggested water use for ethanol production in California. However, it fails to account for the fact that virtually all of the corn for ethanol production in California comes from the Midwest, not California. The paper also provided no comparison with respect to other fuel sources and focuses exclusively on ethanol production while ignoring the livestock feed co-product of the process.


CBO report proves ethanol does not contribute to rising food prices A Congressional Budget Office report released April 8 found that other factors, including higher energy costs, had a greater effect than ethanol on increasing food prices from April 2007 to April 2008. According to the report, ethanol contributed “0.5 and 0.8 percentage points of the 5.1 percent increase in food prices” during that period of time. “The impact on food prices of our nation’s push to find renewable alternatives to imported oil is dwarfed by the widespread negative economic impacts of oil itself,” said Renewable Fuels Association President Bob Dinneen. “While ethanol opponents may try to hold up this CBO report as proof of ethanol’s impact on food prices, a close and honest review of the report reveals that many other factors, especially prices for oil and energy, have greater influence over what Americans pay at the grocery store than does ethanol production.” Due to the limitations and scope of the CBO report, it could not factor in the dramatic plunge in both energy and grain commodity prices following the speculation-fueled peaks seen during the summer of 2008. The CBO report also was not designed to take note of the fact that retail food prices have continued to increase or at least remain at near record levels despite these precipitous drops in grain, fuel and other input costs.


BIObytes Ethanol News Briefs

CCRC awarded U.S. DOE grant The U.S. Department of Energy has awarded the University of Georgia Complex Carbohydrate Research Center a four-year $3.1 million grant. The funding will allow the facility, which houses the DOE Center for Plant and Microbial Complex Carbohydrates, to continue to serve as a national resource for

researchers studying the complex carbohydrates of plants and microbes. The center contributes to carbohydrate research in a wide variety of areas, including biofuels. The CCRC’s biofuel research focuses on determining the structure of the carbohydrate that is left behind after a cellulosic feedstock is pretreated.

Magellan, Poet form pipeline partnership

A proposed U.S. EPA greenhouse gas emissions reporting program would affect approximately 13,000 facilities.

EPA proposes GHG reporting program The U.S. EPA issued a proposed finding in April confirming that greenhouse gases (GHG) contribute to air pollution that may endanger public health or welfare. The agency conducted extensive peerreviewed scientific analysis of carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perflourocarbons and sulfur hexafluoride and found

that concentrations of the gases are at unprecendented levels as a result of human emissions. In March, the EPA proposed a national GHG emissions reporting program that would affect approximately 13,000 facilities, including ethanol production facilities. The proposed plan would take effect Jan. 1, 2010.

IEA releases biofuels report The International Energy Agency released a report examining the current biofuels industry as well as the challenges presented for the development and commercialization of secondgeneration biofuels. The report concluded that while the transition to an integrated biofuels industry will likely take up to 20 years and require substantial government support, the indus-


try will grow at a steady rate. The agency estimated that the first commercial-scale second-generation facilities could be operating by 2012. However, before second-generation biofuels can be commercialized, several issues must be addressed, including feedstock costs, production method technology improvements and utilization of co-products.

Magellan Midstream Partners LP and Poet LLC continue to assess the feasibility of constructing a dedicated pipeline to deliver ethanol from Midwest plants to distribution terminals in the Northeast region of the United States. According to Magellan and Poet, in order for the project to move forward the U.S. DOE’s loan guarantee program must be revised. On April 4, the Renewable Fuels Pipeline Act of

2008 was introduced in the U.S. Senate. The bill seeks to amend the Energy Policy Act of 2005 to provide loan guarantees for projects to construct renewable fuels pipelines.

Clemson University, DOE advance partnership Researchers from Clemson University Restoration Institute and the U.S. DOE’s Savannah River National Laboratory are furthering their partnership to study the development and harvesting of South Carolina’s energy crops, including switchgrass, sweet sorghum and pine, as well as crop-processing techniques to yield viable energy and chemical products. Last fall,

the South Carolina BioEnergy Research Collaborative received a $1.2 million DOE grant to build a pilotscale ethanol facility at the Restoration Institute. Other collaborative partners include: South Carolina State University’s James E. Clyburn University Transportation Center, Dyadic International (USA) Inc., Fagen Engineering LLC, and The Spinx Co. Inc.


U of I to offer masterâ&#x20AC;&#x2122;s in bioenergy The University of Illinois at Urbana-Champaign has developed a Professional Science Master degree program in Bioenergy. Beginning in fall 2009, students in the College of Agricultural, Consumer and Environmental Sciences will begin instruction in the program, which combines advanced training in science and mathematics with graduate-level courses in business. The requirements include classes in accounting, econom-

ics, finance, marketing, management/leadership, strategy, human resources and business courses that interface with science. The professional content will be delivered by the College of Business and the Institute of Labor and Industrial Relations.

North Carolina researchers recently received over $800,000 in grant funding to be used for ethanol-related projects.

N.C. ethanol research projects funded The Biofuels Center of North Carolina has awarded several grants for ethanol-related research projects. The University of North Carolina in Charlotte received $150,295 with the Catawba County Regional EcoComplex and Resource Recovery Facility in Newton, N.C., to develop technology to improve cellulosic ethanol production from crop and lumber mill waste. North Carolina State University received over $700,000

for projects including work to characterize industrial sludges from papermaking processes for feedstock potential; evaluating sugarcane and miscanthus performance in North Carolina; developing a sweet sorghum feedstock industry on marginal lands; and a joint project with Lignol Energy Corp. to determine the economic impact of producing ethanol from varieties of pine wood.


This schematic illustrates of the Energy and Environmental Research Centerâ&#x20AC;&#x2122;s on-demand hydrogen technology at work. SOURCE: EERC

EERC receives patent for hydrogen system The U.S. Patent and Trademark Office has issued an allowance for a patent application to the Energy and Environmental Research Center Foundation in Grand Forks, N.D., for a highpressure hydrogen production process that converts liquid fuels, such as ethanol, methanol, and gasoline, to hydrogen at the time of fueling. The process could reduce or eliminate infra-

structure costs for nationwide hydrogen production, transportation, and storage. Researchers have proven the conversion of methanol into hydrogen and are working on obtaining similar results for ethanol and hydrocarbon fuels. The first demonstration of this technology is tentatively planned for Grand Forks in 2010.


With the inclusion of indirect land use change emissions, the EPA estimates typical corn ethanol reduces GHG emissions by 16 percent when compared to gasoline. Without the inclusion of indirect land use change, corn ethanol is shown to reduce these emissions by 61 percent.

EPA issues proposed rule for RFS2 The U.S. EPA released its proposed rulemaking for the second stage of the renewable fuels standard (RFS2) on May 5. The EPA’s proposed rule for the RFS2 expands the scope of the program to include all transportation fuels, including gasoline and diesel intended for use in highway vehicles and engines, as well as non-road locomotives and marine engines. As directed by the Energy Independence and Security Act of 2007, the proposed rule requires that some renewable fuels achieve greenhouse gas (GHG) emission reductions compared to the gasoline and diesel fuels they displace. A fuel pathway is established for each fuel that accounts for GHG emissions produced over the fuel’s full lifecycle, including emissions resulting from the production and transport of the feedstock, production, distribution, blending, use and land use. Indirect land use change effects are also included in the fuel pathways of biofuels. With the inclusion of indirect land use change emissions, the EPA estimates typical corn ethanol reduces GHG emissions by 16 percent when compared to gasoline. Without the inclusion of indirect land use change, corn ethanol is shown to reduce these emissions by 61 percent. Leaders in the ethanol industry have criticized EPA’s inclusion of indirect land use in the proposed rule for RFS2. Accord-


ing to the Renewable Fuels Association, the quantification of land use change emissions included in the agency’s lifecycle GHG analysis of ethanol is highly speculative and driven largely by assumptions. “We welcome an open and robust science-based discussion of the indirect impacts of all fuels,” said Bob Dinneen, RFA’s president and CEO. “The science of market-mediated, secondary impacts is very young and needs more reliance on verifiable data, and less reliance on unproven assumptions. Done correctly, such an analysis will demonstrate a significant carbon benefit is achieved through the use of ethanol from all sources.” While Growth Energy CEO Tom Buis praised the EPA and Administrator Lisa Jackson for soliciting peer-reviewed science on the lifecycle analysis of biofuels for the purpose of the proposed rule, he said it is important to complete further study on the controversial theory of indirect land use change before finalizing the GHG emissions scores for biofuels. “Indirect land use change theory uses speculative models and incorrect assumptions in an attempt to blame American farmers for deforestation in Brazil,” he said. “As the European Union discovered while developing their biofuels regulations, the science on indirect land use is unsettled and the theory is not ready for regulatory usage.” In addition, Buis said that indirect land use change as currently pro-

posed doesn’t allow an accurate comparison of fuels because it does not include the indirect effects of other fuels. “To include indirect effects in regulations without even considering the indirect effects of other fuels would unfairly bias those regulations against biofuels,” he said. Poet LLC CEO Jeff Broin issued a statement regarding the EPA’s announcement in which he expressed concern regarding an indirect land use change penalty for corn ethanol. “While many scientists have found significant flaws in the models used to calculate indirect land use change, I think the very concept is flawed and stems from a lack of understanding of ethanol and agriculture,” he said. “Due to increasing efficiencies in our production facilities and the increased corn yields from the fields surrounding them, we don’t need new land to meet the Renewable Fuel Standard.” The National Corn Growers Association also weighed in on the issue. “In our conversations with the EPA, we understand a great deal of work needs to be done on modeling and a great effort needs to be put into using current and correct data regarding indirect land use,” NCGA president Bob Dickey said. “NCGA will be working closely with the USDA and EPA to ensure scientific data is used.” —Erin Voegele


The U.S. Grains Council organized the first-ever shipment of U.S. distillers dried grains with solubles (DDGS) to Australia in November 2008. After several months of feeding and milling trials, data has shown Australia could be an important DDGS export market for the United States.

USGC expands distillers grains markets to Australia, Chile In November, the U.S. Grains Council facilitated the first-ever shipment of distillers dried grains with solubles (DDGS) to Australia. Hawkeye Gold LLC in Ames, Iowa supplied 45.7 metric tons of DDGS for the project, The DeLong Company Inc. donated trans-loading services and the USGC paid freight costs for the DDGS to be delivered to Australian feed supplier CopRice Feeds. Once there, CopRice used the DDGS to conduct feeding and milling trials on four dairy cattle farms in the South West Victoria and New South Wales regions of the country. Data gathered throughout the feeding trials suggested that DDGS can be included in dairy rations in those regions of Australia with no ill-effects. Farmers who participated in the trials fed cattle including DDGS at rates of between 5 and 20 percent. Milk production was overall unchanged and other parameters such as butter fat and protein did not change significantly. Milling trials offered similar results. It was noted that the U.S. DDGS when used

at 20 percent absorbed more steam than locally-sourced distillers grains, but any issues caused by this during the pellitizing process were brought under control by reducing the steam feed rates. Upon the conclusion of the milling and feeding trials, CopRice determined that U.S. DDGS is a tangible alternative for the company, as long as it is price competitive. USGC Southeast Asia Director Adel Yusupov said the successful feeding trials gives momentum to the long-term utilization of U.S. DDGS in Australia. “If DDGS prove to be price competitive, I predict Australian end-users will incorporate the coproduct into feed formulations,” he said, adding that shipping costs will be a significant factor in the price of the product. Price will also be the determining factor in the expansion of DDGS use in Chile, according to Reid Jensen, USGC Rest of the World advisory team member. Jensen recently traveled throughout Chile with several USGC representatives to conduct face-to-face meetings with local dairy farm-


ers to present the results of positive Chilean DDGS dairy feeding trials. Jensen said the feeding trials proved that DDGS can coincide with the extensive grazing system currently employed by local farmers. Price will determine how much DDGS local dairy producers are willing to use, but Jensen predicted that lower corn prices will result in greater price competitiveness for DDGS. “Chile’s dairy industry consists of approximately 470,000 head,” said USGC international operations senior director Chris Corry. “If these farms were to use an 8 percent DDGS inclusion rate and limit feeding during the lactation period, approximately 295 days per year, the potential demand for DDGS equates to 233,000 metric tons per year.” According to the USGC, Chile currently imports up to 100,000 tons of DDGS annually, but most of the product is used to feed poultry and swine. —Kris Bevill


Aventine blames excess RINs for bankruptcy In an April 8 statement announcing its Chapter 11 bankruptcy filing, Aventine Renewable Energy Holdings Inc. stated that operating margins, high gasoline prices and excess RINs all have negatively affected the ethanol industry. According to Aventine, “Ethanol demand has also been negatively affected by refiners and blenders using excess renewable identification numbers (RINs) to help meet their renewable fuels standard obligations instead of purchasing actual gallons of ethanol.” Aventine was unavailable for further comment on the role of RINs in its bankruptcy. Hunt Stookey, managing director of management consulting firm HighQuest Partners LLC, said he doesn’t believe excess RINs

Ethanol demand has been negatively affected by refiners and blenders using excess RINs to meet renewable fuels standard obligations instead of purchasing actual gallons of ethanol.

have played a significant role in the bankruptcy of ethanol plants. Instead, he said those plants aren’t able to produce more ethanol because there is not enough corn in the market and many producers are going bankrupt because they bought long corn. Stookey’s firm is using a unique model to project how the ethanol industry will be affected by the corn and RIN markets over the next several years that assumes that the ethanol fleet does the demand rationing in the corn market. This means that the purchasing behavior of those buying corn for use in the food, feed and export markets are not responsive to price increases. The ethanol fleet, however, is. Ethanol producers tend to use the balance of the corn supply that is not utilized in these other markets. While there currently are excess RINs in the market, Stookey said those excess RINs that are carried over year to year will be needed to help obligated parties meet the requirements of the RFS in 2009 and 2010. In 2011 Stookey projects those obligated parties will start bidding up the price of ethanol to meet their requirements, which will also bring up the price of corn.

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Clayton McMartin, president of Clean Fuels Clearinghouse, which owns and operates the Renewable Fuels Registry RINSTAR, said Aventine’s claim regarding RINs may be true, but not for the reason Aventine claims. McMartin said excess RINs are not due to overproduction, but instead due to the presence of invalid or duplicated RINs. There are undoubtedly fraudulent RINs on the market, he said. According to McMartin the issue of greater importance is how ethanol producers deal with the RINs they produce. Although one RIN is generated with each gallon of renewable fuel that is produced, each gallon of renewable fuel can be assigned up to 2.5 RINs, he said. This means that a producer making 1 million gallons of ethanol must generate 1 million RINs, however that producer does not have to assign one RIN to each gallon. Instead, the producer could assign two RINs to each gallon of a 500,000 gallon batch, charge for those RINs, and sell the remaining 500,000 gallons of ethanol with no RINs attached.

Instead of simply giving away a RIN with each gallon of ethanol that is produced, a business model focused on supplying RINs to the entities that need them could allow ethanol producers to realize an additional revenue stream. In fact, McMartin estimates that many producers may see more margin in their RINs than in the ethanol they produce. As part of Aventine’s bankruptcy filing, the company and certain holders of its 10.0 percent senior unsecured notes agreed to a first priority secured debtor-in-possession (DIP) term loan totaling $30 million. The DIP loan, which will enable the company to continue to satisfy customary obligations associated with ongoing operations, was given interim approval by the Bankruptcy Court in the District of Delaware on April 16. The interim approval allowed Aventine immediate access to the first $15 million of its DIP financing. The second $15 million of the DIP financing package was scheduled to be considered at a Bankruptcy Court hearing on May 5. ——Erin Voegele



VeraSun asset sale shakes up industry During a bankruptcy court-approved auction sale in March, the assets of VeraSun Energy Corp. were acquired by San Antonio, Texas-based oil refiner and marketer Valero Energy Corp., a group of lenders represented by AgStar Financial Services ACA of Mankato, Minn., German financial giant WestLB AG, and Minneapolis-based investment banker Dougherty Funding LLC. One of the newest ethanol producers in the U.S., Valero is also suddenly one of the largest. But as of press time, the Texas oil refiner was not a member of the organizations that typically represent ethanol producer interests, such as the American Coalition for Ethanol, Growth Energy, the Renewable Fuels Association, and the National Ethanol Vehicle Coalition, all of whom formally petiCommunities across the Corn Belt this spring anxiously awaited the final outcome of the sale of assets from bankrupt ethanol producer VeraSun Energy Corp. PHOTO: G. BIGALOW

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tioned the U.S. EPA to allow the use of up to 15 percent ethanol in gasoline for motor vehicles. Instead, Valero continues to retain membership in the National Petrochemical & Refiners Association, a lobbying group that testified before the U.S. Senate Subcommittee on Clean Air and Nuclear Safety earlier this year that ethanol should not be blended into gasoline at levels higher than 10 percent, suggesting that levels above 10 percent have not been sufficiently tested for their safety. “We recognize that ethanol is going to be an important part of the fuel mix in this country and the renewable fuels standard isn’t going anywhere,” said Bill Day, director of media relations for Valero, “as long as we’re required to buy ethanol, we might as well make it. That’s why we’re in the business. “The amount of capacity that Valero purchased makes us the third leading ethanol producer in the country but, for us, it’s actually a very, very small part of our operations and a small part of our bottom line,” Day continued. “We’re still overwhelmingly a petroleum refiner and not an ethanol producer. “ While Valero’s acquisition of VeraSun’s plants means a loss in members for some ethanol industry organizations, those who depend on ethanol for their livelihood are looking forward to seeing the plants operating again.


“We want it humming,” said Albion, Neb., Mayor James Jarecki. “Everybody in the community is anxious to see it get going— and stay going—to retain jobs, retain revenue, and retain the tax base.” Jarecki said personally, he is pleased that the plant was acquired by a petroleum refiner and marketer, which must acquire ethanol for blending. “If the federal government mandates 10 percent (ethanol) being mixed—if [Valero] can own it—they probably have a competitive edge and so it can be a huge advantage, also. It would more or less be eliminating a wholesaler, in my eyes, and that would be good. It would make [the ethanol plant] competitive. “It’s still a win-win deal all the way around and it helps the farmer, too,” Jarecki continued. “There are a lot of things that you can put in your town that really doesn’t maybe help the ag community much; but this is one thing that does help.” “The communities where we bought the plants are very excited about a company like Valero coming in and keeping the plants in operation and keeping the employees on the job,” Day said. —Ryan C. Christiansen


Railroad companies profit from ethanol While the ethanol industry relies heavily on rail transport to ship its product to various destinations, ethanol has traditionally accounted for a very small portion of the commodities shipped by rail throughout the United States. However, 2008 proved to be a lucrative year for several railroad companies as related to ethanol, and producers are being recognized for adding to their bottom line as well as for their safety standards. In 2008, Norfolk Southern Corp., which operates approximately 21,000 route miles in 22 states and the District of Columbia, assisted in the location of 19 ethanol and biodiesel production and distribution facilities across 10 states. “Renewable energy projects led the way across our service area in 2008,” said Newell Baker, assistant vice president for the company’s industrial development. In total, Norfolk Several railroad companies recently recognized ethanol producers and shippers for their commitment to safe loading practices, railcar safety and maintenance and reducing the number of non-accident releases of hazardous chemicals. PHOTO: ELIZABETH SLAVENS, BBI INTERNATIONAL



Southern helped locate 80 new industries and assisted in the expansion of 35 existing industries along its rail lines. Also in 2008, Providence and Worcester Railroad Co. reported a profit of $166,000, compared to a net loss of $652,000 in 2007. P&W said chemicals and plastics, including ethanol, as well as construction aggregates, were the two largest commodity groups transported constituting 36 and 13 percent, respectively, of conventional carload freight revenues in 2008. P&W customers last year included Aventine Renewable Energy Inc., Cargill Inc., The Dow Chemical Co., and Exxon Mobil Corp. The railroad company is a class II regional freight railroad that operates 516 miles of track in Massachusetts, Rhode Island, Connecticut and New York. Ethanol producers and refiners were among the 40 companies recently recognized by Union Pacific Railroad for their safe-loading techniques, securement of the shipments and non-accident releases. According to the company, since 1994 non-accident releases of hazardous material have declined 57 percent on Union Pacific. Reductions can be credited in part to increased inspections by the railroad’s chemical transportation safety field personnel as well as to the Pinnacle Award criteria established by the rail company. The 2009 Union Pacific Railroad Pinnacle Award winners included: Valero Marketing & Supply Co. and Poet LLC biorefining facilities in Jewell, Ashton, and Emmetsburg, Iowa, and Hudson, S.D. Non-accident releases


make up the largest portion of Union Pacific hazardous materials incidents. The award program is open to all chemical shippers. CSX Transportation, a subsidiary of Jacksonville, Fla.-based CSX Corp., recently announced the winners of its annual Chemical Safety Excellence Award that reflects a winning company’s commitment to rail car maintenance and safety, as well as continuous safe tank car loading. Sixty-four companies that shipped 600 or more railcars on CSXT rails without any accidental releases were recognized by CSXT. “Throughout the challenging economic environment, these CSEA winners have remained focused on the safe loading and unloading of their fleet, and maintaining their fleet in safe working condition. Among the shippers honored were: Abengoa Bioenergy Operations, CHS Inc. Renewable Fuels Marketing, Hawkeye Renewables and Hawkeye Growth, Lansing Ethanol Services LLC, Methanex Methanol Co., Valero Marketing and Supply, Inc., and VeraSun Marketing LLC. CSX provides rail, intermodal and rail-to-truck transload services through an approximately 21,000 mile rail network that serves 23 eastern states and the District of Columbia. —Hope Deutscher


Production, imports up as Europe increases ethanol requirements The European Union Council of Ministers adopted a European Commission legislative package in April that increases the amount of ethanol to be blended with petroleum gasoline in the EU, establishes sustainability criteria for the fuel, and requires petroleum fuel suppliers to reduce greenhouse gas emissions (GHG) for their fuel. The EU plans to increase the share of renewable energy it consumes in the transport sector to 10 percent by 2020. The measures were first proposed by the Commission in January 2008 and were amended by the European Parliament in December. EU member states must now adopt national plans by June 2010 and enact national laws by the end of that year. For ethanol to be counted in the mandate, the fuel must meet sustainability criteria relating to biodiversity, the protection of species and ecosystems, and GHG emission savings, beginning in 2011. Petroleum suppliers are required to decrease GHG emissions over the entire lifecycles of their fuels by 6 percent by 2020, which can be achieved by blending ethanol. Beginning in 2011, fueling stations can


begin offering E10, but E5 must remain available until 2013 for use in older vehicles. The push for more ethanol comes at a time when European production and imports are increasing. Plants in Europe produced 56 percent more ethanol in 2008 than in 2007, a steep increase over the 11 percent boost the industry experienced in 2007 compared to 2006, according to the European Bioethanol Fuel Association (eBIO). EU producers made 2.8 billion liters (740 MMgy) of ethanol in 2008, up from 1.8 billion liters (476 MMgy) in 2007. The increase is due in large part to growth in French production, which nearly doubled in 2008 to 1 billion liters (264 MMgy), up from 539 million liters (142 MMgy) in 2007. Meanwhile, Germany expanded its output by more than 32 percent to 569 million liters (150 MMgy). Spain was the third-largest producer with 317 million liters (84 MMgy). The increase occurred despite declining production in some producing member states. Belgium produced its first ethanol in 2008 while Austria completed its first full year of production. Finland resumed production last year.


