EPA Concludes Corn-Based Ethanol Will Meet GHG Reduction Requirement

Posted on February 4, 2010. Filed under: Advanced Biofuel, Field-to-Pump | Tags: , , , |

EPA ruling boosts ethanol after fierce lobbying effort for corn-based fuels
By Ben Geman
February 3, 2010

The Environmental Protection Agency (EPA) handed a victory to ethanol producers Wednesday by issuing final regulations that conclude corn-based fuels will meet greenhouse gas standards imposed under a 2007 energy law.

The release of the final regulations follows a fierce campaign by ethanol companies that alleged 2009 draft rules unfairly found that large volumes of ethanol production would not meet targets in the statute for reducing greenhouse gases.

The new rules state that corn-based ethanol will meet a requirement of the 2007 law that they must emit at least 20 percent less in “lifecycle” greenhouse gas emissions than gasoline.

The statute expanded the national biofuels use mandate to reach 36 billion gallons annually by 2022. If the EPA had ruled that corn-based fuels did not meet their emissions target, the fuels could have been frozen out of the market.

The issue has been vital to the ethanol lobby, which feared that an adverse finding could stymie investment and tarnish the fuel’s image.

However, the nation’s current ethanol production — about 12 billion gallons annually — was exempted from the law’s emissions mandate.

EPA Administrator Lisa Jackson on Monday denied the agency had bent to pressure, instead arguing that EPA employed better modeling when crafting the final regulations.

“We have followed the science,” she told reporters on a conference call. “Our models have become more sophisticated. We have accrued better data.”

The new rules, which implement the expanded fuels mandate, are not a complete victory for ethanol lobbyists, who along with several farm-state lawmakers object to the way EPA measures the carbon footprint of biofuels.

Specifically, they’re upset that EPA didn’t give up on weighing “international indirect land use changes” as part of emissions calculations. The phrase refers to emissions from clearing grasslands and forests in other countries for croplands, in order to compensate for increasing use of U.S. corn and soybeans for making fuels.

“We will always be concerned about indirect land use,” said Gen. Wesley Clark, a former presidential candidate who now leads the ethanol industry trade group Growth Energy.

“Why should American farmers be penalized for the problems in the Brazilian rainforest? That’s the Brazilian government’s issue and maybe the United Nations’,” he said in an interview before EPA’s rules were released. “It is so farfetched. I know it comes out of an academic model, but it is just an academic model, and the model is not even based on current facts.”

The industry alleges the science behind the land-use emissions measurements is immature and inaccurate, while environmentalists say such calculations are vital to ensuring federal support for ethanol doesn’t actually worsen climate change.

Nathanael Greene of the Natural Resources Defense Council also praised the measure because EPA did not back away from considering the land-use emissions, even though it came up with numbers friendlier to the industry with the final rule.

“We finally have a tool that we can use to hold the industry accountable, to reward the people that are doing a better job and keep the folks that are doing a really bad job out,” said Greene, the group’s director of renewable energy policy.

EPA said several factors went into the revised emissions calculations. For instance, the agency said that better satellite data allowed more precise assessments of the types of land converted internationally.

The battle over the land use emissions is hardly over. Two senior House Democrats — Agriculture Committee Chairman Collin Peterson (Minn.) and Armed Services Committee Chairman Ike Skelton (Mo.) — introduced a bill this week that would block EPA from considering the land-use changes.

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How Does a Cap-and-Trade Program Work?

Posted on February 3, 2010. Filed under: Advanced Biofuel, cap-and-trade, Hydrous Ethanol | Tags: , , |

U.S. Energy Information Administration
February 1, 2010

What is a cap-and-trade program and how does it work?
A cap-and-trade program is designed to reduce emissions of a pollutant by placing a limit (or cap) on the total amount of emissions. The cap is implemented through a system of allowances that can be traded to minimize costs to affected sources. Cap-and-trade programs for greenhouse gas emissions would increase the costs of using fossil fuels.

A cap-and-trade program is different from an emissions tax. An emissions tax is a fee on each unit of emissions released. A tax sets a price on emissions, which provides an incentive for emissions reduction, but allows the actual amount of reduction that occurs to vary.

A cap-and-trade program sets the quantity of emissions, letting the price of allowances be set in the marketplace. However, both programs ultimately place a value on emissions and provide incentives for emission reductions.

What Is a Cap-and-Trade Program?
A cap-and-trade program is an environmental policy tool designed to reduce emissions of a pollutant by placing a limit (or cap) on the total amount of emissions that can be released by sources covered by the program during a fixed time period.

The overall cap on emissions is implemented through a system of allowances. Each allowance represents the right to emit a specific amount of emissions, and each emissions source covered by the program must submit enough allowances to cover its actual emissions. These allowances, sometimes called permits, are initially allocated to affected sources or auctioned off by the agency implementing the program.

Allowances can be traded, which creates an incentive for those who can reduce emissions most cheaply to sell their allowances to those who face higher emission reduction costs. The incentive to trade allowances persists as long as one or more sources can reduce emissions by an additional unit at a lower cost than some other source faces to achieve its last unit of emissions reduction. Therefore, allowances will be traded until the marginal cost of emission reduction is equal across all covered sources. At this point, the pollution level required by the cap is achieved – theoretically at the lowest possible cost to society – regardless of how the allowances were initially allocated.

How Does a Cap-and-Trade Program Work?
Not all cap-and-trade programs are identical. Below is a list of four characteristics shared by all cap-and-trade programs, with some possible variations shown. These variations could affect how a particular program works.

1. A limit or cap on emissions of a pollutant is established.

Who is required to limit their emissions. Is it all sources of emissions or just some sources of emissions?
What area the cap covers. Is it a region or State, the whole United States, or a group of nations?
When emission limits take effect. Will the cap be in place in the near term or at a later date?
Whether the cap will become tighter, meaning the total allowable level of emissions drops over time. If so, how quickly will this decrease happen?
When the cap is in place. Will it be in effect for a season – such as just for the summer months – or is it applied for the whole year?

2. An allowance must be surrendered for every unit (often a ton) of emissions generated.

Who must submit allowances. While this depends on the specific cap-and-trade program, some examples include producers of the polluting substance, distributors of a product whose production or consumption generates emissions, States, or even nations.
How allowances are initially distributed. Allowances could be auctioned, distributed for free based on current or historical emissions, or given out using some combination of an auction and a free distribution. In an auction, allowances are sold to the highest bidders. Uses of auction revenue depend on the specific cap-and-trade program, and could include the distribution of a portion of the revenue to consumers.
Whether the program allows for the purchase of offsets in lieu of allowances. Offsets are certified reductions in emissions from sources that are not required by the cap-and-trade program to restrict their emissions.

3. Allowances can be traded.

Here’s an example of how the trade could work. Emitter ABC found it really easy and cheap to reduce its emissions below the level covered by its allowances, while Emitter XYZ had a tougher time. ABC was able to make larger reductions in its emissions and offered to sell its extra allowances to XYZ. This transaction was a good deal for XYZ because the cost of allowances it bought was lower than the cost of equipment needed to reduce its own emissions to a level that matched the number of allowances it held before buying more allowances from ABC.
How much an allowance costs. In general, the allowance price depends on the options available to reduce emissions and the demand for allowances. If there are relatively low-cost options to reduce emissions, the price of allowances would be lower.
Whether emitters are allowed to save – or “bank” – allowances, either for their own future use or to sell to someone else later. Some proposals might also allow the current use of a future period’s allowances.

4. Actual emissions are measured and penalties are assessed if targets are missed.

Depending on the program, these tasks could be the responsibility of one or more governmental agencies.

How Do Cap-and-Trade Programs Affect Our Use of Energy?
The burning of fossil fuels, including coal, oil, and natural gas, is the main source of carbon dioxide – the most important greenhouse gas produced by human activity – and a major source of other emissions. A cap-and-trade program for greenhouse gas emissions would increase the cost of using fossil fuels, making them less competitive with non-fossil energy resources and increasing the overall cost of energy to consumers. The cost of using coal, which has the highest carbon dioxide content and the lowest price per unit of energy among the fossil fuels, would be most affected by a cap-and-trade program for greenhouse gases.

Why Might a Cap-and-Trade Program Be Considered?
A cap-and-trade program allows emitters to have flexibility in their approach to reducing emissions. An alternative environmental policy might require each regulated source to use a specific emission control technology. With a cap-and-trade program, the overall cap on emissions is fixed, but the compliance approach by any individual source need not be specified. This flexibility allows parties to choose the least costly option and should reduce the cost of reaching the overall emissions cap.

The implementation of the U.S. cap-and-trade program for sulfur dioxide beginning in 1995 is an example of the benefits of flexibility in reducing environmental compliance costs in the energy sector. Allowances for sulfur dioxide emissions were actively traded as coal-fired electricity generating units covered by the program chose a variety of compliance strategies. These strategies included installing scrubbers, switching to lower sulfur coal, and buying allowances.

Where Has Cap-and-Trade Been Used?
Cap-and-trade programs have been used to limit several different types of emissions in State, U.S., and international contexts. 

As noted above, a cap-and-trade program limiting sulfur dioxide emissions has been operating in the United States since 1995. The European Union established its Emissions Trading System for greenhouse gas emissions in 2005. In 2009, the Regional Greenhouse Gas Initiative established an interstate cap-and-trade system for greenhouse gas emissions covering electric power plants in 10 northeastern States. Recently, there has been a lot of discussion about the Federal Government establishing a nationwide cap-and-trade program for greenhouse gas emissions.

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U.S. Department of Defense Addresses the Issue of Climate Change

Posted on February 2, 2010. Filed under: Advanced Biofuel, Field-to-Pump, Hydrous Ethanol | Tags: , , , |

Excerpts from the U.S. DoD 2010 Quadrennial Defense Review
February 1, 2010

Climate change and energy are two key issues that will play a significant role in shaping the future security environment. Although they produce distinct types of challenges, climate change, energy security, and economic stability are inextricably linked. The actions that the Department takes now can prepare us to respond effectively to these challenges in the near term and in the future.

Climate change will affect DoD in two broad ways. First, climate change will shape the operating environment, roles, and missions that we undertake. The U.S. Global Change Research Program, composed of 13 federal agencies, reported in 2009 that climate-related changes are already being observed in every region of the world, including the United States and its coastal waters. Among these physical changes are increases in heavy downpours, rising temperature and sea level, rapidly retreating glaciers, thawing permafrost, lengthening growing seasons, lengthening ice-free seasons in the oceans and on lakes and rivers, earlier snowmelt, and alterations in river flows.

Assessments conducted by the intelligence community indicate that climate change could have significant geopolitical impacts around the world, contributing to poverty, environmental degradation, and the further weakening of fragile governments. Climate change will contribute to food and water scarcity, will increase the spread of disease, and may spur or exacerbate mass migration.

While climate change alone does not cause conflict, it may act as an accelerant of instability or conflict, placing a burden to respond on civilian institutions and militaries around the world. In addition, extreme weather events may lead to increased demands for defense support to civil authorities for humanitarian assistance or disaster response both within the United States and overseas. In some nations, the military is the only institution with the capacity to respond to a large-scale natural disaster. Proactive engagement with these countries can help build their capability to respond to such events. Working closely with relevant U.S. departments and agencies, DoD has undertaken environmental security cooperative initiatives with foreign militaries that represent a nonthreatening way of building trust, sharing best practices on installations management and operations, and developing response capacity.

Second, DoD will need to adjust to the impacts of climate change on our facilities and military capabilities. The Department already provides environmental stewardship at hundreds of DoD installations throughout the United States and around the world, working diligently to meet resource efficiency and sustainability goals as set by relevant laws and executive orders. Although the United States has significant capacity to adapt to climate change, it will pose challenges for civil society and DoD alike, particularly in light of the nation’s extensive coastal infrastructure. In 2008, the National Intelligence Council judged that more than 30 U.S. military installations were already facing elevated levels of risk from rising sea levels. DoD’s operational readiness hinges on continued access to land, air, and sea training and test space. Consequently, the Department must complete a comprehensive assessment of all installations to assess the potential impacts of climate change on its missions and adapt as required.

In this regard, DoD will work to foster efforts to assess, adapt to, and mitigate the impacts of climate change. Domestically, the Department will leverage the Strategic Environmental Research and Development Program, a joint effort among DoD, the Department of Energy, and the Environmental Protection Agency, to develop climate change assessment tools. Abroad, the Department will increase its investment in the Defense Environmental International Cooperation Program not only to promote cooperation on environmental security issues, but also to augment international adaptation efforts. The Department will also speed innovative energy and conservation technologies from laboratories to military end users. The Environmental Security and Technology Certification Program uses military installations as a test bed to demonstrate and create a market for innovative energy efficiency and renewable energy technologies coming out of the private sector and DoD and Department of Energy laboratories.

Finally, the Department is improving small-scale energy efficiency and renewable energy projects at military installations through our Energy Conservation Investment Program.