Europe increased its imports of ethanol by an estimated 400 million liters (106 million gallons) in 2008 to an estimated 1.9 billion liters (502 million gallons), with most of the ethanol (between 1.4 and 1.5 billion liters, or between 370 and 396 million gallons) coming from Brazil. Increased production and imports of ethanol and biodiesel are a priority for the EU, according to Andris Piebalgs, a member of the European Commission responsible for Energy. Piebalgs addressed the 1st European Bioethanol Fuel Conference, sponsored by eBIO, in April. “Transport [in the EU] depends on oil for 98 percent of its fuel,” said Piebalgs. “That degree of dependence would be a worry, whatever the fuel. It is of double concern given that the fuel in question is oil. “We need to pursue many solutions to this problem; but today, biofuels are just about the only large-scale option currently available to diversify fuel sources in the transport sector,” Piebalgs said.


In Germany, Vereinigte BioEnergie AG reported that for 2008, its ethanol plants produced 270,000 metric tons running at 51.3 percent capacity. The company’s ethanol export business declined 9.8 percent to 19,400 metric tons compared to 2007. U.K.-based Pursuit Dynamics PLC reported in March that it remains confident that its strategy of focusing on the renewable fuels market will produce the best results for the company. During the first quarter of 2009, the company installed its PDX Ethanol Reactor Tower technology at the 40 MMgy Iroquois Bio-Energy Company LLC ethanol plant in Rensselaer, Ind. Also this year, Pursuit Dynamics shifted its research and development focus to improving pretreatment processes for cellulosic ethanol feedstocks. —Ryan C. Christiansen


Canada makes further investments in biofuels Ethanol facilities and research projects recently received a boost from a number of federal and provincial funding sources in Canada, all aimed at accelerating renewable fuel production. British Columbia has pledged more than $32.6 million to commercialize approximately $200 million in provincial renewable energy technology projects. The Innovative Clean Energy Fund has awarded more than $22.6 million to 19 projects and another $10 million in provincial funding will support eight projects to develop cellulosic ethanol, biodiesel, and biofuel technologies that demonstrate low greenhouse gas emissions. The province has mandated that by 2010 gasoline and diesel used in British Columbia must contain a minimum of 5 percent renewable fuel. One of the projects receiving funding was Lignol Innovations Ltd. in Burnaby, British Columbia, which was awarded $3.4 million to produce cellulosic ethanol and other products utilizing forestry residues indigenous to the province. The company will use the funds to

support production runs at its industrial-scale biorefinery pilot plant using forest resources, which will lead to the creation of an engineering design package for a commercial biorefinery within the province. The company also has received $1.82 million from Sustainable Development Technology Canada, a non-profit foundation that finances and supports clean technology developments. Other companies receiving funding included: Northwind Ethanol in Prince George, British Columbia, which received $1.24 million to build a 500,000 gallon woody biomass-toethanol demonstration-scale facility; and Pure Power Global Ltd. in Quesnel, British Columbia, which received $880,000 to design and build a biorefinery in Quesnel that will convert 10 metric tons per day of woody biomass into cellulosic ethanol, lignins and xylose. Canada’s ecoENERGY for Biofuels program, which supports the production of renewable alternatives to gasoline and diesel, recently awarded Permolex Ltd.’s Red Deer, Alberta, ethanol produc-

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tion facility up to $23.2 million. The facility uses feed grade wheat in its initial stages of production and is designed to integrate three traditionally independent manufacturing processes – a flour mill, a gluten plant and an ethanol plant. “I’m very pleased to express our thanks to the government of Canada for its partnership in making this state-of-the-art facility possible, and helping to make sure Permolex remains a part of this community for many years to come,” said Doug MacKenzie, CEO and president of Permolex. Canada’s Agriculture and Agri-Food Canada’s Agricultural Bioproducts Innovation Program is investing $12 million in the Canadian Triticale Biorefinery Initiative research network. Triticale, a hybrid of wheat and rye, contains high yielding potential with disease and environmental tolerance. It is mainly grown for animal feed or forage. CTBI is developing new uses for triticale as an ethanol production feedstock and biomaterials manufacturing source. The network involves 90 scientists from a number of entities working on 30 projects. One of the projects involves Canada’s largest ethanol producer, GreenField Ethanol Inc. and the National Research Council Bio-


technology Research Institute. The two have partnered to improve pentose-fermenting yeast for the production of cellulosic ethanol from triticale and other forms of biomass. The research will occur at GreenField Ethanol’s Center of Excellence pilot-scale cellulosic biorefinery and laboratory in Chatham, Ontario. Canada Foundation for Innovation recently distributed $26.7 million to 116 projects at 29 Canadian institutions. Dr. David Levin and Dr. Nazim Cicek, University of Manitoba biosystems engineering professors, received $400,000 to study improving efficiencies of ethanol and hydrogen synthesis from agriculture and forestry waste. The funding will specifically support a laboratory that will develop a renewable cellulose-based fermentation system for biofuel production. According to the university, the lab will provide a unique opportunity to research alternative fuels in Canada. The CFI is an independent corporation created by the Canadian government to fund research infrastructure. ——Hope Deutscher



Open the Door to Banking Relationships By Peter Martin here has never been a better time to have a positive relationship with your lender. As an ethanol plant manager, you know where you’ve borrowed money but do you have a one-on-one relationship with your banker? Have you met their approver? Consider this relationship from the lender’s perspective. Once the bank approves a loan, they become your business partner and should be in the loop on the ups – and downs – of your operation. From a lending perspective, the ethanol industry might not be the easiest to understand. It is an industry that has caught a bad rap in the past year due to high commodity prices and media reports of bankruptcies and foreclosures. Lenders are skittish about giving money to an industry that is publicly struggling and financing is possibly the single biggest hurdle for ethanol projects at the present time. For these reasons, a personal relationship with your banker is critical. If a loan officer has a misunderstanding about ethanol, they might be bearish about getting involved. However, if you engage them and educate them the odds begin to lean in your favor. Prove that your business can be profitable if managed correctly. Don’t allow your operation to be grouped into a negative aspect of the industry. Inquire about changes in the lenders credit policy and lending authority and how those changes will affect your operation. Ask the same questions of any participating banks. Now is absolutely the worst time to surprise your lender. Be sure to communicate with them about your financial situation. Since most credit facilities are structured by loan covenants including minimum net worth and debt service coverage ratio, you need to fully understand these ratios and their impact on your plant. This is not a time to violate



covenants with a lender, especially if they don’t see it coming. Keeping the communication lines open lets the lender see you are doing everything you agreed to at the inception of the loan. As with any other business partner, keep your banking partner in the loop and don’t be afraid to discuss your books. Raise red flags early so the bank can provide help and discuss options for the future. Remember that your lender has money on the line too and will be willing to help if given the opportunity. However, if challenges are not presented early on it might be too late to offer assistance by the time your lender becomes involved and they will be left with few choices. The bottom line is that people do business with people they like and trust. Your lender needs to have confidence in you and your operation and the best way to do that is to open your doors and bring your banker to visit the plant. Take your loan officer, credit approvers and loan committee members on a ground-floor tour. Introduce them to your employees. Allow them to see you in a management role. All of these things will earn confidence points with your financial institution and give the approvers some buy-in to your operation. There are financial consultants available that can utilize their lender experience, knowledge and contacts to assist borrowers in achieving their end goal. If you are interested in reviewing your existing lending package it could be worth your time to reach out to these types of businesses for assistance. Peter Martin is a finance consultant at Kennedy & Coe LLC. Reach him at or (970) 506-2419.



Foreclosure Alternatives By David Meyer

e have all read about the increased level of foreclosure activity among ethanol producers across the country. However, foreclosure is not the only option for producers who have fallen on hard times. One of the less-frequently discussed alternatives consists of transactions wherein borrowers voluntarily transfer title to their property to their lenders by deed. These voluntary conveyances are commonly referred to as “deed in lieu” transactions.


Benefits of a Deed in Lieu Agreement When a borrower defaults on its obligations to a lender, the lender often ends up foreclosing on the property that secures the loan. Because the foreclosure process can be time consuming and expensive, it may make sense for a lender to accept a deed from the borrower in lieu of foreclosure as satisfaction of the debt. If a lender is willing to accept a deed in lieu of foreclosure, the lender takes title to the property immediately and eliminates the redemption period. By gaining immediate control of the property, the lender can direct its operation, obtain all of its income (if any) and put the property on the market much more quickly. If tenants are operating businesses out of the property, an orderly transfer of title may maintain the value of those tenancies and the businesses. Another advantage to the lender is avoiding the risks associated with litigation. There are a number of reasons why a borrower may be willing to convey title by deed in lieu of foreclosure including to avoid the cost and stress involved in a foreclosure action or to avoid the negative publicity that may be associated with foreclosure. One of the primary reasons a borrower may give a deed, however, is to avoid a personal judgment against the borrower. In exchange for the deed, a lender will generally agree to release the borrower from any further obligations under the mortgage or deed of trust and other loan documents. Similarly, if the loan was


guaranteed, a lender may agree to release the guarantor from any further liability under his or her guaranty.

Typical Provisions in a Deed in Lieu Agreement The actual contract that is executed by the parties is referred to by many different names, including a Deed in Lieu Agreement, an Agreement in Lieu of Foreclosure, or a Settlement Agreement. It is important to note that there is no standard form of Deed in Lieu Agreement. The substance of the agreement will depend on the specific type of property being conveyed and the relative bargaining strength of each of the parties. Lenders generally approach a deed in lieu transaction much like any other purchaser of real estate, including conducting the appropriate due diligence, which may include, for example, title review, environmental testing, surveys, and confirmation of compliance with local zoning ordinances. If the property is improved, the lender may require that the borrower convey not only the real estate, but also any equipment, fixtures and other personal property that is used in the operation or maintenance of the real property. Similarly, if any portion of the property is leased, a lender may require that the leases be assigned to the lender at closing on the deed in lieu transaction. While it may initially seem that a deed in lieu transaction is a relatively simple process for a willing borrower and lender to transfer title to property to avoid a foreclosure, there are risks associated with the transaction that must be carefully assessed by both parties. Also, because there is no standard form of agreement, it is important for borrowers and lenders to consult with their attorneys and other advisors when considering entering a Deed in Lieu Agreement. David Meyer is a partner in Lindquist & Vennum’s Real Estate practice. He can be reached at or (612) 371-3531.


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European Walls he new European requirement to achieve a minimum renewable fuels usage of 10 percent by 2020 as part of the Renewable Energy Directive motivates the oil and car industry to imagine future fuel mix scenarios. Both sectors would like to know how much biofuel will be needed by then as well as how much fuel will be domestically produced and how much will be imported. Car companies are also faced with having to determine how to adjust technology to handle new fuel mixtures. The European fuel quality standard that took effect this month will now allow higher blends of ethanol in fossil fuel. The ceiling has been raised from 5 percent to 10 percent by volume. That is not high enough if one would need to comply with the 10 percent target in the Renewable Energy Directive and regulators will most likely propose a higher biofuel standard ceiling within a few years. Interestingly, the new blending opportunity has already materialized in France, where ethanol producers were desperately awaiting a new blending standard. France finalized its national E10 standard following the political acceptance of the European fuel standard in December. BP was the first to enter the French E10 market, announcing just before April that it would sell E10 at 3 cents per liter lower than its super unleaded 95 petrol. By the end of April, almost all of its 422 service stations in France were set to sell SP95-E10. We will soon see similar moves from E5 to E10 in Sweden, where the E5 market is already saturated, as well as possibly Belgium and Germany. Sweden will return to using E10, as it had prior to joining the European Union. All the other countries will follow over time. Last year in Germany a huge debate on E10 use took place between the government and the automotive and oil industries. The German minister of the environment wanted to push ahead with E10. Oil companies reluctantly agreed to deploy



an E10 filling network guaranteeing enough pumps for the older cars that could not “digest” E10. The German car industry had calculated that about 300,000 cars were not suited for E10. The importers of French and Italian cars had not submitted any data so it seemed defendable to go ahead. In the end the whole scheme collapsed. Why? Because just before the German E10 draft law was to be approved and implemented the car importers (of mainly French and Italian cars) said that 10 times more cars would be unable to use E10. The minister decided to annul the law, knowing that 3 million potentially unsatisfied car drivers would be a political liability. The EU car industry, excluding the flexible fuel vehicle (FFV) producers such as GM and Ford, has always been very much against going over the E5 threshold. It was only in December that the European Automobile Manufacturers Association announced a commitment that from 2010 all new gasoline vehicles would be compatible with E10. Why only from 2010? European models such as Volkswagen, Volvo and Jaguar are sold in the United States and are able to digest E10. Those same models are sold in Europe with no manufacturing adjustments. I witnessed how difficult it is for car manufacturers to think outside the box when we recently discussed fuel scenarios with one of the world’s largest automobile producers. I suggested that for gasoline cars, the solution is as simple as building FFVs to replace gasoline-only models. Manufacturers could simply start doing what all car manufacturers do in Brazil and begin offering flex technology to the consumer. The question, “What’s next beyond E10?” would then be solved. The car people stared at me as if I had made an indecent proposal. Maybe I had. Robert Vierhout is the secretary-general of eBIO, the European Bioethanol Fuel Association. Reach him at





June 2009


E15 The Push for

Growth Energy and other ethanol industry groups made the decision in March to officially file a fuel waiver request for E15 with the U.S. EPA, setting in motion the much-anticipated process to attempt to move the ethanol blend wall. The process is lengthy, but early hints of support from influential parties provide optimism for the industry. By Erin Voegele


June 2009




n an effort to address the E10 blend wall, Growth Energy and 52 ethanol manufacturers and other supportive parties submitted a fuel waiver request to the U.S. EPA on March 6. The waiver request was filed in accordance with section 211(f)(4) of the Clean Air Act and seeks to increase the base fuel blend from 10 percent to 15 percent ethanol. On February 19, Underwriters Laboratories announced it would support the use of up to 15 percent ethanol in certain legacy fuel pumps currently in use. One day later, Susan M. Cischke, Ford Motor Co.’s group vice president of sustainability, environment and safety engineering, wrote a letter to Poet LLC’s Chief Executive Officer Jeff Broin, voicing Ford’s endorsement of efforts to increase base level fuel blend up to E15. The timing of these events has led some to speculate that the announcements made by UL and Ford prompted Growth Energy to submit the fuel waiver request. However Growth Energy Chief Executive Officer Tom Buis says this isn’t so. While the announcements from UL and Ford do help, Buis says


Ford and Poet share a common vision to accelerate renewable fuels use, she continues, and Ford endorses efforts to increase base level blends up to E15. A document attached to the letter further highlighted some key points Ford would like to review Sue Cischke, with EPA regarding the support group vice of appropriate use of renewable president of sustainability, fuel, including the need to expand environment and The Letter next generation ethanol producsafety engineering, Although Growth Energy’s Ford Motor Co. tion technologies. fuel waiver request may not have Jennifer Moore, Ford’s corbeen directly impacted by these actions, Cis- porate news manager, clarifies that the letter chke’s letter did spark a flurry of activity expressed support for E15, but not endorsewithin the ethanol industry. In the letter, Cis- ment at this point. “It would be premature chke thanked Broin for meeting with Ford to to say we are endorsing a move now to discuss renewable energy. “As we discussed, higher blends of ethanol,” she says. “What biofuels continue to be a part of Ford’s over- we endorse is collaborative efforts with key all strategy to address energy security and cli- stakeholders to address concerns with the mate change by increasing fuel economy and use of E15 in our legacy fleet. We need to reducing emissions through the migration of overcome challenges related to higher levels advanced technology that is affordable and of ethanol blends for all vehicles because… accessible for millions of our customers,” she the auto industry designed vehicles around says in the letter. an E10 blend…We are responsible for those the timing of the waiver request was not dependent on them. “The timing was based more on the fact that ethanol producers have run up against that arbitrary regulatory cap of only 10 percent ethanol into our nation’s gasoline,” he says. “[We] need government to raise it in order to let us move forward in clean green energy.”


June 2009


A Step in the Right Direction Nonprofit product safety organization Underwriters Laboratories Inc. recently announced it supports the use of fuel blends containing up to 15 percent ethanol in certain legacy fuel dispensers. Those dispensers, listed to UL 87, previously were rated for use with gasolineethanol blends up to E10. UL Consumers Safety Director John Drengenberg emphasizes two points related to the organization’s endorsement of 15 percent ethanol use in legacy pumps: UL’s endorsement supports the use of up to 15 percent ethanol—not E15. The ethanol content of E10, he says, has been known to vary from 7 percent to 13 percent. “Our research focused on 15 percent,” he says. “And, we are comfortable with that.” UL does not approve the use of equipment, but rather supplies Authorities Having Jurisdiction (AHJs) with relevant safety information to aid in the decision

making process. AHJs are the authoritative body in their respective jurisdictions and make the final call on what fuels are allowable for use in dispensers. UL also has a safety standard in place that is used to evaluate new dispensers for use with fuels containing up to 85 percent ethanol. That standard, UL 87A, was developed two years ago. Drengenberg says UL has no immediate plans to evaluate the use of higher ethanol blends, such as E20, in legacy fuel dispensers listed to UL 87. It is something the organization would consider in the future, he says, but isn’t likely unless federal laws change to allow the use of a higher percentage of ethanol in the base fuel blend.


warranties. How to deal with that is certainly still on the table.” Cischke was not available to comment further on her letter to Poet. According to the supporting document sent by Cischke to Broin, there are several main points Ford is focused on with regards to higher base blends of ethanol in the U.S. sector, including continuing support for the expansion of cellulosic ethanol and reinforcing a vision of ethanol becoming an alternative to gasoline – rather than being limited to a gasoline additive. The document also endorses efforts to increase base level blends up to E15 and to

collaborate with key stakeholders to address concerns regarding use of the fuel in the legacy fleet, while enabling the ethanol industry to expand production and distribution in order to meet energy security and economic goals. According to the document, Ford also recommends establishing a firm planning horizon to support higher level base ethanol blends beyond E15. The automaker says this is necessary to provide adequate lead-time to design, develop and introduce vehicles that are compatible with higher base blends.