The effect of changing climate on the Department’s operating environment is evident in the maritime commons of the Arctic. The opening of the Arctic waters in the decades ahead which will permit seasonal commerce and transit presents a unique opportunity to work collaboratively in multilateral forums to promote a balanced approach to improving human and environmental security in the region. In that effort, DoD must work with the Coast Guard and the Department of Homeland Security to address gaps in Arctic communications, domain awareness, search and rescue, and environmental observation and forecasting capabilities to support both current and future planning and operations. To support cooperative engagement in the Arctic, DoD strongly supports accession to the United Nations Convention on the Law of the Sea.

As climate science advances, the Department will regularly reevaluate climate change risks and opportunities in order to develop policies and plans to manage its effects on the Department’s operating environment, missions, and facilities. Managing the national security effects of climate change will require DoD to work collaboratively, through a whole-of-government approach, with both traditional allies and new partners.

Energy security for the Department means having assured access to reliable supplies of energy and the ability to protect and deliver sufficient energy to meet operational needs. Energy efficiency can serve as a force multiplier, because it increases the range and endurance of forces in the field and can reduce the number of combat forces diverted to protect energy supply lines, which are vulnerable to both asymmetric and conventional attacks and disruptions. DoD must incorporate geostrategic and operational energy considerations into force planning, requirements development, and acquisition processes. To address these challenges, DoD will fully implement the statutory requirement for the energy efficiency Key Performance Parameter and fully burdened cost of fuel set forth in the 2009 National Defense Authorization Act. The Department will also investigate alternative concepts for improving operational energy use, including the creation of an innovation fund administered by the new Director of Operational Energy to enable components to compete for funding on projects that advance integrated energy solutions.

The Department is increasing its use of renewable energy supplies and reducing energy demand to improve operational effectiveness, reduce greenhouse gas emissions in support of U.S. climate change initiatives, and protect the Department from energy price fluctuations. The Military Departments have invested in noncarbon power sources such as solar, wind, geothermal, and biomass energy at domestic installations and in vehicles powered by alternative fuels, including hybrid power, electricity, hydrogen, and compressed national gas. Solving military challenges—through such innovations as more efficient generators, better batteries, lighter materials, and tactically deployed energy sources—has the potential to yield spin-off technologies that benefit the civilian community as well. DoD will partner with academia, other U.S. agencies, and international partners to research, develop, test, and evaluate new sustainable energy technologies.

Indeed, the following examples demonstrate the broad range of Service energy innovations. By 2016, the Air Force will be postured to cost-competitively acquire 50 percent of its domestic aviation fuel via an alternative fuel blend that is greener than conventional petroleum fuel. Further, Air Force testing and standard-setting in this arena paves the way for the much larger commercial aviation sector to follow. The Army is in the midst of a significant transformation of its fleet of 70,000 non-tactical vehicles (NTVs), including the current deployment of more than 500 hybrids and the acquisition of 4,000 low-speed electric vehicles at domestic installations to help cut fossil fuel usage. The Army is also exploring ways to exploit the opportunities for renewable power generation to support operational needs: for instance, the Rucksack Enhanced Portable Power System (REPPS). The Navy commissioned the USS Makin Island, its first electric-drive surface combatant, and tested an F/A-18 engine on camelina-based biofuel in 2009—two key steps toward the vision of deploying a “green” carrier strike group using biofuel and nuclear power by 2016. The Marine Corps has created an Expeditionary Energy Office to address operational energy risk, and its Energy Assessment Team has identified ways to achieve efficiencies in today’s highly energy-intensive operations in Afghanistan and Iraq in order to reduce logistics and related force protection requirements.

To address energy security while simultaneously enhancing mission assurance at domestic facilities, the Department is focusing on making them more resilient. U.S. forces at home and abroad rely on support from installations in the United States. DoD will conduct a coordinated energy assessment, prioritize critical assets, and promote investments in energy efficiency to ensure that critical installations are adequately prepared for prolonged outages caused by natural disasters, accidents, or attacks. At the same time, the Department will also take steps to balance energy production and transmission with the requirement to preserve the test and training ranges and the operating areas that are needed to maintain readiness.

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Carbon Capitalists Warming to Climate Market Using Derivatives

Posted on December 19, 2009. Filed under: Advanced Biofuel | Tags: , , , |

Carbon Capitalists Warming to Climate Market Using Derivatives
By Lisa Kassenaar
December 4, 2009

Across Uganda, thousands of women warm supper over new, $8 orange-painted stoves. The clay-and- metal pots burn about two-thirds the charcoal of the open-fire cooking typical of East Africa, where forests are being chopped down in the struggle to feed the region’s 125 million people.

Four thousand miles away, at the Charles Hurst Land Rover dealership in southwest London, a Range Rover Vogue sells for 90,000 pounds ($151,000). A blue windshield sticker proclaims that the gasoline-powered truck’s first 45,000 miles (72,421 kilometers) will be carbon neutral.

That’s because Land Rover, official purveyor of 4x4s to Queen Elizabeth II, is helping Ugandans cut their greenhouse gas emissions with those new stoves.

These two worlds came together in the offices of Blythe Masters at JPMorgan Chase & Co. Masters, 40, oversees the New York bank’s environmental businesses as the firm’s global head of commodities. JPMorgan brokered a deal in 2007 for Land Rover to buy carbon credits from ClimateCare, an Oxford, England-based group that develops energy-efficiency projects around the world. Land Rover, now owned by Mumbai-based Tata Motors Ltd., is using the credits to offset some of the CO2 emissions produced by its vehicles.

For Wall Street, these kinds of voluntary carbon deals are just a dress rehearsal for the day when the U.S. develops a mandatory trading program for greenhouse gas emissions. JPMorgan, Goldman Sachs Group Inc. and Morgan Stanley will be watching closely as 192 nations gather in Copenhagen next week to try to forge a new climate-change treaty that would, for the first time, include the U.S. and China.

U.S. Cap and Trade
Those two economies are the biggest emitters of CO2, the most ubiquitous of the gases found to cause global warming. The Kyoto Protocol, whose emissions targets will expire in 2012, spawned a carbon-trading system in Europe that the banks hope will be replicated in the U.S.

The U.S. Senate is debating a clean-energy bill that would introduce cap and trade for U.S. emissions. A similar bill passed the House of Representatives in June. The plan would transform U.S. industry by forcing the biggest companies — such as utilities, oil and gas drillers and cement makers — to calculate the amounts of carbon dioxide and other greenhouse gases they emit and then pay for them.

Estimates of the potential size of the U.S. cap-and-trade market range from $300 billion to $2 trillion.

Banks Moving In
Banks intend to become the intermediaries in this fledgling market. Although U.S. carbon legislation may not pass for a year or more, Wall Street has already spent hundreds of millions of dollars hiring lobbyists and making deals with companies that can supply them with “carbon offsets” to sell to clients.

JPMorgan, for instance, purchased ClimateCare in early 2008 for an undisclosed sum. This month, it paid $210 million for Eco-Securities Group Plc, the biggest developer of projects used to generate credits offsetting government-regulated carbon emissions. Financial institutions have also been investing in alternative energy, such as wind and solar power, and lending to clean-technology entrepreneurs.

The banks are preparing to do with carbon what they’ve done before: design and market derivatives contracts that will help client companies hedge their price risk over the long term. They’re also ready to sell carbon-related financial products to outside investors.

Masters says banks must be allowed to lead the way if a mandatory carbon-trading system is going to help save the planet at the lowest possible cost. And derivatives related to carbon must be part of the mix, she says. Derivatives are securities whose value is derived from the value of an underlying commodity — in this case, CO2 and other greenhouse gases.

‘Heavy Involvement’
“This requires a massive redirection of capital,” Masters says. “You can’t have a successful climate policy without the heavy, heavy involvement of financial institutions.”

As a young London banker in the early 1990s, Masters was part of JPMorgan’s team developing ideas for transferring risk to third parties. She went on to manage credit risk for JPMorgan’s investment bank.

Among the credit derivatives that grew from the bank’s early efforts was the credit-default swap. A CDS is a contract that functions like insurance by protecting debt holders against default. In 2008, after U.S. home prices plunged, the cost of protection against subprime-mortgage bond defaults jumped. Insurer American International Group Inc., which had sold billions in CDSs, was forced into government ownership, roiling markets and helping trigger the worst global recession since the 1930s.

Lawmakers Leery
Now, that story — and the entire role the banks played in the credit crisis — has become central to the U.S. carbon debate. Washington lawmakers are leery of handing Wall Street anything new to trade because the bitter taste of the credit debacle lingers. And their focus is on derivatives. Along with CDSs, the most-notorious derivatives are the collateralized-debt obligations they often insured. CDOs are bundles of subprime mortgages and other debt that were sliced into tranches and sold to investors.

“People are going to be cutting up carbon futures, and we’ll be in trouble,” says Maria Cantwell, a Democratic senator from Washington state. “You can’t stay ahead of the next tool they’re going to create.”

Cantwell, 51, proposed in November that U.S. state governments be given the right to ban unregulated financial products. “The derivatives market has done so much damage to our economy and is nothing more than a very-high-stakes casino — except that casinos have to abide by regulations,” she wrote in a press release.

Jet Fuel, Wheat
In carbon markets, many of the derivatives would be futures, options and swaps that would allow a company to lock in a price for carbon like it would for any other commodity related to its business, Masters says. Such derivatives are negotiated every day by airlines trying to guarantee future prices for jet fuel and farmers setting a future price for their wheat crop. A large, liquid market in carbon credits would serve to keep their price low, JPMorgan says.

“The reason why this is important is not because it’s going to create a new forum for us to buy and sell; it’s because the scale of what’s being contemplated here is absolutely enormous,” Masters says. “It’s going to affect your kids and my kids. The worst thing would be to introduce legislation that doesn’t achieve the environmental goal; that would be a crime of epic proportions.”

Not Convinced
Michelle Chan, a senior policy analyst in San Francisco for Friends of the Earth, isn’t convinced.

“Should we really create a new $2 trillion market when we haven’t yet finished the job of revamping and testing new financial regulation?” she asks. Chan says that, given their recent history, the banks’ ability to turn climate change into a new commodities market should be curbed.

“What we have just been woken up to in the credit crisis — to a jarring and shocking degree — is what happens in the real world,” she says.

Even George Soros, the billionaire hedge fund operator, says money managers would find ways to manipulate cap-and-trade markets. “The system can be gamed,” Soros, 79, remarked at a London School of Economics seminar in July. “That’s why financial types like me like it — because there are financial opportunities.”

Masters says U.S. carbon markets should be transparent and regulated by the Commodity Futures Trading Commission. Standardized derivatives contracts — securities that can be bought and sold by anyone — should be traded on exchanges or centrally cleared, she says. The British-born Masters, who has an economics degree from Cambridge University, took over JPMorgan’s commodities business in 2007.

Allowances, Offsets
In a U.S. cap-and-trade market, the government would allot tradable pollution permits, called allowances, to emitters of CO2 and other greenhouse gases. The market would also likely include offsets — credits generated by companies such as Eco-Securities that would have to demonstrate to U.S. agencies running the program that the offsets mitigate carbon pollution.

Point Carbon, an Oslo-based firm that analyzes environmental markets, estimates that by 2020 the U.S. carbon market could surge to more than $300 billion. That’s based on an assumption that the allowances, each representing a ton of carbon dioxide taken out of the atmosphere, would trade for $15. Bart Chilton, a commissioner of the CFTC, which would likely be one of the regulators of the carbon market, says it could grow as large as $2 trillion.

Goldman Building
As they wait for a U.S. cap-and-trade system to be introduced, the big banks are busy building, not trading. Goldman Sachs, for example, has fewer than 10 traders dedicated to carbon around the world.

“Carbon right now is not about sitting in front of a screen and clicking,” says Gerrit Nicholas, Goldman’s head of North American environmental commodities. “It’s all about running around talking to clients about what they can expect, how big it can be and what their risk is.”

Abyd Karmali, who heads global carbon emissions at Bank of America Merrill Lynch in London, says companies, banks and investors are all watching Congress.

“A lot of people are focused on Copenhagen, but what happens in Washington on federal cap and trade is, arguably, more important,” says Karmali, who’s president of the Carbon Markets and Investors Association, an international trade group. “This market is still in its very early stages. U.S. cap and trade would make an order of magnitude of difference.”

‘Ruinous Course’
Although U.S. President Barack Obama and his economic team support cap and trade, Washington politics could defeat it. The House bill passed in June by just seven votes, and senators on both sides of the aisle worry that imposing pollution caps on industry will result in higher energy bills for consumers at a time when U.S. unemployment tops 10 percent. Karl Rove, former president George W. Bush’s deputy chief of staff, wrote in Newsweek magazine in November that cap and trade “would put America on a ruinous course.”

Republican Senator James Inhofe of Oklahoma, who in 2006 called Nobel Prize winner and former Vice President Al Gore “full of crap” on global warming, boycotted committee meetings on the Senate bill in November.