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The Waiver Buis says a move to E15 is necessary because it would create jobs, reduce our dependence on imported oil, help the environment and spur development of second generation technologies. “We think it would have tremendous impact,” he continues. “Going from corn ethanol to cellulosic ethanol is a transformation process. It would create the gap necessary to have a marketplace for cellulosic ethanol.” “Going to 15 percent would create 130,000 new green collar jobs, provide about $25 billion into the U.S. economy and displace 7 billion gallons of imported Tom Buis, gasoline each year,” Buis says. It would chief executive officer, Growth also reduce green- Energy house gas emissions by 20 million tons each year, he continues, which is equivalent to removing approximately 3.5 million vehicles from the road. According to Growth Energy, the United States needs to move to higher ethanol blends in order to keep pace with the Renewable Fuels Standard, which mandates the use of 36 gallons of renewable fuel by 2022. A cover letter accompanying the waiver request signed by Broin and Growth Energy Co-chairman Gen. Wesley Clark states that for all practical purposes, we have already reached the E10 blend wall. The letter further states that a saturated E10 market is a primary reason for the U.S. ethanol industry’s current financial condition, and that delaying action in removing the blend barrier would hinder the viability of current ethanol plants and set back the development of viable second-generation fuels. Buis emphasizes that the waiver application does not seek to mandate the use of E15. Rather, it seeks to remove barriers to its use. Broin and Clark’s letter also states that E15 is simply a first step that would solve the blend wall problem in



June 2009


the short term. A path allowing for E15 now, E20 by 2015 and E30 by 2019 would solve the immediate need to overcome the blend wall, while allowing time for appropriate studies and technological developments to occur prior to the introduction of higher level blends.

EPA’s Potential Pathways The EPA is required to take action on the waiver request within 270 days of its receipt. Statutes require the agency to establish a public docket for the petition that was submitted for Growth Energy and issue a Federal Register notice to take comments on the waiver application. On April 1, EPA’s Director of the Office of Air and Radiation Margo T. Oge submitted a written statement to the U.S. Senate Subcommittee on Clean Air and Nuclear Safety regarding the fuel waiver request. In her statement, Oge described three potential pathways EPA believes can be taken in order to meet the RFS. One option cited by Oge is through the increased use of flex-fuel vehicles and increased availability of E85 across the nation. A second option would be through the use of non-ethanol renewable fuels that do not face the same blending limitations as ethanol. The third option would be to approve the use of a midlevel ethanol blend for use in conventional vehicles. In considering Growth Energy’s waiver request, EPA must determine that a move to higher level blends will not cause or contribute to the failure of any vehicle or engine emissions control system or device. The agency must also evaluate the impact of E15 on drivability and durability. The long-term impacts of E15 must also be considered. In her statement, Oge says that one key issue regarding the E15 waiver is whether the waiver should be granted in whole in a conditional manner. This means EPA could restrict use of E15 to a subset of gasoline vehicles or engines, which may result in the need to alter fuel-


ing infrastructure, such as new pump labeling requirements. Growth Energy’s waiver application includes a wide variety of research designed to address the issues EPA must consider. According to Buis, EPA could use that research to approve the use of a lower blend of ethanol, such as E12 or E13, while the agency considers the E15 waiver request. “I am confident that the ethanol industry will be part of a long-term energy solution and key to our independence,” Buis

June 2009

says. “The technological gains that we are making both in cellulose and in reducing energy costs to produce ethanol and the gains in the reduction of carbon emissions will certainly help us make our case to keep moving forward.” EP Erin Voegele is an Ethanol Producer Magazine associate editor. Reach her at or (701) 373-8040.

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June 2009


The California Air Resources Board voted in April to adopt a low carbon fuel standard designed to lower the carbon content of transportation fuels used within the state. As biofuel producers continue to mount an effort to exclude indirect land use changes from the regulation, EPM examines the proposal and speaks with a representative of CARB to learn how ethanol producers may be affected. By Erin Voegele


June 2009




alifornia’s low carbon fuel standard (LCFS) is one component of the state’s overarching plan to reduce greenhouse gas (GHG) emissions within the state to 1990 levels by the year 2020. In addition to lowering the carbon content of transportation fuels used within the state, the regulation also seeks to reduce California’s dependence on petroleum, create a lasting market for clean transportation technology, and stimulate the production and use of alternative fuels. The California Air Resources Board published the proposed regulation on March 5. Ethanol advocates have criticized CARB’s decision to unilaterally assign indirect land use change (ILUC) carbon values to crop-based biofuels, while other fuel sources are evaluated on the basis of direct effects only. Following a formal 45-day commentary period and a final day-long hearing to consider the LCFS, CARB members voted 9-1 in favor of the regulation. The vote included an agreement to convene an expert work group to assist CARB in refining and improving the metric used to measure ILUC. Although some may object to the metric used to measure carbon intensity values, Dean Simeroth, chief of CARB’s Criteria Pollutants Branch, says it’s important to remember that the regulation aims to reduce carbon emissions from fossil fuels. “It sort of gets lost in the concerns about how different parts [of the regulation] are going to affect people, but the real intent of the regulation is to reduce greenhouse gas emissions from gasoline and diesel,” he says. “And to do

that through the use of alternative biofuels and other alternative fuels – such as biogas or electricity. Our real hope is that we get the biofuels we need to reduce the carbon intensity of the petroleum derived fuels.”

How the LCFS Works The LCFS is designed to provide a framework that uses market mechanisms to spur the introduction of lower carbon fuels. To do this, the framework establishes a performance-based standard that fuel producers must meet each year, beginning in 2011. The regulation contains two standards―one for gasoline and its alternative fuels and another for diesel and its replacements. The standards are back-loaded, meaning fewer reductions are required during the first years of the regulation. A back-loaded schedule helps allow for the development of more advanced fuels and technologies and allows CARB some leeway in addressing unforeseen obstacles. The regulation also requires that a mandatory review of the LCFS implementation be completed by the end of 2011. Simeroth says the mandatory review and back-loaded nature of the regulation is important because they will allow the board to fix any problems that are encountered as the LCFS is implemented. “If we have missed something, or something takes a different turn than we expect, we can catch it before it gets very far,” he says. Corn-based E10 and low sulfur diesel represent the LCFS’s baseline fuels. The carbon in-

tensity value of other fuels are measured on a life cycle basis and compared to these baseline fuels. Each year the carbon intensity of any alternative replacement fuel is compared to the LCFS standard for that year. Fuels that have carbon intensity values below that standard generate credits, while fuels with higher carbon intensity values generate deficits. In order to comply with the LCFS for a given year, a regulated party must show that its credits are equal to or exceed the deficits they have incurred that year. The regulation defines regulated parties for gasoline, diesel and liquid blendstocks – which includes ethanol – as the producer or importer of the fuel or blendstock. “An ethanol facility in the Midwest who exports ethanol thinking somebody is going to buy it when it gets here could be the regulated party,” Simeroth says. “As soon as somebody buys [that fuel] from them, then the responsibility goes to the purchaser. It is meant to let us know what is coming into the state and the quality that is coming in. Our real focus is on the providers of those fuels within California.” One benefit of the LCFS is that it does not limit the carbon intensity of individual batches or types of fuel; rather it requires regulated parties to comply with an annual standard for the total amount of fuel they supply. In other words, not all the fuel a regulated party supplies has to meet a particular year’s carbon standard. Instead, the average of all the fuels supplied by that regulated party must meet the standard.


Adjusted Carbon Intensity Values for Gasoline Fuels and Fuels that Substitute for Gasoline Carbon Intensity Values (gCO2e/MJ)

Fuel Gasoline

Ethanol from Corn

Ethanol from Sugarcane Electricity


Pathway Description CARBOB - based on the average crude oil delivered to California refineries and average California refinery efficiencies CaRFG-CARBOB and a blend of 100% average Midwestern corn ethanol to meet a 3.5% oxygen content by weight (approximately 10% ethanol) CaRFG-CARBOB and a blend of an 80% Midwestern corn ethanol and 20% California corn ethanol to meet a 3.5% oxygen content by weight blend (approximately 10% ethanol) CaRFG-CARBOB and a blend of an 80% Midwestern corn ethanol and 20% California corn ethanol to meet a 3.5% oxygen content by weight blend (approximately 10% ethanol) California; Dry Mill; Wet DGS; NG California average; 80% Midwest Average; 20% California; Dry Mill; Wet DGS; NG Midwest; Dry Mill; Dry DGS Midwest; Wet Mill Midwest; Dry Mill; Wet DGS California; Dry Mill; Dry DGS, NG Midwest; Dry Mill; Dry DGS; 80% NG; 20% Biomass Midwest; Dry Mill; Wet DGS; 80% NG; 20% Biomass California; Dry Mill; Dry DGS; 80% NG; 20% Biomass California; Dry Mill; Wet DGS; 80% NG; 20% Biomass Brazilian sugarcane using average production processes California average electricity mix California marginal electricity mix of natural gas and renewable energy Compressed H2 from central reforming of NG Liquid H2 from central reforming of NG Compressed H2 from on-site reforming of NG SB 1505 Scenario; Compressed H2 from on-site reforming with renewable feedstocks

Direct Emissions

Land Use or Other Effect







96.09 (1)



95.85 (1)




50.7 65.66

30 30

80.7 95.66

68.4 75.1 60.1 58.9 63.6 56.8 54.2 47.44 27.4 124.1 104.7 142.2 133 98.3

30 30 30 30 30 30 30 30 46 0 0 0 0 0 0

98.4 105.1 90.1 88.9 93.6 86.8 84.2 77.4 73.4 41.37 (2) 34.90 (2) 61.83 (3) 57.83 (3) 42.74 (3) 33.09 (3)


(1) Calculated value; land use part of the value; (2) Adjusted by an EER factor of 3.0 to account for power train efficiency improvements over gasoline engines; (3) Adjusted by an EER factor of 2.3 to account for power train efficiency improvements over gasoline engines SOURCE: PAGE ES-20 OF CALIFORNIA ENVIRONMENTAL PROTECTION AGENCY AIR RESOURCES BOARD PROPOSED REGULATION TO IMPLEMENT THE LOW CARBON FUEL STANDARD, VOLUME 1, ,STAFF REPORT: INITIAL STATEMENT OF REASONS

Direct and Indirect Emissions The LCFS assigns direct carbon emission levels to all fuels. Direct emissions represent all

the GHG emissions that result from the production, transportation and use of the fuel. For corn-based ethanol these components would


include farming practices, crop yields, harvesting, collection and transportation of the crop, the fuel used in the ethanol production process,

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Legislation Supporting the LCFS April 2006

Executive Order S-06-06 This executive order specified that 40 percent of the biofuels used within the state should be produced within the state by 2020. The proposed LCFS supports this goal by requiring the use of and stimulating the innovation of low carbon alternative fuels. September 2006

Assembly Bill 32 (AB 32) AB 32, also known as the California Global Warming Solutions Act of 2006, established a comprehensive program to reduce greenhouse gas emissions. Under the bill, the state Air Resources Board was assigned responsibility for monitoring and reducing those emissions and was required to adopt discrete early actions in 2007 and approve a scoping plan in 2008. January 2007

Executive Order S-01-07 This executive order established the goal of developing a LCFS to reduce the carbon intensity of transportation fuels by a minimum of 10 percent by 2020. It also identified that the LCFS would be measured on a full fuels cycle basis and be met through marketbased methods. June 2007

AB 32 Discrete Early Action Measures The California Air Resources Board approved the LCFS as a discrete early action measure. The LCFS is one of nine discrete early actions measures adopted by the bill. November 2007

State Alternatives Fuel Plan The California Energy Commission and Air Resources Board approve the plan, which presents strategies and actions that the state of California must take in order to increase the use of alternative non-petroleum-based fuels. The proposed LCFS was an anticipated part of this plan. December 2008

AB 32 Scoping Plan The Scoping Plan identifies how emissions reductions will be achieved through regulations, market mechanisms and other actions. The proposed LCFS is listed as one of the Scoping Planâ&#x20AC;&#x2122;s key measures. March 2009

Proposed LCFS The California Air Resources Board publishes its proposed regulation for the LCFS.


the energy efficiency of the production process, the value of coproducts such as distillers grains, transportation and distribution of the fuel, and combustion during use. The mode used by CARB to define these direct emissions is a modified version of the Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation model that was developed by Argonne National Laboratory. This model, modified for use in California, is known as CA-GREET. Indirect carbon emissions are defined as any other effects that are caused by the change in land use or other market-mediated effects. So far, indirect carbon emissions are set to be assigned only to crop-based biofuels. According to the regulation, ILUC impacts are triggered when an increased demand for crop-based fuels drives up feedstock prices. The price increases cause farmers to grow more of that particular crop. Supplies of these displaced food and feed commodities decline, leading to higher prices. In response, farmers bring nonagricultural land into production in order to take advantage of higher commodity prices. This conversion of land results in carbon emissions. The Global Trade Analysis Project model is used to measure these indirect land use effects under the LCFS. GTAP was developed by researchers at Purdue University, and has historically been used to model complex international economic effects. The model provides an estimate for the amount of global land that is converted to agricultural land as a result of demand for biofuels. To calculate the GHG emissions that result, a set of emission factors are applied to the data. These factors provide an average value for emissions from carbon stored in the ground, above the ground, and the annual amount of carbon sequestered by the native vegetation. Those in the biofuels industry argue that carbon values resulting from ILUC should be excluded from the LCFS until better techniques to estimate the phenomena are available. However, CARB maintains that doing this would delay the development of truly low carbon fuels. It is possible that CARB would consider replacing the GTAP model as more accurate methods to measure ILUC become available. “The basic answer is we’d consider that,” says Simeroth. “Those types of changes in other regulations have happened as better models, test methods, etc., have become available. The nice thing is that it is actually easier for the state of ETHANOL PRODUCER MAGAZINE

California to change a regulation than it is for the U.S. EPA because we’ve got a different basis process.”

The Many Fuel Paths to Ethanol The LCFS uses fuel pathways to estimate the amount of carbon contained within transportation fuels. The regulation currently lists 11 specific pathways for corn ethanol, and one pathway for sugarcane ethanol. CARB is also working to establish three more pathways for cellulosic ethanol and two additional pathways for sugarcane ethanol. “[The additional pathways] are being worked on right now,” Simeroth says. “Our expectation is by December – assuming that we’ve done everything and [the LCFS] is adopted into law – we will have a number of new pathways.” A regulated party can simply choose to use one of these default pathways from the regulation’s Lookup Table to calculate credits and deficits, or can work to establish a new fuel pathway that more accurately gauges the carbon value of a particular fuel. Fuel paths can be added in one of two ways. Under specified conditions, a regulated party can obtain approval from CARB’s executive officer to modify the CA-GREET model inputs to reflect their specific process. This is referred to as Method 2A. A regulated party can also work with CARB to develop a completely new fuel path using the CA-GREET under Method 2B. Both methods require public review under the proposal. “Our hope is that those [new technologies] develop and people come to us with the information and we keep adding pathways to the Lookup Table – not only modification of existing pathways, but also new pathways,” Simeroth says. Although CARB has seen some pushback regarding the LCFS, Simeroth says that is not out of the ordinary. “To me it is what we’d expect on a new regulation this sweeping,” he says. “Everyone is going to have concerns, everybody is going to be worried about how it is going to impact their concerns, but I think [the LCFS] is designed to allow us flexibility in moving forward and reflects what is going to be an evolving situation.” EP Erin Voegele is an Ethanol Producer Magazine associate editor. Reach her at or (701) 373-8040.

June 2009


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June 2009


Generating Power at the Plant:

CHP Boosts Efficiency Next to corn, energy is the second most costly input for ethanol production. By using a combined heat and power system, an ethanol plant can produce electricity and steam with greater energy efficiency and reduce its carbon footprint. By Susanne Retka Schill


June 2009




lectrical power generation has long been recognized as highly inefficient. Two-thirds of the energy fueling the process is wasted as unused heat after high pressure, high temperature steam does its work. When the typical efficiency of electrical generation is added to the typical efficiency of a boiler system providing process heat to an ethanol plant, the combined efficiency is roughly 49 percent. Bringing the power generation to the ethanol plant and making use of the electrical generation’s waste heat in a combined heat and power (CHP) system, boosts that efficiency to 75 percent. Increasing the efficiency of power and steam generation, in turn, reduces carbon emissions. The round-the-clock plant operations and steady steam and power load in ethanol plants make the industry a prime candidate for CHP systems. Bringing the power plant to the user means that the waste heat from electrical generation can be recovered for process heat. The system efficiencies and reductions in carbon emissions are impressive, and depending on a plant’s fuel cost and


electrical rates, can also provide cost savings to the ethanol plant. The U.S. DOE published a CHP analysis last winter that says if 20 percent of the nation’s electrical generation came from CHP systems, the resulting reduction in carbon emissions would be the equivalent of removing 154 million cars from the road— more than half the U.S. vehicle fleet. The paper, “Combined Heat and Power: Effective Energy Solutions for a Sustainable Future,” published December 2008 by the Oakridge National Laboratory, recommends the U.S. boost its CHP use from the current 9 percent of generating capacity to 20 percent over the next 20 years. The paper argues increasing CHP capacity is a cost effective means of reducing electricity’s carbon footprint using a well-established technology that would be relatively quick to deploy.

A Good Fit CHP systems have been around for a century and are used in large industrial settings such as paper mills, refineries, and chemical and metal manufacturing. In the

mid-1990s, the DOE and U.S. EPA realized there could be real benefits if those large CHP systems were downsized for commercial applications such as hospitals, campuses, hotels and medium-sized industrial users. In 1993, the EPA began its outreach to the ethanol industry as a prime candidate for CHP. In addition to promoting the CHP concept, the EPA provides technical assistance such as preliminary system evaluation and permitting assistance. CHP is a good fit for ethanol plants because energy is the second highest cost after corn. A typical 50 MMgy dry mill will have steam loads of 100,000 to 150,000 pounds per hour and power demands of 4 to 6 megawatts (MW), depending on its vintage and mix of operations. The most common CHP technology used in the dozen or so ethanol plants with installed CHP systems consists of a gas turbine electric generator placed in tandem with a waste heat boiler (heat recovery steam generator or HRSG). Natural gas produces steam to drive the turbine that provides electricity for the facility and the turbine ex-


June 2009


haust is used in the waste heat boiler to produce steam for the ethanol process. Interest in biomass- and coal-fired CHP is growing for ethanol plants located near feedstock sources. Central Minnesota Ethanol Co-op at Little Falls, Minn., has a wood-based biomass CHP system, and Riverland Biofuels LLC at Canton, Ill., has a coal-based system. Coal or biomass systems generally include fluidized-bed gasifiers or boilers that can be configured so the exhaust from the driers is routed to become the combustion air in the boilers, effectively controlling volatile organic compound (VOC) emissions and eliminating the need for thermal oxidizers. According to the EPA, CHP can be combined with VOC destruction in other configurations. The thermal oxidizer can be integrated with a waste-heat boiler to produce steam from the thermal oxidizer exhaust. High-pressure steam from the waste-heat boiler is then used in a steam turbine-generator unit to produce electricity, and low-pressure steam from the back end of the turbine is used to meet process heat requirements. Another approach for

VOC destruction is to integrate the dryer exhaust into the gas turbine waste heat generator, then use a secondary supplemental burner to oxidize the VOCs and efficiently generate additional steam for the plant. There are two strategies for sizing CHP units in ethanol plants. One is to use all of the electrical power generated on site because the economics for selling excess generation to the grid are generally not as favorable as utilizing it on site. When sizing the CHP system based on steam requirements, an ethanol plant will generally produce three or four times more electrical power than the plant uses, making a utility partnership attractive. Utility partnerships are involved in CHP systems installed at two Poet LLC ethanol plants in Missouri. The city of Macon, Mo., partnered with Poet BiorefiningMacon to install a 10 MW CHP system. The utility owns the natural gas turbine, while the ethanol plant is responsible for the HRSG. “HRSG’s are a little unique in the setup, but from an operational standpoint they’re like a boiler,” says Rod Pierson, director of plant

operations for Poet Plant Management. “The HRSG is not a lot of extra work, and the goal is to recover as much heat as possible.” The HRSG at Macon recycles waste heat from the turbine into approximately 51,000 pounds per hour of steam to satisfy up to 70 percent of the plant’s process heat. The 45 MMgy ethanol plant also has two natural gas boilers to supplement whatever level of thermal energy is not provided from the CHP. In normal operation, the power from the CHP is fed into the grid. With an electric substation installed on the site, the ethanol plant can disconnect from the local grid should the grid experience an outage and continue operating. Eighty miles southeast of Macon at Laddonia, Mo., Poet Biorefining-Laddonia has partnered with the Missouri Joint Municipal Electric Utility Commission in a 14.4 MW CHP system. The ethanol plant uses approximately 7 MW of power and 75,000 pounds per hour of steam for process heat for the 45 MMgy plant. The utility owns and is responsible for the gas turbine, while the ethanol plant owns and is responsible










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Separate power and heat systems typically use 154 units of fuels to produce 30 units of electricity and 45 units of steam at an overall efficiency of 49 percent. With combined heat and power (CHP), one system could provide the same amount of electricity and steam using only 100 units of fuel, offering an overall efficiency of 75 percent. Because the CHP system uses nearly 35 percent less fuel, it produces lower emissions than the conventional system. EPA estimates a CHP system produces about half the carbon emissions of conventional separate heat and power systems. The emissions reductions can be even greater when replacing aging conventional systems with CHP. SOURCE: EPA CHP PARTNERSHIP

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for the heat recovery boiler and steam system. The ethanol plant and the city formed a unique agreement with each entity paying half the cost of the turbine natural gas consumption. In turn, the ethanol plant recovers the entire waste heat load, resulting in an overall 20 percent annual savings in natural gas costs by the ethanol plant. The city of Macon is decreasing its fuel cost for the generated capacity by 50 percent and, along with the credits it receives for providing the added electric capacity to the local power pool, it has estimated a payback on its investment in the CHP system to be 13 years. In April, the EPA gave the utility commission an Energy Star CHP award for its efforts. In Iowa, the Poet Biorefining-Ashton 55 MMgy ethanol plant has a naturalgas-fueled CHP system that supplies 75 percent of the plant’s steam requirements and 7 MW of electrical power. In southern Minnesota, the CHP system at Poet Biorefining-Lake Crystal generates 1 MW of electrical power for the 56 MMgy ethanol plant. Essentially, the ethanol plants use standard boilers to generate steam at a higher pressure than a conventional ethanol plant’s boiler to produce electricity. Once that work is accomplished, the lower pressure steam is used for process heat. Like Poet’s Lake Crystal plant, East Kansas Agri-Energy LLC in Garrett, Kan., generates 1 MW of electricity from a natural gas turbine. The natural gas boiler produces high pressure steam to generate about one-third of the 35 MMgy plant’s electrical needs, then the lower pressure steam goes on to supply the plant’s process heat. “We save $15,000 a month in electrical bills,” says Doug Sommer, EKAE plant manager. The EPA figures the heat and electricity supplied to the plant requires approximately 23 percent less fuel than typical separate onsite thermal generation and purchased electricity. That in turn reduces carbon dioxide emissions by an estimated 14,500 tons per year, which is equal to removing the annual emissions from 2,400 cars and planting 3,000 acres of forest.