Senate Majority Leader Harry Reid said on Nov. 18 that climate-change legislation may not be discussed until the spring, prompting speculation among others in the Senate that the bill won’t be passed before Congressional elections in 2010. The Obama administration is also driving to overhaul U.S. health care and develop proposals to push down unemployment.

House, Senate Bills
U.S. cap and trade, as currently configured in both the House and Senate bills, would mean the government sets an upper limit on emissions of seven greenhouse gases, including CO2, methane and nitrous oxide, for thousands of power plants, refineries and factories. Over time, the caps would fall, pushing emitters to adopt clean-air technology.

The government would give some pollution allowances to companies free to help them meet their caps during the first years of the program. Emitters who invest in cutting their pollution would have allowances to sell; those that don’t would have to buy.

The allowances — similar to those that sold in Europe in mid-November for 13.5 euros ($20) — would be tradable on an exchange or, if Congress allows it, between parties in an over- the-counter market. The credits garnered through offset projects such as the stoves in Uganda are distinct from allowances in that they may be generated on the other side of the world.

Accounting for Carbon
U.S. companies would account for carbon in long-term strategic plans, bankers say. For instance, utilities such as American Electric Power Co., which produces power from coal, would hedge the price of carbon over periods as long as a decade or more. Columbus, Ohio-based AEP is the biggest U.S. greenhouse gas emitter in the Standard & Poor’s 500, according to the London-based Carbon Disclosure Project, which collects such data. Companies like AEP would retain financial institutions to come up with customized derivatives contracts to help them manage their risk.

Derivatives contracts designed for a particular company or transaction, known as over-the-counter derivatives, are a hot- button issue in the larger debate over how the U.S. banking system should be regulated. Most CDSs and CDOs are OTC derivatives. They are created and traded privately — not on any exchange — and can be illiquid and opaque, says Andy Stevenson, a financial analyst for the Natural Resources Defense Council, an environmental group that supports the Senate legislation. The House cap-and-trade bill bans OTC derivatives, requiring that all carbon trading be done on exchanges.

OTC Derivatives
The bankers say such a ban would be a mistake. OTC derivatives are a $600 trillion market, much of which consists of interest-rate swaps designed to hedge risks for individual companies. “It’s a concern of ours if they limit the market,” says Pat Hemlepp, a spokesman for AEP. “It reduces the options when it comes to cap and trade, and we have told people that on the Hill. We do feel it’s best to have banks and other parties able to participate.”

The banks and companies may get their way on carbon derivatives in separate legislation now being worked out in Congress. In October, the House Financial Services Committee, headed by Representative Barney Frank, a Democrat from Massachusetts, approved a bill that would require collateral for all derivatives trading between financial institutions. And broker-dealers such as JPMorgan and Goldman Sachs would be forced to clear most derivatives contracts on regulated exchanges or through so-called swap-execution facilities. However, the new rules would not apply to end-users — companies such as AEP that use derivatives to hedge operational risks.

Price Collar
The Senate environment bill, dubbed Kerry-Boxer for Senators John Kerry of Massachusetts and Barbara Boxer of California, the two Democrats who introduced it, contains little detail on how the cap-and-trade market would work. It sets a price floor of $11 per ton on carbon. The bill also creates a strategic reserve of allowances that the government could use to flood the market if the price of carbon shoots up.

“It will be the best-regulated market in the country,” Stevenson says. “The effort is to make all of the trading known to the regulator. That wasn’t the case in the mortgage market.”

Wall Street sees profits at every stage of the carbon- trading process. Banks would make money by helping clients manage their carbon risk, by trading carbon for their own accounts and by making loans to companies that invest to cut greenhouse gas emissions.

Chicago Climate Exchange
A clear U.S. price on carbon, determined in a large market, would help drive billions of dollars into investments to clean the air, says Richard Sandor, founder and chairman of the Chicago Climate Exchange and the Chicago Climate Futures Exchange. He is also the principal architect of the interest- rate futures market.

“What’s important is the price signal,” Sandor says. “It will stimulate inventive activity and cause behavior to change.” The Chicago Climate Exchange, the biggest U.S. voluntary greenhouse-gas-emissions trading system, trades 180,000 tons of carbon a day, up from 40,000 tons in 2006.

Over time, carbon, like other commodities, needs markets linked around the world, Goldman’s Nicholas says.

“If you believe the science and that something needs to be done about this, the market probably needs to be big,” he says. “Carbon could become an important commodity. I’m not saying it will be bigger than others, but it will be another important business for us.”

Polluters Only
Critics, including Senator Cantwell, espouse a smaller, less complex market in which pollution permits would be publicly exchanged only among fossil-fuel producers. Such a system may block progress on the environmental goals, says JPMorgan’s Masters.

“We say, ‘Let’s incentivize people to have the lowest-cost opportunities to avoid carbon emissions,’” she says.

Masters has been dealing with complex securities since she did a summer internship on JPMorgan’s London derivatives desk while she was at Cambridge. She joined the desk full time soon after graduating in 1991. The derivatives group’s task was to find ways to spread the risk of JPMorgan’s loans, partly to reduce the amount of capital it was required to hold in reserve against them.

Offloading Risk
In 1994, Exxon Corp. needed a credit line after it was threatened with a $5 billion fine for spilling 10.8 million gallons (40.9 million liters) of oil into the ocean off Alaska in 1989. Masters asked the London-based European Bank for Reconstruction and Development to take on the Exxon risk in exchange for an annual fee paid by JPMorgan, according to “Fool’s Gold,” a book by Gillian Tett (Free Press, 2009) that chronicles the history of credit derivatives at JPMorgan. The loan would remain on JPMorgan’s books and be insured by the EBRD, an international bank owned by 61 countries that supports development projects in Central Europe.

The bankers called the contract a credit-default swap.

Masters left the credit derivatives unit in 2001 to do other jobs at the bank. From 2004 to 2007, she served as chief financial officer of the investment bank. Since she took over the commodities division in 2007, its staff has almost doubled to 400 employees. The firm added Bear Energy to the division when it acquired Bear Stearns Cos. in the March 2008 heat of the credit crisis.

In December 2008, Masters led the purchase of UBS AG’s agriculture business and Canadian commodities operations. She now sits in a corner office in Bear’s former Madison Avenue tower. Outside her glass door are rows of traders making markets in metals and oil futures.

Subprime Carbon
Friends of the Earth’s Chan is working hard to prevent the banks from adding carbon to their repertoire. She titled a March FOE report “Subprime Carbon?” In testimony on Capitol Hill, she warned, “Wall Street won’t just be brokering in plain carbon derivatives — they’ll get creative.”