June 2009


Calculating Payback Period The capital cost for installing a CHP system is quite substantial, and the payback period depends upon the energy cost for fuel powering the system and electrical rates. The DOE’s Midwest CHP Application Center published a study in 2007, “Research Investigation for the Potential Use of Combined Heat and Power at Natural Gas and Coal Fired Dry Ethanol Plants,” that delved into the details of installation and energy costs for a CHP system in a 100 MMgy plant. The study concentrated on energy costs in the eight Midwestern states that comprise 80 percent of the nation’s ethanol capacity. It found relatively attractive paybacks for natural-gas-fired ethanol plants ranging from three years in Wisconsin to six years in South Dakota. Coal-fired ethanol plants were even more attractive in the analysis ranging from a one-year payback in Wisconsin to 1.5 years in Nebraska (to access the DOE and EPA’s papers and other information about CHP visit: www. The best time to install a CHP system is when the plant is being built, although retrofits can be attractive as well, according to Bruce Hedman, vice president of energy systems for the consulting firm Energy and Environmental Analysis Inc. The firm has worked with the EPA and DOE in promoting CHP. Hedman says that even though installing CHP when building a plant makes the most sense, in the heyday of the ethanol plant construction boom, the added time for permitting and additional engineering and construction demands made incorporating a CHP system a tough sell. “When times are tight and plants are trying to be low-cost producers, it may be time to look at CHP again,” he adds.

the future, CHP-generated power is likely to increase in value as utilities become required to build clean power portfolios and reduce their carbon emissions. Currently, utilities in 34 states are faced with state-level renewable power standards (RPS) and a national RPS is being considered by the U.S. Congress. Fourteen of the existing state RPS’s qualify CHP using renewable fuels, but only two include CHP using gas turbines, Hedman says. Other new policies have been passed that may tip the balance in favor of CHP. A 10 percent investment tax credit and accelerated depreciation for CHP systems are included in the Energy Independence & Security Act of 2007. The economic stimulus package also contained money for unfunded CHP incentives outlined in the 2007 EISA. Pierson and Sommer say both of their companies are watching the development of carbon markets and legislation. “I don’t see

the point in spending money on infrastructure or even measuring carbon until there is concrete legislation,” Sommer says. As soon as there is, EKAE will be looking for opportunities to participate. Pierson adds that Poet has a team evaluating the potential for participating in carbon markets. Pleased with the performance of CHP, Poet continues to evaluate its potential use at other facilities. “It all depends on local utilities and their need for electrical generation,” Pierson says. ”But as we go east in the Corn Belt, the cost of electricity goes up.” EP Susanne Retka Schill is an assistant editor at BBI International Reach her at sretkaschill@ or (701) 738-4922.

A More Efficient Future “Everyone in the CHP industry is pretty optimistic that even though times are tough, carbon reduction is not going away, and efficiency is key,” Hedman says. “You get enormous efficiency and carbon dioxide reductions from CHP.” In


June 2009




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June 2009


Doing the Math

An Iowa State University sociologist has developed a tool to help rural communities and policymakers understand how volatile corn and ethanol prices might affect the fate of the ethanol industry. By Ryan C. Christiansen


June 2009




igh corn prices and low ethanol prices are bad for the U.S. ethanol industry. For ethanol producers, this recipe for disaster is a no-brainer. However, not everyone outside the industry understands the gravity of this simple math. Even some industry insiders are surprised when they actually put pencil to paper. Take David Peters, for example. He’s an assistant professor of sociology in the College of Agriculture and Life Sciences at Iowa State University in Ames, Iowa. During the summer of 2007, while working as a community economics specialist in the Department of Agricultural Economics at the University of Nebraska-Lincoln for the university’s extension service, Peters assisted communities and local governments with assessing the long-term viability of proposed ethanol plants. “We had a lot of local governments—cities and counties—that had ethanol companies coming to them asking for them to provide infrastructure revenue bonds or property tax abatements and to extend roads, rail lines, and water, sewer and electric lines,” which were expensive propositions for small towns with as little as 500 people, he says. “The question was: ‘If we bond out the infrastructure for 15 to 20 years, what is

the long-term viability of the per bushel for corn, the price ethanol plant? Will we have of ethanol would only have to a stable, long-term revenue tick up another dime to change stream?’ I did some research the entire economics of an and put together this calculaethanol plant.” tor where they can input the Deciphering the Data parameters and assumptions Peters calculates that a and look forward in time to David Peters, typical 100 MMgy ethanol determine profits. The goal Iowa State plant with a typical amount of was to give the communities a University tool that can help them to make assistant professor debt breaks even when corn is of sociology at $3.75 per bushel and ethapublic policy decisions.” nol is at $1.85 per gallon. With That was when corn prices were low and ethanol prices were high. $4 corn the break-even ethanol price is Peters’ calculator hasn’t changed, but $1.90. For every $.25-cent increase in prices have. Peters can easily show you the price of a bushel of corn, the price how high-priced inputs and lowpriced outputs Peters’ calculator allows anyone to input mean losses instead their own data to estimate what the prices of profits, but even he is surprised of corn and ethanol would have to be for at how far things an ethanol plant to be profitable. have gone up and down. “The main thing that surprised me was how sensitive the bottom line is toward changes in of ethanol only needs to go up approxicorn and ethanol prices. Obviously, it’s mately 5 cents per gallon for the plant to intuitive that it would work that way, but break even. If the price of ethanol goes what surprised me is how relatively mi- up an additional 10 cents, the ethanol nor changes either way can lead to profits plant realizes profits in the millions of or losses in sizeable amounts. At $3.50 dollars.


“It’s important for people to understand that the ethanol industry runs pretty lean,” Peters says. “There’s not much fat to trim out of the industry. Corn is the big cost component and most of your revenue comes from ethanol. If either of those changes, there isn’t much you can cut. Distillers grains help, but you’re not in the business of making distillers grains, you’re primarily producing ethanol.” Peters’ calculator allows anyone to input their own data to estimate what the prices of corn and ethanol would have to be for an ethanol plant to be profitable. The calculator, a spreadsheet, models the data for a typical 100 MMgy ethanol plant built in Iowa or Nebraska in 2005. The plant is assumed to operate at 100 percent capacity with an ethanol yield of 2.9 gallons, a distillers dried grains with solubles yield of 19 pounds, and a carbon dioxide yield of 17.5 pounds per bushel of corn. Inputs include 7 gallons of water per bushel of corn and also 1.1 kilowatt-hours of electricity and 35,000 British thermal units of natural gas per gallon of ethanol. The capital costs for construction and equipment are assumed at $160 million with 60 percent financed at 8 percent and 40 percent equity returned to investors at 15 percent. The calculations include labor costs for 45 workers with an average salary of

Breaking Even With debt, the hypothetical 100 MMgy ethanol plant breaks even when: Corn is $3.75 per bushel and ethanol is $1.85 per gallon Corn is $4 per bushel and ethanol is $1.90 per gallon Corn is $4.25 per bushel and ethanol is $2 per gallon Corn is $4.50 per bushel and ethanol is $2.05 per gallon

Without debt, the hypothetical 100 MMgy ethanol plant breaks even when: Corn is $3.75 per bushel and ethanol is $1.70 per gallon Corn is $4 per bushel and ethanol is $1.80 per gallon Corn is $4.25 per bushel and ethanol is $1.85 per gallon Corn is $4.50 per bushel and ethanol is $1.90 per gallon

Source: David Peters, assistant professor of sociology in the College of Agriculture and Life Sciences at Iowa State University in Ames.

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“In general, it’s the price of corn and the price of ethanol that really drive profits,” Peters says. “The only other inputs that might have a [variable] impact on production costs would be electricity, natural gas and water, but those are secondary inputs. Transportation costs are an issue, but they are a relatively small component, because most of the ethanol is shipped by rail, which is relatively inexpensive per ton-mile.”

Ethanol producers are making strides to become more efficient and to squeeze out more ethanol, but this country needs to determine whether it is a national priority. This model can help to give policymakers a rough estimate of what that gap is and what we would need to cover. Besides corn and ethanol prices, another key variable in the ethanol profitability equation is debt. “Timing is everything, as they say,” Peters says. “Plants that maybe broke ground in 2004 or 2005 and went into operation in 2006 are in a better position. We’ve learned about investors getting back double their investments. It was wildly profitable when the Energy Policy Act of 2005 went into effect and the price of ethanol shot up to $2.60 per gallon with corn at almost $2 per bushel. “(However) a lot of plants... are struggling now,” he continues. “They made money, but not enough to retire their debt. Or if they gambled and did a risk analysis and thought the revenue outlook was positive—and paid off their initial capital and wanted to expand—then they are in the same situation with a high debt payment.” In the past few years, when ethanol prices were high and corn low, many plants made enough money to retire their debt early. These plants with no capital debt are now roughly breaking even or losing a few cents on every gallon, according to Peters. “No one has a crystal ball to see the future, but this (spreadsheet) can give people an idea of where prices need to be,” he says. However, corn and ethanol prices haven’t been where they should be. “Things really turned the corner last summer (2008),” Peters says. “I think most plants were buying short-term contracts and were kind of banking that the price of corn wouldn’t go up as much as it did. I think a lot of plants didn’t lock in cheap corn a year or two ahead of time and they were forced to lock


June 2009


in contracts at $5.50 and $5.75. But no matter what contracts they had, the price of ethanol kept falling. The most important advice I have for ethanol producers is to be sure they have a good grain marketer on staff.” Peters says the ethanol industry is partially a victim of its own success. “We were given the [renewable fuels standard] in 2005 and within a couple of years, the industry responded to meet it,” he says. “Then prices began to back off. How can you fault them? They saw the demand and met the challenge.” However, a lot of what has happened is not the fault of the industry, Peters says. “Last year, investors started to look for inflation hedges and started dumping into commodities,” he says. “When the prices were overbid, people pulled back, and we had an economic downturn. Things began to unravel and oil fell. Everyone got caught up in it.” There is a misperception amongst the general public that the ethanol industry is heavily subsidized, Peters says, “but this industry isn’t really that reliant on direct subsidies,” because the volumetric ethanol excise tax credit—also known as the “blender’s credit”—is already factored into the price of ethanol, he says.

More than Money What his profitability calculator doesn’t include, Peters says, are the more intangible profits from producing ethanol: clean air and reducing greenhouse gas emissions. “The benefits for people in larger cities burning ethanol blends and having cleaner air—while not a benefit to the ethanol producer itself—is a benefit to the communities and to government, and to lowering health care costs. People wouldn’t miss as much work and workers would be more productive. We need to look at the benefits of ethanol on a macroeconomic and social scale. It’s hard to quantify.”


Peters says policymakers need to consider price supports for ethanol. “If ethanol is deemed to be a national priority,” he says, “then instead of having a blender’s credit, one of the sanest ideas I’ve heard is to subsidize losses to help smooth out these fluctuations. You need to try to smooth that out because we need to preserve the industry, our rural development, our clean air, and our energy independence. Ethanol producers are making strides to become more efficient and to squeeze out more ethanol, but this country needs to determine whether it is a national priority. This model can help to give policymakers a rough estimate of what that gap is and what we would need to cover. You could boost that up to a point to where at least the plants [are making some profit]. No one is expecting that the government should make the industry profitable, but it should at least ensure there is some guarantee to break even.” The ethanol profitability calculator is just one piece of a much larger set of calculations used to help communities and their chambers of commerce to model the impact of an ethanol plant on their local economies, Peters says, to identify where new job opportunities might materialize and how getting an ethanol producer to agree to buy locally might increase its impact on the community. “From a rural development perspective, this is something that rural communities see that they can invest in,” Peters says. “Ethanol has had a positive impact on rural development, that’s all true. For many towns it was the biggest thing to ever happen, as far as industry. People need to better understand how the prices of corn and ethanol really impact the bottom line.” EP Ryan C. Christiansen is the assistant editor of Ethanol Producer Magazine. Reach him at or (701) 373-8042.

June 2009



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June 2009


The Economics of Distillers Grains For the past decade, as ethanol production has steadily increased so has the production of distillers grains. Now, despite some ethanol plants idling operations, the industry continues to see ethanol and distillers grains production increase. By Hope Deutscher


June 2009




he production and demand for distillers grains continues to grow despite several dozen ethanol plants shutting down and/or reducing production capacity. Simla Tokgöz, international grains and ethanol analyst with the Food and Agricultural Policy Research Institute (FAPRI) at Iowa State University, says recent research conducted by the institute shows that in 2008, 27.7 million tons of distillers grains were produced, up from approximately 23 million tons in 2007. In 2009, that figure is expected to increase to 31.5 million tons. “We have higher ethanol production this marketing year and therefore higher distillers grains production,” Tokgöz says. “It’s the same for domestic use of distillers grains and net exports of distillers grains. In the U.S., domestic distillers grains production has increased this year and the net exports of distillers grains to the world from the U.S. have increased as well.” According to the U.S. Grains Council,

FAPRI’s 2009 Agricultural Outlook shows distillers grains production continuing to grow as ethanol production increases to meet renewable fuels standard mandates over the next several years.

one bushel (56 pounds) of corn used in the dry mill ethanol process yields about 17 pounds of distillers dried grains with soluble (DDGS) for global livestock and poultry industries. One gallon of ethanol equals about seven pounds of DDGS. The Council has been working to establish overseas markets since 2002, and last year's total DDGS exports totaled 4.5 million tons. FAPRI’s 2009 Agricultural Outlook shows distillers grains production continuing to grow as ethanol production increases to meet renewable fuels standard

mandates over the next several years. As well, Tokgöz says domestic and overseas demand from livestock producers who include distillers grains in their feed rations for livestock, such as beef and dairy cattle, hogs, and poultry, will continue to increase. According to the outlook report, U.S. distillers grains exports will increase more than 46 percent over the next 10 years, reaching 6.6 million metric tons in the 2018-’19 marketing year. Top destinations include Mexico, Canada, and Asia, including Indonesia, Japan, the Philippines, South Korea, and Taiwan.


prices really, really closely. Corn prices lead, of course, distillers grains prices just followed and that is because of the substitution of these two types of products.” According to the FAPRI 2009 Agricultural Outlook, growing demand for biofuels, livestock, and dairy will strengthen prices and sustain them at historic highs across all commodities over the next decade. Lower petroleum prices encouraged slower growth in U.S. ethanol production and lower livestock and poultry production contributed to a sharp decline in feed use.


However, because distillers grains is a protein substitute for other feed products, such as corn and soybean meal, the demand among livestock producers will depend on prices. “We looked at the historical data when the first substitutions

Ten years ago, before ethanol production really took off, the supply of distillers grains was relatively small and it was used primarily as a substitute for protein because of its high protein value, says John Lawrence, director of the Iowa Beef Center. With the price of distillers grains tracking fairly close to corn and soybean meal, he says the current distill-

started and historically distillers grains really follows the corn price a lot because they substitute for each other,” Tokgöz says. “After the ethanol production boom, this relationship has not changed. Distillers grain prices still follow corn

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ers grains market is simply ducers) like distillers grains, supply and demand econombut I don’t know very many ics. “And so yes, we’ve had who would not rather feed fewer plants or we’ve had corn, not because of quality some plants shut down, and issues, just because of price. the supply of distillers grains If plants shut down, the price has declined but as those of grains comes back down plants shuts down, it’s kind and it’s more profitable for John Lawrence, of a chicken and egg – they director, Iowa Beef the livestock producers.” shut down in part because of Center When, and if, an ethanol high grain prices and low fuel plant returns to production prices but as they shut down, and begins outputting more more corn is put on the mardistillers grains, Lawrence is ket so farmers didn’t have to buy distill- confident that local producers will reers grains, they could buy corn.” turn to using distillers grains. “What Formed in 1996 through a legisla- we’re hearing on cattle has been an intive mandate, the Iowa Beef Center at teresting evolution. You go back three Iowa State University in Ames, Iowa, or four years ago, I had farmers saying serves as the university’s extension pro- ‘this ethanol plant just opened up in gram to cattle producers providing the my area and they’re trying to give me latest in research-based information to wet distillers grains for free if I’ll pay improve the profitability and vitality of the trucking, should I accept it?’ And a Iowa’s beef industry. year later they are coming back and sayLawrence, who tracks the use of ing ‘I’ve been feeding this stuff all year distillers grains by the livestock industry, from these guys and now they want me says the question of whether distillers to sign a contract for a year to take it. grains will run out is frequently asked. Should I do that?’ And then they come According to Lawrence the answer is back a year later, saying ‘I want to sign simply no. If a local ethanol plant shuts a contract for a year longer to lock in down or reduces its capacity, livestock the price and they don’t want to do producers switch to using more corn that. They won’t guarantee me a supthan distillers grains in their feed ra- ply.’ And now you talk to them and they tions. “Many of them (livestock pro- say, ‘well, some plants are drying it and

selling it overseas, I can’t get anything locally. I’m switching back to corn.’” In 2005, Lawrence says out of 100 Iowa cattle feeders, more than 70 percent who had at least 500 head of cattle were feeding distillers grains. “I would guess it was probably 80 percent in 2008; early 2009, probably more. It might be 100 percent. We are the heart of ethanol, we are the heart of hogs and I think there are a lot of them (producers) using it.” Lawrence says the exception would be the independent farmer who raises his own corn and mixes his animals’ feed. Beef producers will slowly change the percentage of distillers grains ration in their feed, according to Lawrence. “I think what our guys will do is maybe gear up to feed 40 percent, pushing the limits, and get comfortable with that and then as it gets more expensive or they can’t get as much as they wanted, they may not go back to zero, they may say ‘I’ll put 25 percent in the ration. If I get enough and as price sets up, I can cut it back to there.’ Because what happens in cattle is that it has a very high value relative to corn. I’ve heard as high as a 140 percent for the first 10 percent in the ration. Then you go to 20 percent and its worth 120 percent of corn and you get 30 percent in there, maybe it’s



June 2009


worth a 105 percent of the corn. You get up to 50 percent, it’s about equal to corn. Depending on how it’s priced, so if the price of it goes up, they can cut back to 20 percent of the ration, it’s still a good deal for them. But if the price comes down they can push that up to 30 percent, 40 percent or whatever.” Because the renewable fuels standard calls for 10.5 billion gallons of renewable fuel to be produced in 2009 and the majority of that renewable fuel is corn-based ethanol, Lawrence says the supply of distillers grains will continue to increase. However, there is currently lower domestic feed demand from the livestock sector. Lawrence says there are a number of reasons: cattle feedlots have had record losses; dairy prices have dropped; pork producers sustained their largest losses last winter since 1998; last summer’s grain prices hit the poultry industry; and people have changed their eating habits as a result of the current recession. “People are more cautious about what they buy,” he says. “They still eat but they don’t eat out at restaurants. They don’t spend as much - they’ll have hamburger instead of steak, they’ll eat chicken instead of meatloaf - and they’re trying to value shop. So there’s some demand things going on in the economy that’s

hitting the livestock producers as well.” The response by animal agriculture has been to cut back on production. Feedlot cattle, which are the biggest users of distillers grains rations, will continue to be lower in 2010, 2011 and 2012, according to Lawrence.

Historically a Volatile Market There’s been quite a bit of volatility in the distillers grain market, Lawrence says. “On a pound for pound basis, you look at dried distillers grains relative to the price of corn – that has declined over time. We used to be at 115 to 120 percent the price of corn back in 2000 and into 2002, now we’re down under 90 to 94 percent,” Lawrence says. “The volatility has increased a little bit relatively speaking…and that’s the reason why we see farmers will feed it sometimes and other times it’s priced out of the diet, so they’ll wait until it comes back in.” Lawrence says the distillers grains market has been historically volatile for several reasons. “Think about the growth of the distillers grains supply over the past five or six years— it was one of those where supply was kind of outpacing demand. New plants would come on; there would be a good supply so we had to convince more livestock

producers to look at that product.” In Iowa, he adds, cattle producers have been feeding distillers grains to their livestock for more than 20 years. “And there was no problem getting adoption here among cattle but it was suddenly, can we justify feeding to hogs? Well, once we figured out we could, then there were a lot of hogs in Iowa…so suddenly, boom, there’s a big demand for it. Then we bring more plants on and have more supply, well, then it’s what about poultry, well we’ve never tried it before. They start trying it and boom, the poultry comes on and suddenly it uses up that supply.” The domestic success of feeding distillers grains kept growing and led to exporting it to other countries. “I don’t know if we’ve saturated all those markets,” Lawrence continues, “... or if there’s still untapped markets out there…it’s just whether it works today or doesn’t work, it ebbs and flows.” EP Hope Deutscher is an associate editor of Ethanol Producer Magzine. Reach her at or (701) 373-8046.

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ary Wobler was frustrated. The owner of Ag Pellet Energy LLC of Carmel, Ind., had worked for months to come up with a way to pelletize distillers dried grains with solubles, (DDGS); but he always came up just short of producing the perfect pellet— one that would be durable enough to withstand bulk transport, yet pure enough to feed to livestock without hesitation. After consulting with scientists at a few agricultural universities, Wobler was given a list of companies that pelletize agricultural products for feed. At the top of the list was Ft. Worth, Texasbased Landers Machine Co. “Gary just happened to call me first and asked if I thought it could be done,” says Scott Landers, president of Landers Machine. “I said we have quite a background in [pelletizing] and I’ll talk it over with some of my engineers and we’ll see if we can do it. “We started kicking some things around and decided that we would go ahead and give it a shot,” he says, “and so we started our research to try to develop this process and, after probably four months of testing, we had a pretty good feeling that we would achieve something. At that point, we decided that [Landers Machine and Ag Pellet Energy] would form Ag Fuel & Feed.” Landers says Ag Fuel & Feed LLC has overcome the technical challenges associated with pelletizing 100 percent DDGS without using additives or binders. The key to their engineering success has been to design a pellet mill die that has been specifically engineered for pelletizing DDGS. “(After forming Ag Fuel & Feed), it took us probably another nine months of research and then testing and modifications until we actually came up with the process,” Landers said. The production process was developed and test-runs were completed at the Waterloo Mills Co. in Waterloo, Iowa, funded in part by a $49,380 Grow Iowa Values Fund grant through Iowa State University.

Challenges One of the baseline measurements for determining the quality of a pellet is the pellet durability index (PDI), which is determined by tumbling pellets for a period of time to find the volume of fines produced. “We like to see a pellet with a pellet durability index of 92 percent or better,” says Alan Doering, associate scientist of co-products at the Agricultural Utilization Research Institute office in Waseca, Minn., which has been testing to see how U.S. energy crops can be made into pellets for combustion. “You can make pellets that are 99 percent durable,” he says, “but then you typically sacrifice throughput in terms of tons per hour.” Achieving a durable pellet using DDGS is difficult. Comparing figures provided by animal scientists at Ohio State University with information from Encyclopedia Britannica, DDGS has four to nine times less lignin content than varieties of wood. In general, the lower lignin content of non-woody biomass gives it less tensile and compressive strength, according to French agronomist Olivier Pastré in a report for the European Biomass Industry Association. “In the past, you might get [DDGS] to produce a pellet,” Landers says, “but it would have no hardness or a very low PDI and, in handling, they would just completely fall apart, even going from the pellet mill to the cooler.” Landers says DDGS has been successfully used as an additive for feed pellets, “but you’re talking somewhere between 25 and 45 percent addition there,” he says. “Anytime they get any higher than that, they just can’t maintain the pellet.” After months of work, however, Landers says he and his engineers have mastered pelletizing 100 percent DDGS to produce a pellet with a high PDI. The Ag Fuel & Feed pellet has a PDI of 94 percent, he says, compared to a 72 percent average using traditional pelletizing technologies. Wood pelletizes at a 96 percent average PDI.


June 2009



Ag Fuel & Feed has been working with power companies to test burn DDGS pellets with coal. A mixture of 10 percent DDGS pellets was co-fired with coal at Corn Belt Power Cooperative’s Wisdom Station power plant near Spencer, Iowa. Burning a mixture of pellets at 8,400 British thermal units per pound with bituminous coal averaging 10,500 Btu, the test resulted in visually clearer smoke from the plant’s stack.

“The biggest challenge that has to be overcome is the oil content,” Landers says. “With about eight percent oil still remaining in the granular DDGS, it poses a significant problem to conventional [pelletizing] operations. That’s just too much oil to keep bound in a pellet, even a small pellet. “The product is too slippery, too moist, and the oil works against the actual process of holding and compacting the pellet together and then having it stay together,” he continues. “The oil lubricates it so that the granules won’t stay together. In our patent-pending process, we have taken measures to overcome having that amount of oil and, in a way, use it to our advantage to actually help us to make the pellet.”

Lower Expenses The market for DDGS is global and plants typically sell two-thirds of distillers grains dried, but the drying process can consume about 30 percent of the plant’s operating budget. Meanwhile, shipping DDGS to international markets using a combination of rail, con-

tainers and barge has led to transportation costs becoming the third-highest expense for ethanol producers after feedstock and energy costs, according to Frank Dooley, an agronomist at Purdue University in West Lafayette, Ind., and Bobby Martens, a logistician at Iowa State University. Meanwhile, the industry continues to address DDGS flowability issues. Dooley and Martens note that DDGS that has moisture content higher than 10 percent can solidify during shipment, forcing load operators to hammer the sides and bottoms of hoppers to induce flow. This has led railroads to require DDGS to be shipped in hopper cars owned or leased by the shipper. (There was a 25,000-unit increase in demand for jumbo hoppers between 2005 and 2007, Dooley and Martens say.) Dooley and Martens published their observations in an electronic book titled "Using Distillers Grains in the U.S. and International Livestock and Poultry Industries" published by the Midwest Agribusiness Trade Research and Information Center at ISU.

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If ethanol producers were to pelletize DDGS before shipping them, the increased bulk density of the pelletized DDGS would result in transportation cost savings and would alleviate DDGS flowability issues. Ag Fuel & Feed can produce a pellet with a bulk density of 40.6 pounds-per-cubic-foot, 28 percent more dense than un-pelletized DDGS, and the pellets flow “like corn”, according to company president Scott Landers. If ethanol producers were to pelletize DDGS before shipping them, the increased bulk density of the pelletized DDGS would result in transportation cost savings and would alleviate DDGS flowability issues. Landers says Ag Fuel & Feed can produce a pellet with a bulk density of 40.6 pounds-per-cubic-foot, 28 percent more dense than un-pelletized DDGS, and the pellets flow “like corn," he says, better than unpelletized DDGS. Pelletized DDGS might help to open export markets where customers are having difficulty unloading and transporting bulk products, especially DDGS, Landers says. “[Pelletizing] facilitates handling problems,” he says, “because [the pellets] flow much better in screw conveyers and bucket elevators and they would be able to unload rail cars much more easily. “If [ethanol producers] would take a hard look at what savings could be achieved in transportation and handling, I think that our product starts to look better and better,” Landers says. John Fox, an agronomist at Kansas State University in Manhattan and a contributor to the MATRIC publication, says that to expand export markets, the ethanol industry needs to address product variability issues. One way to do that is to sell DDGS as a branded product. An individual ethanol producer might also consider pelletizing its DDGS to differentiate the co-product from others. Landers says cattle producers might see more value in pelletized DDGS. “Pellets in a feedlot are going to be eas-

ier for the cows to consume and to consume fully than when they are dealing with mash,” Landers says. “When they are having mash thrown in those trays, then they slop a lot of it around. Pellets are just easier to consume.”

DDGS Pellets for Fuel As more U.S. states and Canadian provinces adopt or increase renewable portfolio standards for electrical utilities, more power companies are looking at burning biomass pellets in coalfired boilers. AURI has seen a continual growth in interest from industries for pelletizing non-woody biomass over the past six years, spurred in part by sporadic increases in wood prices, Doering says. “[They are] looking at pellet fuels to displace natural gas,” he says, “or looking at densified solid fuels to cofire with coal. We’re working with some utilities, investigating that potential.” Pastré notes that the fluidized bed combustion technology used at power plants is inherently flexible and can burn fuels with a wide range of calorific values, ash and moisture content and they have successfully been used to cofire wood, biomass and waste materials, in addition to coal. Ag Fuel & Feed has been working with power companies to test burn DDGS pellets with coal. A mixture of 10 percent DDGS pellets was co-fired with coal at Corn Belt Power Cooperative’s Wisdom Station power plant near Spencer, Iowa. Burning a mixture of pellets at 8,400 British thermal units per pound with bituminous coal averaging


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June 2009


10,500 Btu, the test resulted in visually clearer smoke from the plant’s stack. “They visually saw an improvement in the opacity of the emissions from the stack,” Landers says, “and that is what was most interesting and significant to them.” Before power companies can use biomass pellets on a regular basis, they must address emissions issues. Pastré notes that compared with wood, agricultural residues typically have higher nitrogen, sulfur, chlorine and potassium content due to increased use of fertilizers, pesticides and herbicides in agriculture. He says agro-pellets should primarily be used in large-scale combustion plants equipped with sophisticated combustion control and flue gas cleaning systems. In a report for Pellets Atlas, dubbed pellets@las, an Intelligent Energy Europe-funded project for the European Union, Martin Junginger, a researcher at Utrecht University in The Netherlands, notes that unknown emissions from biomass pellets is one of the major factors preventing the development of a larger, non-woody biomass pellet market. Landers says while emissions from burning DDGS pellets alone have been quantified, further tests are planned to check the emissions levels when DDGS pellets are co-fired with coal. “Right now, we are working with several different cooperatives in trying to get some more testing (completed) and to get the EPA involved to actually get some tangible figures on the emissions,” Landers says. “If we can get some hard facts, then that would give us some more ammunition to go out to other cooperative generating plants to say that by blending this product, you will see X amount in carbon dioxide emissions.” Landers says Ag Fuel & Feed hired a consultant to quantify the lifecycle carbon dioxide emissions from burning DDGS pellets as fuel to generate electricity. The report determined burning DDGS pellets contributes 38 to 77 times less carbon dioxide than coal on a per-unit basis, even without factoring in the additional carbon dioxide generated from mining and transporting coal to the power plant. The test burn at Wisdom Station also resulted in slightly less power generation, which was expected. “They ran a twohour test and they did see some drop in efficiency at the plant,” Landers says, “just because the coal they were using had about 10,500 Btu per pound, but that was expected, given our Btus.” Landers says the 8,400 Btu measurement is on the low end of the varying Btu amounts DDGS pellets might produce. “We got several different Btu contents from several different batches,” he said, “and I’d rather under-promise and overachieve.” EP Ryan C. Christiansen is the assistant editor of Ethanol Producer Magazine. Reach him at or (701) 373-8042.


June 2009



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Storage Strategies

Demand for wet distillers grains can dip during summer months when feedlots are less active, which allows feedlot owners to take advantage of lower wet coproducts prices. Proper storage techniques can help feedlots to stock up on WDGS and modified WDGS. By Ryan C. Christiansen




June 2009



June 2009




efore blending solubles with distillers grains, an ethanol producer can add a preservative to the solubles to inhibit yeast and mold growth, thereby extending the shelf life of wet distillers grains with solubles (WDGS) and modified WDGS for both the ethanol producer and the local feedlot and dairy operations. WDGS is typically 30 to 35 percent dry matter and MWDGS is typically 42 to 50 percent dry matter. In other words, WDGS can have up to 70 percent moisture content and MWDGS up to 58 percent. Exposed to air, the surfaces of piles of these wet co-products will begin to spoil within three to 14 days, depending on the ambient temperature, according to researchers in the Agricultural Research Division at the University of NebraskaLincoln Institute of Agriculture and Natural Resources. The university collaborated with the Nebraska Corn Board to produce the May 2008 publication "Storage of Wet Corn Co-Products." Ethanol producers typically use preservatives during summer months, which increases input costs for WDGS. At the same time, demand for WDGS can dip during summer months when feedlots are less active. â&#x20AC;&#x153;Typically, the number of cattle


Proper storage techniques can help feedlots to stock up on WDGS and modified WDGS while saving the ethanol producer from having to use more natural gas to dry the product to produce distillers dried grains with solubles.

in feedlots is lower during the summer and so the demand for WDGS is lower. That can lead to lower prices,â&#x20AC;? said Bowe Wingerd, manager of Feedlot Biofuel LLC, a Wichita, Kan., company that has developed a low-volume ethanol plant design for cattle feedlots. However, diminished summer feedlot activity is not the only factor limiting WDGS purchases for feedlots. The UNL researchers also noted that while ethanol producers might prefer to deliver 25- to 30-ton semi-load quantities of wet coproducts to livestock producers, cattle operations with fewer than 1,000 head often find it difficult to use up that much WDGS or MWDGS before spoilage occurs. Researchers in the Department of Agricultural Economics at Purdue Uni-

versity, who published "Distillers Grain Handbook: A Guide for Indiana Producers to Using DDGS for Animal Feed" in December 2008, point out that if the daily consumption of WDGS per cow is eight pounds, a truckload of the wet co-product would last six days for a herd of 1,000 cows. Other classes of livestock that consume less would need to be in much larger herds to prevent WDGS spoilage. Meanwhile, some operations, particularly cow-calf producers, might need to use wet co-products on a seasonal basis. Seasonal demand for WDGS and MWDGS allows livestock producers to take advantage of lower wet co-products prices. Proper storage techniques can help feedlots to stock up on WDGS and modified WDGS while saving the etha-


June 2009


nol producer from having to use more natural gas to dry the product to produce distillers dried grains with solubles. “Hot summer temperatures cause rapid spoilage of WDGS exposed to air, and so it makes economic sense to have viable storage methods,” Wingerd said. How quickly wet co-products develop noticeable spoilage depends upon heat and humidity. WDGS can spoil in weather above 50 degrees Fahrenheit in just a few days. The key to longer storage is to exclude the oxygen, according to researchers at the Iowa Beef Center at Iowa State University, which serves as the university’s extension program to cattle producers. The program publishes the newsletter "Ethanol Feeds: Feeding Distillers Grains to Beef Cattle". The methods for storing wet coproducts are not much different than the methods for ensiling corn silage or highmoisture corn. The UNL researchers said excluding air is key because WDGS are acidic (with a typical pH of 4 to 4.5) and fermentation is unlikely to occur in an anaerobic environment. The main issue with storage is that it is difficult to pile or compact high-moisture co-products. WDGS tends to flow


Oxygen is the Enemy

If the daily consumption of WDGS per cow is eight pounds, a truckload of the wet co-product would last six days for a herd of 1,000 cows. Other classes of livestock that consume less would need to be in much larger herds to prevent WDGS spoilage unless it has been stored.

and spread into wide piles. However, MWDGS does pile adequately and WDG (without solubles) also piles more easily, the UNL researchers said. Dry forages must be added to WDGS to increase bulk for piling. Mixing forage

with WDGS can be difficult because in many cases, the forage will need to be ground first so that it will mix well. According to Pedro Nogueira, a ruminant nutritionist for Kenpal Farm Products Inc. in Centralia, Ontario, one advantage


of storing WDGS mixed with forage is that the blend is easier to break during winter months. Kenpal Farm Products published Nogueira’s article “Storage of Wet Corn Distillers Grains” in its January 2009 issue of “Dairy Briefs.”

Bagging Wet Coproducts MWDGS can be stored in silo bags under pressure. However, wetter WDGS without added forage stored in silo bags under pressure (300 psi or greater) can result in split bags, which usually occurs

within a few days of bagging, according to UNL researchers. Alternatively, WDGS can be stored in silo bags under no pressure, but the method requires more storage area and might result in air pockets within the bags. The weight of WDGS tends to settle bags to a low height with an expanded width. Because the height of a silo bag is a determining factor for storability, adding forage to WDGS helps to improve bag shape, as noted in “Using Distillers Grains in the U.S. and International Live-

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stock and Poultry Industries," published by the Midwest Agribusiness Trade Research and Information Center at the Center for Agricultural and Rural Development at Iowa State University. The MATRIC publication says recommended levels of forage for bagging with WDGS are 15 percent grass hay, 22.5 percent alfalfa hay or 12.5 percent wheat straw on a dry matter basis. The corresponding as-is percentages of the mix for the added forages are 6.3, 10.5, and 5.1, respectively. If too much forage is added, the mixture may become too dry and will not compact well inside the bag and some air may become trapped. WDGS has also been stored in silo bags mixed with DDGS, wet corn gluten feed, soy hulls, corn silage, and beet pulp. The UNL researchers note that forages will need to be ground before mixing and that higher-fiber forages are the best choices for adding bulk and allow for bagging WDGS under pressure. Therefore, forages such as wheat straw and corn stalks work better than forages that are more digestible. The Iowa Beef Center notes that MWDGS can be stored in silo bags for 60 to 200 days. The MATRIC publication cites research that says WDGS can be stored in silo bags for six months to a year.


The solution behind the solution.


Cattle producers who wish to purchase and store larger quantities of WDGS might have or choose to use bunkers. Once again, the UNL researchers note that while MWDGS appears to pile well in earthen or concrete bunkers, some forage will need to be added to WDGS to increase its bulk so that it can be compacted to exclude air. With either co-product, the bunker should be covered to prevent surface spoilage.


June 2009


In a bunker, WDGS mixed with 40 percent grass or 29 percent corn stalks on a dry matter basis, for example, allows for adequate compaction and to hold the weight of a pay loader. Nogueira notes that it is best to pile wet co products on a firm surface, such as concrete, to avoid contamination from the soil and to prevent nutrients from leaching and percolating into the ground. He notes that covering the bunkered co products not only prevents spoilage, but protects the co products from rain, the accumulation of which might result in runoff or a change in the moisture content of the mix. “Even during the winter, covering them is important,” he notes, because WDGS that arrives fresh from the ethanol plant can exceed temperatures of 150 degrees Fahrenheit. “If [warm co-products] are snowed on, this high temperature will melt the snow, resulting in greater effluent losses and increased moisture,” he says.

WDGS with plastic covers is important due to concerns about the dangers of feeding moldy corn grain to livestock. The researchers say samples of stored WDGS have been tested for the presence of various mycotoxins—including aflatoxins, ochratoxins, vomitoxin, zeralenol, zearalenone, T-2 toxin and fumonisin— and only fumonisin was found in any of the samples, but at a low level. It was not clear whether the fumonisins were produced during storage or whether they were present in the corn grain before it

entered the ethanol plant. According to the Iowa Beef Center researchers, species of bacteria can produce mycotoxins on corn and when the grain is processed into ethanol, the mycotoxins are not destroyed, but become concentrated in the co-products. EP Ryan C. Christiansen is the assistant editor of Ethanol Producer Magazine. Reach him at or (701) 373-8042.