Sitting in Cafe Madeleine, a small sandwich shop on a hilly stretch of California Street in San Francisco, Chan, 37, talks over coffee about her campaign. She’s brought her own ceramic mug from her crammed office across the street.

Chan started at FOE — the biggest network of environmental groups in the world, with offices in 77 countries — on a six- month fellowship after she graduated from the University of California, Los Angeles in 1994. Her first job was to pin responsibility for what FOE regarded as environmentally damaging projects on the banks that loaned the enterprises money.

Three Gorges Dam
In 1997, Chan uncovered and helped publicize loans to China’s Three Gorges Dam by banks including Morgan Stanley and Merrill Lynch. Since then, Wall Street banks have sought Friends of the Earth’s help in burnishing their environmental image.

In 2005, Chan worked with Goldman Sachs to write an environmental policy statement for the firm, she says.

Carbon isn’t like other commodities, Chan says. The government’s goal to reduce pollution means it will gradually diminish the number of allowances it issues, and that will be a powerful incentive for speculators to try to corner the market and drive up the price, she says.

While banks say they’re a long way from packaging securities from environmental credits now, Chan points to two deals that Zurich-based Credit Suisse Group AG completed in 2007 and 2008 that each combined more than 20 different offset projects, then sliced them into tranches and sold them to investors. The securities were the equivalent of carbon CDOs, Chan says.

Boom and Bust
Chan has an ally in hedge fund manager Michael Masters, founder of Masters Capital Management LLC, based in St. Croix, U.S. Virgin Islands. He says speculators will end up controlling U.S. carbon prices, and their participation could trigger the same type of boom-and-bust cycles that have buffeted other commodities.

In February 2009 House testimony, Masters — who is no relation to Blythe Masters — estimated that the early 2008 price bubbles in crude oil, corn and other commodities cost U.S. consumers more than $110 billion.

The hedge fund manager says that banks will attempt to inflate the carbon market by recruiting investors from hedge funds and pension funds.

“Wall Street is going to sell it as an investment product to people that have nothing to do with carbon,” he says. “Then suddenly investment managers are dominating the asset class, and nothing is related to actual supply and demand. We have seen this movie before.”

Companies Need Banks
Still, companies need the financial markets to help them drive down their greenhouse gas emissions at a reasonable price, says the NRDC’s Stevenson. “There are trillions of dollars needed to make this transition, and companies need the banks,” says Stevenson, a former trader for London-based hedge fund firm Brevan Howard Asset Management LLP.

Stevenson dismisses as overblown the concern that banks will soon be packaging greenhouse gas allowances into securities that look like CDOs. The banks stand to make more money, he says, as lenders to companies that need to invest in new power plants and factories to reduce their emissions. “I would argue that this is only a bonanza for the banks in that they get to go back to their day jobs — which is lending money,” Stevenson says. “I’m suspect of them generating a lot from carbon trading itself in the early years.”

Northeast Test Case
A relatively small-scale cap-and-trade effort called the Regional Greenhouse Gas Initiative tells a cautionary tale. RGGI is a CO2 reduction program established by a group of northeastern and mid-Atlantic states in 2003 with a goal of cutting CO2 emissions from power plants in the region 10 percent by 2018. Ten states are now members. Trading in the companies’ pollution permits began in September 2008 — in the middle of the financial crisis. As of mid-November 2009, prices of the pollution permits were down 50 percent, according to data compiled by Bloomberg.

Meanwhile, the 10 best-performing investment funds with climate change or clean energy as a central goal all plunged 40 percent or more in 2008, according to data compiled by London- based New Energy Finance. The shrinking global economy sapped momentum for developing new environmental projects.

“To mobilize capital now and begin a transformation to new energy technologies is a very risky business,” says Ken Newcombe, founder of C-Quest Capital, a Washington-based carbon finance business that invests in offsets. “Returns have to be reasonable to take on those risks.”

Risk Capital Vital
Newcombe is the former head of Goldman’s U.S. carbon market origination and sales department and one of the world’s first carbon traders. He holds a Ph.D. in energy and natural resource development from the Australian National University. Private money, including capital from banks, hedge funds and other investors, must keep flowing into the system to realize global environmental goals that the Copenhagen meetings will try to hash out, he says.

“The ultimate objective is economic efficiency,” Newcombe says. “How can we reduce the cost of implementing important public policy? Having a pool of risk capital is absolutely vital to the smooth introduction of a cap-and-trade regime in the U.S.”

As Washington debates climate policy in the shadow of the recent financial meltdown, lawmakers have a right to be wary, Newcombe says.

“There’s legitimate concern that there may be unseemly profits or untenable risks,” he says. “But a problem now is that the critical objective of stabilizing the financial system could lead to an overregulation of the carbon market.”

‘Such a Fog’
Meanwhile, the industrial firms that would be affected by cap and trade are eager for the game to begin, says Lew Nash, a Morgan Stanley executive director and the firm’s U.S. point person on the carbon markets.

“There is such a fog right now in terms of how the legislation is going to work,” Nash says. “There is a real economic desire here for price signals that will permit the market to properly price carbon. Our customers have little choice but to participate in this evolving market.”

Nash says his clients aren’t just looking for help figuring out how to use carbon trading to manage their emissions caps. Pricing carbon will also set the tone for strategic investments. If a company wants to build a new factory, for instance, it’s going to need to factor prospective carbon emissions into its construction and operational plans, Nash says.

Supporters of cap and trade see, over many years, a remaking of the U.S. industrial landscape and a sharp reduction in the gases that cause global warming. Little will happen, though, until the debate is resolved between the bankers who want more liquidity and the lawmakers who demand more regulation.