Shrink and Spoilage To determine how much wet co product might be lost due to shrinkage, the cattle producer might assume between three and six percent for silo bags and between 10 and 14 percent for covered bunkers, similar to silage storage, the UNL researchers said. The Iowa Beef Center notes studies that say WDGS stored in silo bags with 20 percent hay shrink by 7.2 percent after bagging, compared to 14 percent for corn silage and 9.7 percent for haylage stored in bags. The amount of mold and odor stored wet co products will produce appears to be directly related to the amount of air the co products are exposed to, the UNL researchers said. Bagging WDGS or covering bunkered, compacted


June 2009


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The Forefront of

Enzyme Production As important as enzymes are to the production of ethanol, only a handful of companies specialize in their production. EPM visits with Novozymes, one of the worldâ&#x20AC;&#x2122;s leading enzyme producers, to take a look at the future of enzyme production. By Kris Bevill



June 2009



June 2009




t’s hard to believe that the future of cellulosic ethanol relies on a microscopic enzyme. But don't be fooled by the enzyme’s benign appearance. These miniscule bits of matter have Herculean appetites for change and are capable of setting in motion any number of biological reactions, including the conversion of biomass to ethanol. However, while Mother Nature clearly intended enzymes to be a vital part of life and biological reactions, she left it up to us to figure out the exact recipes for success. In the scientific equivalent of test kitchens, Novozymes scientists in laboratories around the world are constantly cooking up new variations on success. The company became involved in enzyme work related to cellulosic ethanol at the beginning of this decade and received its first U.S. DOE grant in 2000. Since then, the company has made a name for itself globally as a provider of enzymes, and it continues to build on that reputation. Christopher Veit, Novozymes senior marketing manager of biomass, says they began with a very limited amount of research and development committed to developing enzymes for cellulosic ethanol production. “Now it’s the single largest R&D project in the company,” he says. “We have eight years of experience


to fall back on and build upon nol,” she says. “Looking at the when it comes to the training results from our partners, we’ve of our scientists, understanddecided that these products can ing the substrates, the enzyme help others with progressing interactions and so on. There’s their research and developmena lot of momentum that goes tal activities.” into our current efforts, moProduction partners that mentum that comes from the have been testing these enzymes Christopher Veit, experience that we’ve built over Novozymes senior include potential cellulosic leadthe past nine-plus years.” ers such as Poet LLC, ICM Inc., marketing Dedication to the produc- manager of KL Energy Corp., and BBI tion of enzymes for ethanol biomass BioVentures LLC. The variety production appears to be workof producers testing the Cellic ing well for the company. Earlier this year, product family means that the enzymes Novozymes introduced a new enzyme have already been tested on a wide array product family for use in the production of feedstocks. Corn stover, corn fiber, of cellulosic ethanol. According sugarcane bagasse and wood to Novozymes global biomass pulp are some of the substrates business development manager that have been tested, and the Cynthia Bryant, the Cellic prodenzymes have proven to work uct family of enzymes will lead with this line of enzymes. Work to the availability of commercontinues with other feedstocks cially viable enzymes that will as well. The research and develhelp make commercial-scale opment pipeline at Novozymes cellulosic ethanol production a is a long one, but Bryant is Cynthia Bryant, reality. “We actually have been Novozymes global confident that Novozymes will testing these enzymes for a year biomass business deliver on its 2010 promise of with some of our partners be- development delivering a commercially viable manager cause we wanted to make sure enzyme that will enable its partthat our products could make ners’ processes and deliver even a difference for the industry and act as a higher performing enzymes in the future. catalyst for the industry for further devel- “Our partners have faith in Novozymes’ opment and progress for cellulosic etha- capability,” she says.


June 2009


While the Cellic enzymes are available industry-wide under the product names Cellic CTec and Cellic HTec, Bryant stresses that the Cellic enzyme family is not intended to be commercialized. “To us the definition of a commercial enzyme is something that is commercially-viable. These enzymes are definitely a significant step in the right direction toward getting to our 2010 promise of providing commercially-viable enzymes, but they’re not there yet.”

Cost is Key Cost is one of the main focuses in the production of enzymes. Bryant says the Cellic family has the best cost/performance ratio on the market today with an average cost of use of $1 per gallon of ethanol. But costs still need to be cut in half before anyone can use the enzymes to produce fuel on a commercial scale. Novozymes’ researchers are confident they’re on the right track. “One thing we have learned is that we need to look at enzyme costs as the total enzyme cost window and not as the enzyme price per kilogram,” says Bryant. “Until very recently, enzyme costs have always been a gray area. No one’s really fully understood what is in the range of getting into that commercially-viable enzyme cost window.” Novozymes plans to reduce


enzyme costs per gallon to $.50 by next year. The cost window for enzymes Bryant refers to varies greatly and is dependent upon many factors, including pretreatment processes, fermentation processes and feedstocks. Bryant says that through

its research, Novozymes is trying to provide a little clarity for producers on these issues and offer a better estimate of what it will take to produce at a commercial level while at the same time perfecting its own production process. According to Veit, “It’s all about efficiency—develop-

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June 2009




Denmark based-Novozymes’ North American headquarters is located in North Carolina. The company also recently broke ground on a $200 million enzyme production facility in Nebraska.

ing a cost-effective process and at the same time developing better enzymes for less.” Of course, all of this cost analysis research also costs money. The financial requirements necessary to conduct enzyme research and development are significant and Novozymes has secured several federal grants to assist in funding enzyme discovery and modification. In February 2008, the U.S. DOE awarded several companies, including Novozymes, millions of dollars in aid for a project aptly named DECREASE – the Development of a Commercial-Ready Enzyme Application System for Ethanol. Novozymes has its own researchers in California, North Carolina, Denmark and China working on the project as well as outside partners at Cornell University, Pacific Northwest National Laboratory, the DOE’s National Renewable Energy Laboratory and France’s national scientific research center. This research will directly affect the availability of $.50 per gallon enzymes in the near future.

Novozymes’ Next Chapter Determining the enzyme cost window and continuing research and development of technologies are vital parts of the enzyme production recipe, but another vital component is defining the right production model. For Novozymes, that model has become a hub production facility. According to Veit, the idea of a hub model is to centrally locate a large enzyme production facility and enable the facility to



June 2009


'We want to build as close to the industry as we possibly can to minimize our transport costs and some of the costs that go into producing enzymes but at the same time realize all of the benefits that can come from producing on a large-scale and incorporating the new technology that’s being constantly developed.' Christopher Veit, Novozymes senior marketing manager of biomass

be incorporate constant improvements in technology as they come about. In late March, the company broke ground on its first enzyme hub in Blair, Neb., and plans to have it operational in 2011. The $200 million facility will encompass 30 acres of property approximately 25 miles north of Omaha—right near the heart of the Midwest ethanol industry. “We want to build as close to the industry as we possibly can to minimize our transport costs and some of the costs that go into producing enzymes but at the same time realize all of the benefits that can come from producing on a large-scale and incorporating the new technology that’s being constantly developed,” Veit says. By comparison, the on-site enzyme production model would be hindered by limited resources and would have difficulties incorporate continuous improvements to their processes. Veit adds that having multiple small facilities spread across many locations would lead to consistency issues. “One of the things Novozymes takes pride in is that no matter where our enzymes are produced, you’re going to get the same product,” he says. “We want to make sure that continues going forward.” In addition to the expansions being made on U.S. soil, Novozymes North American President Lars Hansen noted in his March stakeholder letter that the company and its Chinese partner, China National Cereals, Oil & Foodstuff Corporation, brought the world’s largest en-


June 2009

zyme facility online earlier this year in Jiangsu, China. Shortly after, the two companies signed an agreement with Chinese oil and energy company Sinopec to develop secondgeneration ethanol from agricultural waste. Hansen told stakeholders in his letter that U.S. and Chinese car owners will be the first to fuel their cars with second-generation ethanol, due in part to the enzyme work being conducted at Novozymes. Confident in the company’s timeline for commercial-scale ready enzymes by 2010, Hansen encourages decision makers to create policies with clear targets for the development of second-generation biofuels. “This is not only the most efficient way to support continued investment in large-scale production, but also continued innovation and improvement of second-generation biofuels,” his letter states. While enzymes are not the only component necessary for cellulosic ethanol producers to scale-up their product, it is an extremely necessary one. Costs may be an issue across the board when considering commercial-scale production, but getting enzyme costs to within a window of possibility will pave the way for other cost issues to be resolved. And for producers who have already been waiting so long, one more year is not much more to wait. EP Kris Bevill is the editor of Ethanol Producer Magazine. Reach her at kbevill@ or (701)373-8044.


Cobs to Switchgrass to Gasoline Parity Partners in a venture taking shape in eastern Tennessee hope to realize the promise of cellulosic ethanol. By Susanne Retka Schill



June 2009



June 2009




eports from a spring U.S. DOE meeting of cellulosic ethanol grant recipients indicate the embryonic industry is bogged down by a difficult financing environment and the challenge of creating a feedstock supply chain from scratch. While a few projects are under construction, others are still working to put the final package together and many DOE-funded projects are struggling to build momentum. In eastern Tennessee, a corporate/state partnership is forging ahead with its vision despite industry-wide problems and has begun the construction of a demonstration cellulosic ethanol facility while its second round of switchgrass seedlings are emerging. The University of Tennessee has been laying the groundwork for this project for several years, conducting a full range of agronomic research on switchgrass varieties, establishment and management and potential conversion technologies and uses. Tennessee’s vision began taking shape as part of the SunGrant Research Initiative, created by Congress in 2003 to establish five regional efforts in biobased energy and product technologies. Several departments in the University of Tennessee, along with the DOE’s Oak Ridge National Laboratory explored feedstock and conversion options. In the fall of 2007, the university’s groundwork seemed to have come to a fruitful juncture when a partnership was announced with cellulosic ethanol developer Mascoma Corp. to build a 5 MMgy cellulosic ethanol plant at Vonore, Tenn. The project, designed to demonstrate cellulosic ethanol technology at one-tenth commercial scale, landed a $26 million DOE grant and the state of Tennessee committed $40 million to the project. But just a year later, in July of 2008, UT announced it had ended that partnership and would be working with the joint venture Dupont Danisco Cellulosic Ethanol LLC.

Shifting Directions With the shift in direction for industry partners in Tennessee, it appears the project is picking up momentum. DDCE’s plans are to build a 250,000 gallon demonstration facility with corn cobs as the initial feedstock at the site near Vonore, Tenn., chosen by the Tennessee Bioenergy Initiative. Meanwhile, the University of Tennessee continues to 108

sign up farmers in a state-funded incentive program to stimulate switchgrass establishment, and is now looking to get a pelleting plant established as an alternative user of switchgrass production while the biorefinery project develops. A ceremonial groundbreaking was held in October at Niles Ferry near Vonore for DDCE’s demonstration plant. The plant is a joint venture with Genera Energy LLC, the corporation formed by the University of Tennessee Research Foundation to manage the collaboration. Construction began in earnest in December on the 250,000 gallon per year facility. “We’re calling it a demonstration instead of pilot plant,” says Georg Anderl, DDCE vice president of engineering. “Because of the strengths that the parent companies have going into this joint venture, at this scale we can go directly to commercial scale without intermediate steps.” By the end of the year DDCE expects to be running cob through the facility, producing the data for the parallel engineering of the first commercial facility targeted to be operational by late 2012. While DDCE is planning to build and operate several commercial plants using its technology, it is not planning to become a major provider of cellulosic ethanol, says Joe Skurla, president and CEO. “We will be entering the market globally as a provider of cellulosic ethanol technology. That will mean licensing, royalties, providing proprietary equipment, maintenance contracts and support.” DDCE has a team already looking for a location for the first corn cob-based commercial facility, likely to be co-located with a corn ethanol plant to make use of existing infrastructure. Once the cob-based process is underway, DDCE will turn to switchgrass, with the first commercial facility to be built in Tennessee. “It’s important to put your money where your mouth is,” Skurla says, “and that makes your mouth more credible.” The commercial facilities are aimed at demonstrating the viability of DDCE’s technology platform and the Vonore facility under construction now will become an applications laboratory for optimizing DDCE’s process for multiple agricultural residues and dedicated energy crops. Unlike many cellulosic ethanol ventures under development, the money backing DDCE is coming entirely from the joint


June 2009



DDCE’s executive team and board members attended the ceremonial groundbreaking last October in Vonore, Tenn. From left, Philippe Lavielle, board member; Joe Skurla, CEO; Tjerk de Ruiter, board member; John Ranieri, board member; Jack Huttner, vice president; Nick Fanandakis, board member; Vonnie Estes, vice president; Georg Anderl, vice president.

venture partners. Each entity is contributing $70 million as well as technology and key personnel. Skurla and Stuart Thomas, DDCE technology director, joined the joint venture from Dupont, while Georg Anderl, vice president of engineering, and Jack Huttner, vice president commercial and public affairs, came from Genencor, a division of Danisco AS. The joint venture is built upon previous collaborations. The Dupont-Tate & Layle BioProducts Joint Venture tapped into Genencor’s enzyme expertise as they developed and built a plant at Loudon, Tenn., to manufacture bio propanediol from corn starch. DuPont sells the bio-based polymer and also uses it in several product lines including fibers, de-icers and detergents. Anderl says DDCE goes beyond the typical joint venture. “We’re not taking technology and throwing it over the wall to a partner,” he says. “We’re developing the technology in an integrated fashion in one technology shop. The coupling of the types of enzymes with the substrate and the pretreatment technology and how we’re processing downstream are not seen as individual operations but an integrated process that we can quickly iterate through to an optimal design. I don’t think that truly exists with anybody else. In its final form, the commercial facilETHANOL PRODUCER MAGAZINE

ity will have everything it needs, including the enzyme production on site. It’s truly a way to get at this in a rapid way with the best possible answer.” The joint venture is structured to draw from the parent companies, Huttner says, “while being deliberate about changing the culture of the two companies to make the joint venture the kind of lean, decisionoriented, action-oriented, good collaborator that we want to be.” For Skurla, a main advantage of the joint venture is being fully funded. “It frees me up to focus on the technology and the business development rather than focusing on fundraising.” Skurla adds DDCE is planning to roll out its technology quickly. “Once we have the data from our demonstration facility, we would expect we would get funding for our commercial facility, we also expect to be in a position to work with early adaptors to provide them with customized licenses to do their own commercial facilities. This is to take advantage of subsidies and early loan guarantees. We view this deployment as starting to occur next year, rather than three or five years down the road.” DDCE plans an ongoing relationship with licensees to share process improvements as the technology develops.

June 2009

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Careful not to divulge too many details, the management team provides an overview to EPM of the DDCE process. Dupont has contributed the thermochemical pretreatment process it has been working on for five years based on a dilute alkaline process. The enzymatic hydrolysis to convert the cellulose and hemicellulose into fermentable sugars is based on the Accellerase enzyme platform developed by Genencor, although DDCE is customizing the enzyme cocktail to integrate it with preprocessing and fermentation environments. The proprietary ethanalogen used in fermentation was developed through a Dupont collaboration with DOE National Renewable Energy Laboratories, based on NREL’s work with Zymomonas mobilis. “It’s a chemical approach that is very energy efficient and also byproduct efficient,” Thomas says. “We’ve taken the path of extensive chemical recycling to minimize the environmental footprint. From a feedstock perspective it is fairly flexible.” “Cob will be first,” Skurla explains, “because it is where we’ve done our work and it has the existing infrastructure. But cob is a finite opportunity. The real development will be in the area of dedicated energy crops, which brings us to switchgrass and that brings us to why we’re doing work with Tennessee.” Skurla sees a potential for dedicated energy

crops to change economics in rural areas and possibly change the dynamics of the ethanol market as cellulosic ethanol production develops outside the Corn Belt.

Targeting Marginal Land There is little corn in east Tennessee where DDCE is building its facility. The most common crops are hay, soybeans and wheat. To diversify and strengthen the agricultural economy, the state is backing the development of dedicated energy crops in the region through an $8 million investment in a farmer incentive program. Most of the 750 acres signed up in the first round of farmer contracts last year were cropland since there was little time for field preparation. Also, the number of acres was limited by seed availability. “We had very good success with the first year switchgrass production we harvested beginning in November,” says Kelly Tiller, co-director of UT’s Office of Bioenergy Programs and president and CEO of Genera Energy. “We had almost a 90 percent success rate in establishment which is higher than we expected,” she says. “The first year average was a little over two tons per acre.” UT agronomists researching switchgrass production had projected the first year yields would average between 1 and 2 tons per acre, between 5 to 6 tons per acre in the second year and 8 to 10 tons in the third and subsequent years.


June 2009


The first year production has been baled and moved to a central location where it has been covered with tarps for storage. The success from the first year of the program led to 3,500 acres being offered for enrollment in the second year, of which 1,950 were selected, all within a 50-mile radius of Vonore. “One thing we are trying to do in this program is get a good cross section of a lot of different conditions,” Tiller says. “We’re looking not only at soil productivity and soil types, but slope, previous cropping history and weed pressure – also managerial expertise and equipment available. We have used all of those in our selection criteria for participation in the program to try to give us as a broad of an experience as we can with all of these factors.” The smallest acreage allowed is 15 acres per farm, although that can be broken into smaller fields. Based on economic analysis done in earlier research, UT established a price of $450 per acre, which amortizes the cost of switchgrass establishment over the three years of the contract. It is an attractive, yet risky option for farmers, Tiller says, as there is no guarantee of a market when the contract ends after three years. As UT extension service works with farmers in planting and establishing the switchgrass, agronomic studies continue along with work on storage issues, with equipment manufacturers on harvesting and handling, and preprocessing issues. “We’re putting together the engineering systems to get the quantity and quality you need at a price you can afford,” Tiller explains. The goal is to get the switchgrass to the bioenergy user at $60 per dry ton. “We’re not there right now, but we do see where there is lots of room for improvement in reducing those costs.”

integrated into the economics throughout the value chain. On top of that you have to impose the life cycle analysis as well to ensure you are managing the carbon molecule to its optimal advantage.” Skurla says the DDCE vision is to reach gasoline parity. “We’ve done the modeling in terms of expected crude oil prices, expected biomass prices, expected costs of conversion. Our focus is not to be competitive with starch ethanol, although we will be. Our focus is not to become a desirable biofuel, although we

will be. Our focus is to become an alternative for the consumer to make the choice of what they will put in their vehicles. With oil at about $80 a barrel and technology development of the path where we anticipate it to be – this is a learning curve, of course – sometime within the next decade, this industry will be at gasoline parity.” EP Susanne Retka Schill is an assistant editor at BBI International. Reach her at sretkaschill@ or (701) 738-4922.

Gasoline Parity “We need to look at the entire value chain and understand how you can squeeze the most capital and cost out, and increase the wealth created,” Skurla says. “The citing of the plant, the treatment of the biomass whether it’s chopped up finely or coarsely, whether it’s compacted or not, has to be


June 2009



Ethanol in Armenia The Renewable Resources and Energy Efficiency Fund of Armenia recently commissioned a feasibility study to determine the possibility of producing ethanol in Armenia. The study, financed by World Bank as a grant from the Global Environment Facility, was conducted by Enertech International Inc. and BBI International in cooperation with DHD Contact LLC of Armenia.


s a land-locked country without any significant deposits of crude oil, Armenia is 100 percent dependent upon fuel imports to meet a growing demand for gasoline. Increases in world crude oil prices are being passed on to and reflected at retail gasoline outlets, and prices for gasoline in Armenia are expected to increase at an even more rapid rate in the future, as long-term import contracts lapse and are renegotiated at higher market

One of the key factors for determining the overall success of a biofuels program is the availability of appropriate feedstocks at attractive prices. Corn and sugarcane serve as the major feedstocks for current ethanol production throughout most of the world, but virtually any feedstock with high sugar or starch content can be utilized for ethanol production. prices. Natural gas prices from Russia are expected to increase making compressed natural gas (CNG) more expensive and

causing upward pressure on gasoline prices as well. Such trends will make alternative motor transport fuels such as ethanol

more competitive in the market. Finally, ethanol for blending as a motor transport fuel has the potential to reduce imports of gasoline through displacement, reduce foreign exchange drains, increase energy security of supply in a traditionally unstable region of the world, create value from domestically grown ethanol feedstocks on surplus lands, create jobs in depressed rural areas, and improve local air quality particularly in congested urban areas.

The claims and statements made in this article belong exclusively to the author(s) and do not necessarily reflect the views of Ethanol Producer Magazine or its advertisers. All questions pertaining to this article should be directed to the author(s).



June 2009

Feedstocks One of the key factors for determining the overall success of a biofuels program is the availability of appropriate feedstocks at attractive prices. Corn and sugarcane serve as the major feedstocks for current ethanol production throughout most of the world, but virtually any feedstock with high sugar or starch content can be utilized for ethanol production. Armeniaâ&#x20AC;&#x2122;s climatic conditions are not suitable for sugarcane production; however, there are several alternative crops suitable to Armeniaâ&#x20AC;&#x2122;s climate for cultivation on available agricultural land that is not intended for the production of food crops. In particular, Jerusalem artichoke has been identified as a crop with great potential as a feedstock for ethanol production in Armenia in the near to midterm future. It can be cultivated on land that is currently fallow and it possesses relatively high carbohydrate content, especially in its root tuber, thereby making it extremely suitable for ethanol production. Farmers grow Jerusalem artichoke for their own use, but there is no large scale production due to the small market for it. Similarly, feed corn for livestock and poultry is a suitable crop for the soils and micro climates found in several parts of the country. Utilizing a dry mill corn fractionation process, feed corn can be processed in such a manner as to extract all of the starches contained in the feedstock corn for conversion into ethanol while at the same time producing important animal feed co-products. The byproduct

Table 1 â&#x20AC;&#x201C; Forecast of Ethanol Production Required to Achieve Selected Blending Levels (in thousands of metric tons per year) Year Indicator 2009







































will have a higher percentage of protein, fats and carbohydrates than that found in unprocessed dry corn, which is currently the principal animal feed used by livestock and poultry producers in Armenia. Similar byproducts can also be produced using Jerusalem artichoke. Presently there is no large scale feed corn production in Armenia, but the Ministry of Agriculture has developed a program of increasing production to reduce the import and to develop a local market for feeding livestock. The goal is to have 14,826 acres of corn production in Tavush Marz in northern Armenia. The program has seen limited success. Where farmers use good techniques, the yields have been satisfactory, but in many cases the yields have been far below what would have been expected. The preliminary feasibility study suggested developing two very different types of ethanol plants: one based on an inulin extraction process for Jerusalem artichoke to be situated in Syunik Marz; and a second plant


June 2009

based on a dry milling process with fractionation utilizing feed corn grown in Tavush Marz. These two regions have high rural unemployment rates and microclimates suitable for the production of the identified feedstocks. There are a number of advantages and disadvantages that should be recognized from the outset when considering a decision on whether or not to implement a nationwide ethanol program. With respect to advantages, ethanol can be produced from domestic renewable feedstock sources, helps to stimulate agricultural employment in depressed rural areas, and can provide farmers and ethanol processing plant owners with a dependable revenue stream. In addition, ethanol can lower air emissions in major metropolitan areas when combusted as a motor transport fuel, can reduce overall greenhouse gas emissions, and can reduce foreign exchange drains on the Armenian economy. On the other hand, a nationwide ethanol program could

face several hurdles and challenges. Ethanol has a lower energy content value compared to gasoline and could face an initial public acceptance hurdle. In addition, ethanol blends greater than 10 percent are not compatible with existing non-flexible fuel vehicles, pipeline infrastructure, distribution systems, or tanks and pumps at retail outlets. If the imported gasoline is not of a high quality or contains moisture, there will be performance and maintenance problems with automobiles that are operated on fuels mixed with ethanol, and the program will in all likelihood be perceived as a failure by the consumer public. In addition, no markets currently exist in Armenia for useful animal feed by-products from ethanol conversion processes. Potential Ethanol Market Size Table 1 (shown above) forecasts the ethanol production needed annually to achieve the 5 percent blending levels, by volume, with gasoline. These projections formed 113

ARMENIA. the basis of the decision to develop 14,000 metric tons per year of ethanol production capacity by 2014. Therefore, the recommended capacity sizes for each of the two proposed plants is 7,000 metric tons per year based on the assumption that the Armenian government would mandate 5 percent blending of ethanol by volume with gasoline by the year 2014. Construction of a 7,000 metric ton per year ethanol plant would cost $17 million to $19 million (2008 dollars) depending upon specific conversion technology chosen by the developer. The major variables for the financial analysis of a biofuel project are ethanol price, feedstock price, co-product price and energy costs. Due to the lack of reliable price information for the proposed feedstocks (Jerusalem artichoke and corn), the financial analysis was necessarily conducted by setting an acceptable rate of return on investment


and solving for the cost of the feedstock that would generate this return over time. A variety of scenarios was analyzed to assess the sensitivity of the projected results to the different assumptions. If yields are around 40 to 45 metric tons per hectare, pricing for Jerusalem artichoke is expected to be approximately $50 per metric ton as farmers move towards more modern production practices. The financial model showed that the processing plant can pay up to $88 per metric ton for Jerusalem artichoke and still achieve a return on investment of 15 percent. The 2008 price for imported feed corn into Armenia was approximately $400 per metric ton. This price is significantly above the world market price of corn, likely at least in part due to high transportation costs and small trading volumes. Results of the analysis indicate that while higher yield seeds are now being used by local farmers, the

upward pressure on corn production costs especially from the higher cost of fertilizers, weed suppressants, and diesel fuel for tractors is offsetting enhanced revenues from higher crop yields. Farmers will have to beat this price if they hope to enter into long-term contracts with an ethanol processing plant. However, given that the financial model was set to achieve a minimum ROI of 15 percent, financial projections indicated that the processing plant could only afford to pay up to $393 per metric ton for feed corn and still remain attractive to potential investors. Based on these results and competitive guidelines, either plant could provide sufficient economic returns. The risk is perceived to be greater with Jerusalem artichoke due to the lack of commercial production experience, cost data regarding cultivation and harvest, and historical pricing data in the commercial marketplace. However,

in the final analysis, such risks are common to any new dedicated energy crop. Land Availability for Feedstock Production On average, only 70 percent of tillable land in Armenia is presently being used. Guiding principles for identifying suitable land during conduct of the ethanol program assessment were to:  Focus on surplus lands only  Consider lands from the Soviet era that are not presently being utilized for food production and unlikely to ever be brought back into useful production  Primarily concentrate on marginal lands between 1,000 and 2,400 meters in elevation or else saline soils that cannot be utilized for food production regardless of elevation  Rule out lands that are not accessible by mechanized farm equipment or include en-


June 2009

Considering all of the potential ethanol fuel cycle environmental aspects, it can be concluded that the project will have a favorable impact on the environment in Armenia. The main positive aspect of the proposed project will be the reduction of air pollutions.

carbohydrate animal feed as well as feedstock for combined heat and power systems. Potential coproducts from a corn fractionation plant include DDGS and corn oil. In addition, both processing plants are expected to produce dry ice and liquid carbon dioxide as coproducts.

dangered species of plants or animals An extensive study was conducted to determine the best locations for growing acceptable feedstocks from the perspective of prevailing climatic conditions, soil suitability, elevation constraints and possible access to irrigation. It is anticipated that the local farmers, not agri-businesses, would be responsible for planting and growing feed corn. Harvested feed corn would then be stored in humidity-controlled storage containers or buildings for use throughout the season. A study of available land for

Anticipated Developmental Impacts Rural development is another important driver for worldwide support of biofuels. Since feedstocks are grown on agricultural land, increasing demand results in increased economic development in rural areas; however, biofuels policies have faced increased scrutiny in recent years. The two most controversial topics are the food versus fuel issue, and the actual level of environmental benefits accruing from ethanol programs. In Armenia, only unused marginal lands or surplus will be utilized and only non-food feedstocks will be grown for conver-

corn growing shows there is the capability to produce the required amount within 50 km of the proposed plant. Potential Coproduct Markets The sale of coproducts from a planned ethanol plant is essential to ensure the economic viability of such a project, especially if no direct financial subsidies will be provided by the government to guarantee an ethanol programâ&#x20AC;&#x2122;s success over time. Potential coproducts from a Jerusalem artichoke plant include pulp to be used as a high


June 2009

sion into ethanol, unlike major ethanol programs in the United States, Europe and Brazil. Moreover, the proposed projects are expected to have significant and positive developmental impacts and benefits to Armenia. The most important benefits include:  Stimulation of Employment in Depressed Rural Areas. An ethanol feedstock production program of this magnitude will have an instant and measurable positive economic and job creation impact upon the two most depressed parts of Armenia.  Human Capacity Building. Most of the construction work would be provided by local Armenian contractors- overseen by an international contractor with experience in ethanol plant construction. New jobs would be created both directly and indirectly. These jobs will require new skills and training to operate and maintain the two plants.  Technology Transfer.



Environmental Impacts Considering all of the potential ethanol fuel cycle environmental aspects, it can be concluded that the project will have a favorable impact on the environment in Armenia. The main positive aspect of the proposed project will be the reduction of air pollutions. With a nationwide program goal of 5 percent ethanol blending, it is anticipated that carbon dioxide emissions will be reduced by 3,300 metric tons per year or by


There has been little experience with ethanol processing plants for Jerusalem artichoke on a major commercial scale. Only small demonstration facilities using Jerusalem artichoke have been implemented to date. In a sense, this project will create a whole new industry in Armenia.  Economic Development Benefits. Substantial tax revenues would be generated, as well as money spent in local rural economies.

The Tavush Marz area of Armenia was determined to be well-suited for a dry mill corn ethanol facility.

at least 15 percent of the level of such emissions in 2007. Considering a projected increase in the number of vehicles that will be added to the current stock in the future, this anticipated emissions reduction will have a ten-

dency to increase over time. Other environmental concerns are mostly related to land use changes triggered by higher agricultural product prices. By historical averages, current prices for commodities

such as corn and soybeans are high. The higher prices provide an incentive to increase production, which in many cases means expanding the amount of land used for agriculture. If the expansion land is currently

1-800-827-1662 •


forested, turning it into arable land will require deforestation resulting in environmental harm which will likely outweigh the benefits of biofuels for many years. However, ethanol production as envisioned for Armenia will result from greater utilization of unutilized crop lands or marginal lands and not result in reductions of forested lands. Suggested Policy Measures for Consideration Suggested government energy and transportation policy measures to stimulate ethanol market development in Armenia include the following:  Develop a fuel standards program by 2009  Mandate a minimum fuel blending program at 5 percent by volume by 2014 coupled with an excise tax on imported ethanol in an effort to create a new industry

Jerusalem artichoke has been determined to be a feedstock with great potential for ethanol production in Armenia. Farmers currently grow the crop for their own use on a small scale.

 Increase mandated blending requirement to 10 percent by volume by 2020  Classify ethanol as a motor transport fuel for tax purposes rather than as ethanol for use in alcoholic beverages  Institute vigorous enforcement of fuel quality stan-


June 2009

dards testing at fuel depots and retail outlets  Treat ethanol as a renewable energy resource  Develop and implement a nation-wide public awareness program to introduce and promote the production and use of ethanol EP

Kendrick Wentzel participated in the study as a project manager for Enertech International. Reach him at enertech@friend. Areg Gharabegian participated as the environmental and biomass specialist. Reach him at areg.gharabegian@parsons. com or (626) 440-6047.



Project Financing in Difficult Capital Markets Acquiring financing for ethanol projects is more difficult now than ever before. Fortunately, there are many types of government grants and loans available to assist future producers.


he biomass industry, including cellulosic ethanol, represents an exciting new area of opportunity in renewable energy. As an emerging industry, there remains a lot of uncertainty around feedstock costs, supply, aggregation, technology, and off-take contracts. Project finance, difficult in the best of times, is especially challenging

in todayâ&#x20AC;&#x2122;s capital markets. The bright side is the amount of money flowing from the federal government into renewable energy in the form of grants and loan guarantees. The American Recovery and Reinvestment Act (ARRA or the stimulus package) has allocated billions to renewable energy, and biomass and cellulosic ethanol are key focus areas. By leveraging these grant,

loan guarantee and tax incentive programs, as described below, it is possible to get a well-planned and organized biomass project funded today. These government programs will bridge the gap in funding biomass projects until the industry matures and traditional capital becomes available. The stages that projects go through in the financing life-

cycle and the types of capital available at each stage are include pre-development capital, development capital and project debt financing.

Sue Wyka, partner, Ascendant Partners Inc. and Ascendant Financial Partners LLC.

The claims and statements made in this article belong exclusively to the author(s) and do not necessarily reflect the views of Ethanol Producer Magazine or its advertisers. All questions pertaining to this article should be directed to the author(s).



June 2009

One of the best alternatives in todayâ&#x20AC;&#x2122;s market is to pursue federal government guaranteed loans. There are many programs that provide government guaranteed loans through the farm bill, the energy bill and the American Recovery and Reinvestment Act.

Pre-Development Capital The first phase in the lifecycle of a project is pre-development. Pre-development capital or risk capital is the first money raised in a project and, in the overall scope of the project, is relatively small. These dollars are used to determine the feasibility of the project. This can be the toughest to find or the easiest. If the founders have capital, are well connected locally and/ or the project has strong appeal locally, bringing in local investors can be less difficult. Development Capital Development capital is used in several areas, including business planning, land acquisition, engineering, contracting with vendors and contractors. The same attributes that bring in pre-development capital can make raising development capital easier. Most project developers find it very difficult to raise development capital as the dollars are larger (up to several million dollars depending on the size of the project) and the risk is still very high. In stronger economic times, local inves-

tors and agricultural producers were willing to fund renewable energy development efforts locally. Friends, family, and local/ regional angel investors are still the most viable capital alternative at this point in the development cycle. Strategic investors with a reason to invest such as off-take or supply arrangements are worth pursuing as well. With the amount of federal dollars available under the farm bill, energy bill and stimulus bill, grants are worth pursuing to fund pre-development and development tasks. Federal grants that are available to renewable energy projects include Section 9008 grants (joint USDA and U.S. DOE) for advanced biofuels (non-corn cellulose) research and development and demonstration plants. The deadline for the initial round for these grants has passed, but it is expected that additional grants will be announced this year. Other DOE grants and USDA grants such as biomass research and development, Renewable Energy for America Program grants, and value-added producer grants will also of-


June 2009

fer funding opportunities. It is important to monitor funding announcements at www.grants. gov as well as state programs at Project Debt Financing Once the development equity has been raised, the next step is to find debt financing. One of the best alternatives in todayâ&#x20AC;&#x2122;s market is to pursue federal government guaranteed loans. There are many programs that provide government guaranteed loans through the farm bill, the energy bill and the American Recovery and Reinvestment Act. The U.S. government, through various agencies, provides the underlying guarantee but loans are made by private commercial lenders. The lender must underwrite the loan and present it to the government agency for its approval to provide the guarantee. Lenders set the terms but must work within program parameters. There are a limited number of lenders that understand and are willing to work with these programs. The process can be tedious and time consuming. Feasibility studies are generally required for all government loan programs. The government guarantees do not become effective until the project is complete and in operation; therefore, a construction loan must be procured. The major loan guarantee programs available for biomass projects are:  USDA Business & Industry Guaranteed Loans (B&I Loans)

http://www.rurdev.usda. gov/rbs/busp/b&i_gar.htm  USDA Renewable Energy for America Program (REAP) Guaranteed Loans http://www.rurdev.usda. gov/rbs/busp/9006loan.htm  Biorefinery Assistance Program http://www.rurdev.usda. gov/rbs/busp/baplg9003.htm  DOE Innovative Technology Loan Guarantee Program The USDA B & I probgram has been around for many years and is well established. The purpose of both B & I and REAP loans is to assist farmer/ producer owned and rural small businesses. Both loan programs require that the project be situated in a rural location. The guarantees are on loans up to $25 million and cover between 60 and 85 percent of the loan amount depending on the size of the loan. Minimum tangible equity of between 20 and 40 percent of the project cost is required, depending on the project. Renewable energy is an area of interest for REAP loans. The B&I loans program is funded and available now, and REAP funding announcements are expected at any time. The Biorefinery Assistance Program also known as Section 9003 of the 2008 Farm Bill focuses on advanced biofuels. Funds must be used to build or retrofit commercial-scale biorefineries to produce advanced biofuels (non-corn cellulose).


FINANCE. The technology must be established or demonstrated as a viable commercial technology. The guarantees are for qualifying loans up to $250 million, not to exceed 80 percent of project costs. The next funding announcement for 2010 is expected in the fourth quarter of this year. The DOE Innovative Technology Loan Guarantee Program totals $6 billion. The government wants rapid deployment and is expected to announce the application process by the end of this month. The loan program will provide loan guarantees for renewable

There are a multitude of government financing programs for alternative fuel projects. Most loan guarantee and grant programs are funded by either the USDA or the U.S. DOE. The DOE Innovative Technology Loan Guarantee Program alone totals $6 billion. The DOE is expected to announce the application process this month.

technologies and transmission technologies. The goal is to encourage early commercial use of innovative technologies in energy projects and to achieve substantial environmental benefits (reducing greenhouse gas emissions). The DOE can guarantee up to 100 percent of a loan as long as the loan does not exceed 80 percent of project costs, but the DOE prefers lower guarantee amounts. Other Federal Programs Other programs applicable to biomass developers worth monitoring and exploring include:

Government is leading the way in encouraging new biomass projects, and grants and loan programs are being announced on a continuous basis.

 Section 9004 - RePowering Assistance - to encourage existing biorefineries to replace fossil fuel used during production  Section 9005 – Bioenergy Program for Advanced Biofuels – provides payments to ag producers to support and ensure expanding production of advanced biofuels  Section 9009 – Rural Self-Sufficiency Initiative – provides funding to enable rural communities to increase energy self-sufficiency (uncertain program timing/funding)  Section 9011 – Biomass Crop Assistance Program – provides support to establish and produce crops for conversion to bioenergy and to help with collection, harvest, storage  Section 9012 - Forest Biomass for Energy – to support R & D to facilitate use of forest biomass for energy-related applications

Project Equity Financing In conjunction with the senior debt, sufficient equity must be raised. The options for equity today are local investors, strategic partners, equity funds (not very likely) and tax equity. The ability for biomass-to-electricity companies to claim investment tax credits, production tax credits, bonus depreciation and accelerated depreciation opens the door for tax equity investors. The tax equity market has shrunk significantly in the past few years due to the economic environment. As a result of this situation, a new program under ARRA has made it possible to get a grant from the federal government in lieu of the 30 percent investment tax credit for certain biomass projects. These grants are issued within 60 days of project completion. With this grant, local equity and a loan guarantee, more project developers will be able to successfully fund their projects. Another tax driven option

is New Market Tax Credits. This federal program has been in existence for several years and funding was increased this year. It is very difficult to meet the requirements but worth the effort as the capital is treated as subordinated debt or equity. The first hurdle is the project must be in a qualifying census tract that is distressed. Being in a rural area is a positive. The census tract must be low income or with high net migration of population. Economic development and job creation are needed to qualify. The investor invests up to 25 percent of the project cost and gets tax credits against federal taxes (39 percent) over seven years instead of getting his capital returned from the project. The interest rates and fees on new market capital are between two percent and four percent per year with no amortization. The structure is complicated and it is difficult to find lenders that can work within the structure. The project size that

works best is in the $10-$40 million total cost range. In today’s capital markets, there is scarce private capital beyond the developer’s own seed capital, making it a difficult environment in which to start and fund a new project. That being said, the emphasis on renewable energy in this country has never been greater. Government is leading the way in encouraging new biomass projects, and grants and loan programs are being announced on a continuous basis. There are many requirements and procedures to navigate and it can take a long time, but it is worth the effort if your project qualifies. The right business plan, the right partners and a realistic capital structure significantly improve the odds for success. EP Sue Wyka is a partner at Ascendant Partners Inc. and Ascendant Financial Partners LLC. Contact her at swyka@ or 303-2214700.

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Protecting Distillers Grains from Sulfur Build-up Excess amounts of sulfur in distillers grains could result in a less desirable product, affecting the company’s bottom line and its reputation.


n today’s marketplace, maximizing the value of ethanol co products has never been more important, and contaminants in an ethanol plant’s distillers grains can impact overall profitability in many ways. Producing a product that is in any way not compatible with industry standards could not only potentially reduce the plant’s ability to sell its distillers grains but could also affect the

The amount of sulfur in distillers grains is one of the most important product elements for plants to be aware of. While sulfur at small doses is an essential nutrient, excessive amounts are a concern in all species, especially ruminants.

plant’s overall reputation. A facility’s distillers grains customers must feel confident that the feed

source they are purchasing for their livestock is a safe, as well as cost-effective, product.

The amount of sulfur in distillers grains is one of the most important product elements for plants to be aware of. While sulfur at small doses is an essential nutrient, excessive amounts are a concern in all species, especially ruminants. Sulfur at high levels can cause a decrease in the rate of weight gain and at worst may cause Polioencephalomalacia (PEM), commonly known as polio,which can lead to death.

The claims and statements made in this article belong exclusively to the author(s) and do not necessarily reflect the views of Ethanol Producer Magazine or its advertisers. All questions pertaining to this article should be directed to the author(s).



June 2009

In distillers grains, sulfur build-up occurs due to an additive effect associated with typical processing practices. Ethanol producers can improve the marketability of their distillers grains by consciously trying to minimize sulfur additions whenever possible.