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Introduction to the Renergie Weblog

Posted on November 28, 2009. Filed under: Advanced Biofuel, Hydrous Ethanol | Tags: , , , , , |

Company Milestones
(1) Renergie drafted the legislation (“HB 1270”) for the creation of an advanced biofuel industry development initiative in Louisiana. On June 21, 2008, Louisiana Governor Bobby Jindal signed into law the Advanced Biofuel Industry Development Initiative (“Act 382”). Act 382, the most comprehensive and far-reaching state legislation in the U.S. enacted to develop a statewide advanced biofuel industry, is based upon the “Field-to-Pump” strategy. Louisiana is the first state to enact alternative transportation fuel legislation that moves fuel ethanol beyond being just a blending component in gasoline by including a mandatory variable blending pump pilot program and hydrous ethanol pilot program;

(2) On December 20, 2008, Renergie submitted a testing exemption application to the U.S. Environmental Protection Agency (“EPA”) for the purpose of testing hydrous E10, E20, E30 & E85 ethanol blends in non-flex-fuel vehicles and flex-fuel vehicles in Louisiana. On-site blending pumps, in lieu of splash blending, are used for this test. On February 4, 2009, the U.S. EPA granted Renergie a tampering waiver for the purpose of testing hydrous E10, E20, E30 & E85 ethanol blends in non-flex-fuel vehicles in Louisiana. On February 24, 2009, the U.S. EPA granted Renergie a first-of-its-kind RVP waiver for the purpose of testing hydrous E10, E20, E30 & E85 ethanol blends in non-flex-fuel vehicles and flex-fuel vehicles in Louisiana; and

(3) On October 18, 2007, Renergie submitted a grant application to the Florida Department of Environmental Protection (“DEP”), pursuant to the Renewable Energy Technologies Grant Program, for the purpose of funding the comprehensive development of a sweet sorghum-to-ethanol industry in Florida. On February 26, 2008, Renergie was one of 8 recipients, selected from 139 grant applicants, to share $12.5 million from the Florida DEP’s Renewable Energy Technologies Grants Program. Renergie received $1,500,483 in grant money to design and build Florida’s first ethanol plant capable of producing fuel-grade ethanol solely from sweet sorghum juice. On April 2, 2008, Enterprise Florida, Inc., the state’s economic development organization, selected Renergie as one of Florida’s most innovative technology companies in the alternative energy sector. On January 20, 2009, the Florida Energy & Climate Commission amended RET Grant Agreement S0386 to increase Renergie’s funding from $1,500,483 to $2,500,000.

As a means of introduction for first-time visitors, the following is a list of the currently most popular articles and links on the Renergie weblog.

BP’s Strategy to Limit Liability in Regard to Its Gulf Oil Gusher

BP is Not the Only Responsible Party

BP Oil Spill of April, 2010: Why Class Action Lawsuits May Not be in the Best Interests of Potential Plaintiffs

Regional Greenhouse Gas Cap-and-Trade Programs May be the Solution

The U.N. Approval Process for Carbon Offsets

The Role of Offsets in Climate Change Legislation

Why Carbon Emissions Should Not Have Been the Focus of the U.N. Climate Change Summit and Why the 15th Conference of the Parties Should Have Focused on Technology Transfer

Act 382

Our Nation’s Need to Transition to Hydrous Ethanol as the Primary Renewable Transportation Fuel

The Renergie “Field-to-Pump” Strategy

Florida’s “Port-to-Pump” Advanced Biofuel Initiative

Independent Ethanol Producers in Florida Have the Legal Right to Receive Blender’s Tax Credit

Why the Ethanol Import Tariff Should be Repealed

Independent U.S. Ethanol Producers Will Not Survive as Price Takers

Louisiana Enacts the Most Comprehensive Advanced Biofuel Legislation in the Nation

Why Big Oil Should Not be Allowed to Monopolize the Blender’s Tax Credit

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The Cellulosic Ceiling

Posted on September 5, 2009. Filed under: Advanced Biofuel | Tags: , , , , , , |

By Ryan C. Christiansen
Ethanol Producer Magazine
From the August 2009 Issue

The renewable fuel standard calls for 100 MMgy of cellulosic biofuel to be blended into the nation’s fuel in 2010, ramping up to 16 billion gallons per year in 2022. Will the U.S. produce enough to satisfy the mandate?

By 2022, the U.S. EPA expects the domestic biofuels industry to produce more than 32 billion gallons per year of renewable fuel. However, less than half of that fuel is expected to be corn-based ethanol. The majority, 16 billion gallons, will be cellulosic biofuel. The Energy Independence and Security Act of 2007 defines cellulosic biofuel as renewable fuel produced from any cellulose, hemicelluloses, or lignin that is derived from renewable biomass and has life-cycle greenhouse gas (GHG) emissions that are at least 60 percent less than the baseline life-cycle GHG emissions. The EPA predicts that, in the long run, those 16 billion gallons of cellulosic biofuel will be cellulosic ethanol. However, EISA’s definition for cellulosic biofuel leaves open the possibility that the mandate can be met by other fuels.

Federal Investments
The goal of ultimately producing billions of gallons of cellulosic biofuel has a hefty price tag. Between 2002 and 2008, the U.S. DOE’s Energy Efficiency and Renewable Energy Biomass Program, established to develop and demonstrate biomass feedstock and conversion technologies for integrated biorefineries and to ensure cellulosic ethanol can be produced cost-effectively by 2012, was allocated more than $800 million in federal funding. Since 2007, the DOE has announced more than $1 billion in multi-year investments in cellulosic biorefineries and since 2006 the USDA has invested almost $600 million to develop biofuel technology.

The bulk of the DOE’s investments began in February 2007 when it announced plans to invest $385 million in six biorefinery projects over four years for a total cellulosic ethanol production capacity of 131 MMgy. Combined with the industry cost share, the projects equated to more than $1.2 billion in investments. Projects identified for funding included an 11 MMgy Abengoa Bioenergy SA plant in Kansas, a 14 MMgy Alico Inc. plant in Florida, a 19 MMgy BlueFire Ethanol Fuels Inc. facility in California, a 30 MMgy Poet LLC plant in Iowa, an 18 MMgy Iogen Corp. plant in Idaho, and a 40 MMgy Range Fuels Inc. plant in Georgia.

In May 2007, the DOE announced it would provide up to $200 million over five years to support the development of small-scale cellulosic biorefineries. The first $114 million was allotted in January 2008 for four projects. The companies identified for funding included ICM Inc., Lignol Energy Corp., Pacific Ethanol Inc., and Stora Enso Oyj. The remaining $86 million was allotted to RSE Pulp & Chemical LLC, Mascoma Corp. and Ecofin LLC in April 2008. In July 2008, the DOE announced an additional $40 million investment for two more companies – Flambeau River Biofuels LLC for its project in Wisconsin and Verenium Corp. for its demonstration-scale facility in Louisiana. Seven of the nine plants were funded for cellulosic ethanol and two for cellulosic diesel.

On the research side, both the DOE and the USDA also provided funding to companies and universities. In March 2007, the DOE invested $23 million in five projects to develop highly efficient fermentative organisms to convert biomass material to ethanol; the companies and organizations identified for funding included Cargill Inc., Verenium, E. I. du Pont de Nemours and Co., Mascoma, and Purdue University. In June 2007, the DOE and USDA together awarded $8.3 million to 10 universities for biomass genomic research. During that month, the DOE also announced a $375 million investment in three new bioenergy research centers, including the DOE BioEnergy Science Center, the DOE Great Lakes Bioenergy Research Center, and the DOE Joint BioEnergy Institute.