Such results could cause major damage to a plant’s reputation and reduce the price they command for its distillers grains. Sulfur is an essential macro-mineral for all livestock species. It is contained in essential amino acids such as methionine and cystine and is also found Tom Slunecka, in the B-vivice president of tamins, thimarketing, Phibro amine and Animal Health Corp. Ethanol biotin. The Performance 2005 NaGroup

How much is too much?

tional Research Council guidelines recommend a 0.3 percent total dietary sulfur on a dry matter basis for livestock consuming high concentrate rations, such as feedlot cattle and 0.5 percent total dietary sulfur on a dry matter basis for livestock consuming forage-based rations, such as beef cows. Sulfur can come from the following sources:  Distillers grains  Water supply  Other feed additives In distillers grains, sulfur build-up occurs due to an additive effect associated with typical processing practices. Corn contains about 0.12 percent sul-

Researchers at the University of Nebraska-Lincoln recently compiled data from experiments on ethanol byproduct feeding conducted over the past several years at the university’s research feedlot in Mead, Neb. More than 4,000 cattle, including calf-fed and yearling cattle, were used for the feeding studies. According to the published report, data showed that the incidence of polioencephalomalacia (polio) was very minimal when the animals’ diets contained 0.46 percent or less of sulfur. When levels of sulfur increased to amounts greater than 0.56 percent the incidences of polio also increased. Researchers found that of the 4,143 cattle used for the experiment, a total of 23 cattle were classified as having polio. The majority of polio cases resulted from an experiment in which the cattle were fed a diet that contained 0.47 percent sulfur and no roughage. Cattle which were fed a diet consisting of 0.46 percent sulfur or less fared better – only three of 2,147 animals were diagnosed with polio. After conducting several test runs, the researchers concluded that phosphoric acid could be safely substituted for sulfuric acid in ethanol production, however the amount and cost of phosphoric acid needed for production likely limits the feasibility of its use. SOURCE: 2009 Nebraska Beef Cattle Report, University of Nebraska-Lincoln, Institute of Agriculture & Natural Resources.



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June 2009


SULFUR. fur. The addition of other sulfur-containing compounds can quickly elevate the sulfur content of distillers grains. Additionally, yeast will add to the amount of sulfur in the distillers grains. Ethanol producers can improve the marketability of their distillers grains by consciously trying to minimize sulfur additions whenever possible. The recycling and reuse of water streams within these plants may increase the sulfur concentration by as much as 300 percent, according to James Chapman, Ph.D, dairy technology manager for Prince Agri Products Inc. In addition, several chemicals that are utilized during the typical ethanol production process can contribute to higher sulfur levels in the finished product. Among the chemicals that are major culprits in elevated sulfur concentrations in finished products are: 1. Sulfuric acid 2. Cleaning acids (sulfamic acid or sodium bisulfate) 3. Sodium bisulfite used in ethanol carbon dioxide scrubbers. The amount of sulfur in distillers grains could have a detrimental effect on cattle if left unchecked. High levels of sulfur can cause a decrease of the rate of weight gain and, in extreme cases, cause polio. Chemical companies are willing to work with ethanol producers to monitor the amount of sulfur in distillers grains and can assist in the reduction of sulfur content.



June 2009

►Sulfuric Acid Sulfuric acid is the largest non-naturally occurring contributor to sulfur levels. Sulfuric acid is used for pH adjustment to optimize fermentation and distillation conditions. The generation of chlorine dioxide from sodium chlorite is improved with the addition of sulfuric acid. The industry needs to be wary of adopting antimicrobials that can add more sulfur to DG through the addition of sulfuric acid. ►Cleaning Acids Sulfamic acid, as a cleaning agent, is used to remove mineral scale in heat exchangers. The amounts and frequency of cleanings need to be minimized, within reason, to reduce the contribution of sulfur into the recycle streams while still maintaining a clean system. ►Sodium Bisulfite Sodium bisulfite is utilized to remove acetaldehydes from the carbon dioxide scrubber. Its use can be minimized by making more frequent inspections of scrubber gas emissions to insure that the sodium bisulfite dosage is optimized. Overuse of sodium bisulfite will contribute to sulfur levels and can stress the yeast into producing more glycerol thus reducing ethanol yield. “High sulfur can be devastating to a livestock producer,” says Chapman. “As such, making informed decisions about the production aids used in ethanol production plants, and working closely with live-stock producers to minimize the addition of sulfur in their operation will make significant strides towards reducing the negative outcomes associated with distillers grains. This technical vigilance will ultimately increase the broad acceptance, safety and profitability of our industry as a whole.” Chemical companies are willing to work closely with ethanol plants and their distillers grains customers to assist in reducing sulfur content and its associated


negative effects. If a plant manager discovers a problem with the facility’s fermentation process, an on-site diagnostic test kit can be used to collect data from areas within the plant where suspected contamination has occurred. A successful resolution to a customer’s problem will result in a series of recommendations to alter the operating parameters of the fermentation process. EP

June 2009

Tom Slunecka is the vice president of marketing for Phibro Animal Health Corp.’s Ethanol Performance Group. Reach him at or (402) 575-5855.


EVENTS CALENDAR R-energy Brazil June 17-19 Anhembi Parque Sao-Paolo, Brazil R-energy Brazil will provide a compact and comprehensive market overview of what’s going on in the renewable energy industry. Display areas for special product groups and related industries will be offered. The event will cover topics ranging from ethanol to biodiesel, and wind and solar. +55 11 4412 9468

R-energy Argentina June 10-12, 2009 Golden Center Buenos Aires R-energy prides itself in being a global initiative to create an expo and congress network for the renewable energy industry. The event will provide a comprehensive and specific business hub for renewable energy and development, covering topics from ethanol and biodiesel to wind and solar, and provide attendees with opportunities to network with others in the renewable energy business. +49 521 96533-90

Millennium Hotel Jakarta, Indonesia The conference will provide a platform to learn about the latest trends as well as regional and international developments in the biofuels market. Leaders in the biofuels industry speak on ethanol, biodiesel, next generation biofuels and jatropha. Ethanol sessions will cover developments of bio ethanol, refining, production and distribution, and cellulosic ethanol. Discussions will target policies, refining and blending, downstream logistics, and the transport sector.

China Biofuels & Ethanol Outlook 2009 June 24-25, 2009 The Westin Beijing Beijing This event will provide in-depth knowledge of China’s stimulus plan on renewable energy, including the advantages and pitfalls of different feedstocks, and the latest technology updates. Industry experts and market representatives will give pointers on maximizing production potential in the current economy.

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International Fuel Ethanol Workshop & Expo June 15-18, 2009

Biofuels Markets Asia & Jatropha Executive Briefing June 29 – July 1, 2009

2009 BioFuel Conference June 24 -25, 2009

Denver Convention Center Denver This will mark the 25th anniversary of the world’s largest ethanol conference, with more than 3,500 attendees and 700 exhibitors representing more than 500 countries. The event will provide unmatched business development, networking opportunities, and an industry leading educational forum. The workshop will address conventional ethanol, next-generation ethanol and biomass.

Minneapolis This conference will host sessions on commodity risk management, leadership best practices, business analysis, technical and industry updates and discussions on mistakes of the past year and what the future may hold for ethanol. A discussion is planned on the correlation between corn, ethanol and petroleum throughout 2008 and how plants can manage the correlation to their advantage. Other topics will cover financial models for plants and how leadership roles should be defined within a plant.

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World Congress on Industrial Biotechnology & Bioprocessing July 19-22, 2009 Palais des congrès de Montréal Montreal This 6th Annual World Congress will focus on relevant topics in the field of industrial biotechnology including advanced biofuels, feedstock collection, ethanol and cellulosic ethanol. Individuals with diverse experience will share knowledge that will speed the development and growth of a sector that is vital for value creation and sustainable industrial development. This conference will foster the exchange of ideas and will provide “real world” scenarios, present an overview of the latest technological developments, and offer unparalleled networking opportunities. (202) 962-6630



June 2009

2009 Farm to Fuel Summit July 29-31, 2009

The Alcohol School September 13-18, 2009

Rosen Shingle Creek Orlando The summit is a major gathering place for stakeholders to assemble to advance the development of Florida’s bioenergy industry. The event promotes the production, distribution and use of renewable fuels, particularly ethanol. This year’s featured international, national, and state speakers will discuss research, production, and distribution of biofuels and bioenergy.

Montreal This week-long course will educate fuel-ethanol and distilled beverage producers in the science of alcohol production. The program will cover the ethanol production process from milling and mash preparation through fermentation and distillation. Enzyme usage, yeast biology, bacterial contamination and control will also be discussed, along with other issues currently affecting both industries. Registration is limited, with preference given to fuel-ethanol and distilled beverage producers.

(850) 488-0646

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Ethanol Conference & Trade Show Aug. 11-13, 2009 Milwaukee The American Coalition for Ethanol’s 22nd annual conference will highlight public policy, technology and education related to the ethanol industry, among many other topics. The conference will include: updates from high level political officials, updates on technological innovations and efficiencies in corn and cellulose, discussions on blending economics, risk management techniques, and updates on biofuels role in reducing greenhouse gas emissions. A more detailed agenda will be available as the event approaches. (605) 334-3381

World Bioenergy – Clean Vehicles & Fuels September 16-18, 2009 Stockholmsmässan Stockholm, Sweden This conference will focus on the practical implementation of bioenergy and sustainable transport systems. A variety of commercial examples from Sweden will be highlighted. Topics to be covered include socio-economic drivers, impact of international trade in biofuels, emergence of bio-refineries, coproduction of fuels, chemicals, power and materials, and the development of markets for clean vehicles and fuels. Attendees will include delegates, officials, researchers, and visitors from Europe and beyond. +46 (0)18-67 38 03


June 2009

Atlantic BIOenergy Conference September 21-23, 2009 Delta Beausejour Moncton, New Brunswick The Atlantic BIOenergy Conference, hosted by BBI Biofuels Canada, focuses on growth and sustainability and renewable energy opportunities in Atlantic Canada. The conference features dynamic sessions and discussions on biomass-based energy generation, anaerobic digestion, waste management technologies, government incentives and more. The conference promises lively debates, action-oriented discussions and world class presentations on the latest developments, applications and technologies in the bioenergy fields. (888) 501-0224 (North America) (519) 576-4500 (International)


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Lipten 800-860-0790


Natural Resource Group, LLC. 612-347-6789

Agra Industries, Inc. 715-536-9584

Pinnacle Engineering Inc. 507-280-5966

Process Design

Seneca Companies 800-369-5500

ICM, Inc. 877-456-8588

Process Engineering Associates, LLC 865-220-8722

Weaver Boos Consultants 888-645-5240

Vogelbusch USA, Inc. 713-461-7374



Equipment & Services


Agitation Equipment

Integrated Solutions for Every Challenge Providing turnkey civil & geotechnical engineering & environmental services for industrial, commercial & residential land development projects. A full-service engineering firm, integrating many disciplines for each project, saving our clients time and money.

Greenway Consulting,LLC 320-589-3085

Air Pollution/Odor Control Ceco Abatement Systems, Inc. 630-493-0624

Plant Optimization Granatus Consulting, Inc. 218-773-0005

Analytical Instruments

Colorado•Florida•Illinois•Indiana Michigan•Missouri•Ohio•Texas

Harris Group Inc. 206-494-9422

Gusmer Enterprises, Inc. 847-277-9785

888-645-5240 877-645-5242

ICM, Inc. 877-456-8588

Lipten 800-860-0790

Feasibility Studies Harris Group Inc. 206-494-9422

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ProQuip, Inc. 330-468-1850

Blowers & Fans FlaktWoods 716-845-0900

Project Development Harris Group Inc. 206-494-9422

Perten Instruments, Inc. 801-936-8165

Robinson Industries, Inc. 724-452-6121


Boiler Systems

Iowa Lakes Community College 800-242-5108

Hurst Boiler & Welding Co., Inc. 800-666-6414




Wabash Power Equipment CO. 847-541-5600

McDermott & Bull-Energy Practice 415-722-8966


June 2009

EPM MARKETPLACE Combustion Equipment Eclipse.Inc. 815-637-7213

Control Systems-Distributed

Dust Control Systems MAC Equipment, Inc. 816-891-9300

Computer Software

Emission Monitoring Systems

Encore Business Solutions 204-989-4330

MonitorTech Corp. 866-682-6771

Conveyors–Mechanical U.S. Tsubaki 847-459-9500

You produce fuel. We fuel your success.

Conveyors–Pneumatic MAC Equipment, Inc. 816-891-9300

Cooling Towers Delta Cooling Towers, Inc. 800-BUY-DELTA

Ethanol Efficiency.

Corn Oil Recovery

Integrated business management system for purchase/sales contracting, risk management, plant production and material usage data collection, and automated receiving and loadout.

ICM, Inc. 877-456-8588

Dryers-Fluid Bed Aeroglide Corporation 919-851-2000

dbc SMARTsoftware, Inc. 770-427-7633

Littleford Day, Inc. 859-525-7600

Control Systems


FeedForward, Inc. 770-426-4422

Barr-Rosin,Inc 630-659-3980

ICM, Inc. 877-456-8588

Revere Control Systems 800-536-2525 SoftPLC Corporation 512-264-8390

SRS Engineering Corporation 800-497-5841

© 2009 John Deere Agri Services, Inc.

ICM, Inc. 877-456-8588

Your Solution. Advertise Today.


June 2009

ETS Laboratories 707-963-4806


WINBCO Tank Company 641-683-1855

Filtration Equipment Fluid Engineering 814-453-5014

Buhler Inc. 763-847-9900

Cereal Process Technologies 217-779-2595 Crown Iron Works 651-639-8900

FWS Technologies 204-487-2500

Ronning Engineering Company, Inc. 913-239-8118

Reach your customers

Fermentation Monitoring


Dryers-Rotary Drum Barr-Rosin,Inc. 630-659-3980

Continuous Emissions Monitoring Systems Easiest installation, operation and maintenance Meet or exceeds EPA requirements NOx, O2, CO, SO2 and others Turnkey systems for under $100,000.00 P.O. Box 9271, Columbus, Oh 43209 866-682-6771

ATEC Steel 620-856-3488

Distillation Equipment


ICM, Inc. 877-456-8588

MOR Technology, LLC 618-522-8324

Grain Handling & Storage

Dryers-Rotary Steam Tube

Agra Industries, Inc. 715-536-9584

ICM, Inc. 877-456-8588

McC, Inc. 763-477-4774


EPM MARKETPLACE Mechanical Solutions, LLC 515-332-7035

Heat Exchangers Custom Metalcraft Inc. 417-862-0707

Maintenance Software

Munters - Des Champs Products 540-291-1111

ICM, Inc. 877-456-8588


Mapcon Technologies, Inc. 800-922-4336

Endress+Hauser 317-535-2174

Perten Instruments, Inc. 801-936-8165

WIKA Instrument Corporation 888-945-2872, x5127



KINEMATICA, INC. 631-750-6653

Robert-James Sales, Inc. 800-666-0088

Pipe-Flanges Robert-James Sales, Inc. 800-666-0088

Pressure & Temperature WIKA Instrument Corporation 888-945-2872, x5127


Industrial Construction & Engineering 636-970-1650

CPM/Roskamp Champion 800-366-2563

Agra Industries, Inc. 715-536-9584

Robert-James Sales, Inc. 800-666-0088




Perten Instruments, Inc. 801-936-8165

Pressure Vessels WINBCO Tank Company 641-683-1855

Process Control Harris Group Inc. 206-494-9422

Moisture Analyzers

VFTechnical Services, LLC 423-794-6747


Perten Instruments, Inc. 801-936-8165

SGS North America Inc. 281-479-7170

Sartorius Mechatronies-Omnimark 800-835-3211


Molecular Sieve Desiccant

ITT Industries Goulds Pumps 315-568-2811

CHATA Biosystems

3 Angstrom 630-980-5205

Valley Equipment Co. Inc. 423-753-3541


Phenomenex 310-212-0555

Watson-Marlow Bredel Pumps 800-282-8823

Molecular Sieves

Laboratory-Testing Services

ICM, Inc. 877-456-8588

Midwest Laboratories, Inc. 402-829-9877

Vaperma, Inc. 418-839-6989

Romer Labs, Inc. 636-583-8600

Zeochem, LLC 502-634-7600


Loading Equipment

Trico TCWind, Incorporated 320-693-6200

Hemco Industries, Inc. 877-347-7106 SafeRack 866-761-7225

Paint & Protective Coatings Mongan / Bockman 260-748-7655

Perten Instruments, Inc. 801-936-8165

Resource Recovery

Scales-Software John Deere Agri Services 800-518-0472

Scales-Truck Weigh-Tec Inc. 1-800-461-4153

Parts & Services

Maintenance Services Jouleâ&#x20AC;&#x2122; Industrial Contractors

ICM, Inc. 877-456-8588

Pipe ISCO Industries 800-345-4726


QA Test Products

Eco-Tec, Inc. 905-427-0077

Trilogy Analytical Laboratory 636-239-1521

Carbis, Inc. 800-845-2387


Seals Aesseal Inc. 865-531-0192

Utex Industries, Inc. 432-333-4151/800-873-0946


June 2009

EPM MARKETPLACE Separation Equipment Fluid Engineering 814-453-5014

Thermal Oxidizers

Used Equipment

Puritan Magnetics, Inc. 248-628-3808

Size Reduction-Shredders DuraTech Industries / Haybuster 701-252-4601


Storage-DDGS Laidig Systems, Inc. 574-256-0204

EISENMANN Corporation Crystal Lake, Illinois

Structural Fabrication Agra Industries, Inc. 715-536-9584


Tanks ATEC Steel 620-856-3488

Agra Industries, Inc. 715-536-9584 Brown Tank LLC 651-747-0100

CMC Letco Industries 417-831-1528

Federal Equipment Company 800-652-2466

Pro-Environmental, Inc. 909-989-3010


North American Safety Valve 800-800-8882

in one convenient location, Ethanol

Biothane Corporation 856-541-3500x501

a useful directory in each publication. Whether a first-time advertiser wanting to raise awareness

WINBCO Tank Company 641-683-1855

Wastewater Treatment Services

tains top editorial content but also

Check-All Valve Mfg. Co. 515-224-2301

With all contact information placed

Producer Magazine not only con-

Paragon Trailer Sales 800-471-8769


Hydro-Klean, Inc. 515-283-0500

ICM, Inc. 877-456-8588

UEM, Inc. 561-385-7515

of your business or a frequent dis-

Water Treatment

play advertiser looking for added

Aquatech International Corporation 724-746-5300

exposure, EPM Marketplace is the perfect solution.

Fluid Engineering 814-453-5014


June 2009


EPM MARKETPLACE Faegre & Benson, LLP 612-766-6930

Yield Enhancement EdneiQ, Inc. 310-592-4158

Ethanol Production

Stoel Rives LLP 612-373-8800


Existing Producers

Distillers Grains

Louis Dreyfus Commodities 402-844-2680 POET LLC 605-965-2200

CGB Feed Ingredients 985-867-3554

Fuel Ethanol Atlas Renewable Energy, LLC 800-884-8290

Finance Accounting Christianson & Associates PLLP 320-235-5937 Eide Bailly LLC 605-977-2703

Kennedy and Coe, LLC 800-303-3241

Gavilon 402-595-5678

Miscellaneous Nelson Ink Promotional Products 218-222-3831




Natwick Associates Appraisal Services 800-279-4757

Evolution Markets, Inc. 914-323-0259

Due Diligence

Railcar Moving

Harris Group Inc. 206-494-9422

Shuttlewagon, Inc. 816-767-0300

Mergers & Acquisitions

Railcar Parts

Kent Group, Inc. 715-358-7528

Salco Products, Inc. 630-783-2570

Risk Management

Terminals & DSP

First Capitol Risk Management 800-884-8290

ERS Rail Transload 205-322-8312

R.J. Oâ&#x20AC;&#x2122;Brien 800-621-0757


Software-Accounting Encore Business Solutions 204-989-4330

Software-Commodity John Deere Agri Services 800-518-0472

Legal Services Attorneys BrownWinick Law Firm 515-242-2400

Biomass Magazine is a trade journal serving companies that use and/or produce power, fuels and chemical feedstocks derived from biomass. Collectively, these biomass utilization industries are positioned to replace nearly every product made from fossil fuels with those derived from plant or waste material. The publication covers a wide array of issues on the leading edge of biomass utilization technologies, from biorefining, dedicated energy crops and cellulosic ethanol to decentralized power, anaerobic digestion and gasification. Itâ&#x20AC;&#x2122;s all here.

Utility Integrys Energy Services 608-235-2547

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For additional information please contact us at (701) 746-8385 or at

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June 2009

Robert-James Sales is your #1 source

for stainless PIPE, FITTINGS and FLANGES up to 36" in Sch 5, 10 and 40. We also carry 2205 duplex through 24". Buffalo, NY Cleveland, OH Cincinnati, OH Chicago, IL Cranbury, NJ

800-666-0088 800-777-0820 800-777-2260 800-777-2008 800-777-1858

Indianapolis, IN Minneapolis, MN Raleigh, NC Tavernier, FL

800-777-0510 800-777-1355 866-493-8834 305-852-1694

Free Product CD Contact the Robert-James Sales location nearest you and ask for a free copy of our comprehensive, up-to-date CD. It outlines our stainless product line including reference charts, graphs and tables to help you calculate what your processing plant needs.

Profile for BBI International

June 2009 Ethanol Producer Magazine  

June 2009 Ethanol Producer Magazine

June 2009 Ethanol Producer Magazine  

June 2009 Ethanol Producer Magazine