To close out the year, the DOE awarded $7.7 million in December 2007 to four projects to demonstrate the thermochemical conversion process of biomass-to-biofuels. Then, in February 2008, the DOE invested $33.8 million in four projects to develop improved enzyme systems to convert cellulosic material into sugars suitable for the production of biofuels. The companies identified for funding included DSM Innovation Center Inc. (a partner with Abengoa), Genencor, a division of Danisco A/S, Novozymes A/S, and Verenium.

In March 2008, the DOE and USDA awarded $18 million to 18 universities and research institutes to develop biomass-based products, including biofuels.

To meet renewable fuel standard targets, the U.S. EPA says cellulosic ethanol plant startups must begin in earnest with a few small plants during 2010-’11 and must continue at an increasing pace thereafter with larger plants. The EPA says the rate of growth for the cellulosic ethanol industry should be similar to that of the corn starch-based ethanol industry in recent years.

Finally, in May 2009, the DOE announced that it would provide $786.5 million from the American Recovery and Reinvestment Act to accelerate advanced biofuels research and development and to provide additional funding for commercial-scale biorefinery demonstration projects. Of the total, $480 million will be distributed among 10 to 20 projects for pilot- or demonstration-scale integrated biorefineries that produce advanced biofuels, bioproducts, and heat and power in an integrated system, which must be operational within three years. In addition, $176.5 million will be used to increase the federal funding ceiling on two or more demonstration- or commercial-scale biorefinery projects that were selected and awarded funds within the past two years. Also, $110 million will be used to support new research. Finally, $20 million has been set aside for optimizing flexible fuel vehicle technology, evaluating the impact of higher ethanol blends on conventional vehicles, and upgrading refueling stations to be compatible with ethanol blends up to E85.

Scaling up
To meet renewable fuel standard targets, the EPA says cellulosic ethanol plant start-ups must begin in earnest with a few small plants during 2010-’11, increasing pace thereafter with larger plants. The EPA says the rate of growth for the cellulosic ethanol industry should be similar to that of the corn starch-based ethanol industry in recent years, beginning with 40 MMgy plants from 2010-’13, increasing to 80 MMgy during 2014-’17 and 100 MMgy and upwards during 2018 and beyond. The EPA projects that approximately two billion gallons per year of new plant construction will need to come online between 2018 and 2022. In total, approximately 180 plants will need to be completed by 2022.

However, with only a few months to go before petroleum blenders must begin to use cellulosic biofuels, there are no commercial-scale plants ready to deliver the fuel. Since the DOE’s initial February 2007 funding announcement, very little money has actually been distributed to selected projects. Two of the first six companies to be awarded DOE money – Alico and Iogen – have dropped their applications. Lignol announced in February that it was discontinuing its project as a result of instable energy prices, capital market uncertainty and general market malaise. Meanwhile, subsidiaries of Pacific Ethanol filed for bankruptcy in May.

Abengoa and Poet say they are on track to begin production, but not until 2011. Only Range Fuels, which received an additional $80 million loan guarantee from the USDA in January (the first-ever USDA loan guarantee for a commercial-scale cellulosic ethanol plant), expects to begin producing at near-commercial scale during 2010, with plans to complete the first phase of its planned 40 MMgy facility in Soperton, Ga., early next year.

According to Range Fuels CEO David Aldous, the plant is expected to be mechanically complete during the first quarter of 2010 and commissioning will begin soon thereafter. The plant will produce ethanol from wood chips, he says, and will be scaled up gradually from an initial 20 MMgy capacity. The EPA is predicting that Range Fuels will supply 10 million gallons of cellulosic ethanol toward the cellulosic biofuels mandate in 2010.

Aldous says Range Fuels’ technology is unique. “It is proprietary technology,” he says. “There are a lot of companies that are doing thermal front-end processes, whether they are pyrolysis or gasification, and there are a lot of other companies using different kinds of back-ends, converting the syngas into ethanol, (but) we use a proprietary catalyst on the back end and we use a proprietary technology on the front end.” Prior to leading Range Fuels, Aldous was executive vice president for strategy and portfolio at Royal Dutch Shell plc and also served as president of Shell Canada Products. He is also the former CEO for the Shell Group’s catalyst company, CRI/Criterion Inc.

Meeting the Mandate
To help meet the 100 MMgy cellulosic biofuels target for 2010, the EPA says there will be 24 pilot- or demonstration- scale plants and seven commercial- scale plants producing cellulosic ethanol or cellulosic diesel in 2010. However, ethanol will satisfy only 28 percent of the total cellulosic biofuels mandate. The EPA says the only companies that will produce more than one million gallons of cellulosic ethanol during 2010 are Verenium, Western Biomass Energy LLC, Fulcrum Bioenergy Inc., RSE, Southeast Renewable Fuels LLC, and Range Fuels.

The majority of the cellulosic biofuels volume (72 percent), the EPA says, is projected to come from cellulosic diesel. A small portion (3 million gallons) will be produced by Flambeau River Biofuels at its 6 MMgy plant in Park Falls, Wis., while the majority of all cellulosic biofuels that will be produced, the EPA says, will be cellulosic diesel from Cello Energy (pronounced “sell-oh”), which has a 20 MMgy plant in Bay Minette, Ala. The EPA says to expect 20 million gallons from the Bay Minette plant, as well as 16.67 million gallons from each of three future 50 MMgy plants, which are expected to be swiftly built—two in Alabama and one in Georgia—at locations to be determined.

Feedstock for Cello Energy’s operation can include plant biomass, waste wood, and other organic materials, as well as plastics and used tires. The company uses a catalytic depolymerization technology, the EPA says, to convert the feedstock into short-chain hydrocarbons that are polymerized to produce diesel fuel that meets ASTM standards at a cost between 50 cents and $1 per gallon. The process is reported to be 82 percent efficient and the only energy input is electricity. Allen Boykin, president of Cello Energy, told EPM that the catalyst used by the company is a proprietary catalyst that takes approximately 22 to 25 minutes to convert garbage into fuel oil using a continuous process.

Boykin says Cello Energy’s technology has been in the making for 12 to 15 years. His father, Dr. Jack Boykin, a chemical engineer who served as a Lieutenant in the U.S. Navy from 1961 to 1965, is CEO of Cello Energy and has been conducting the research. Allen says he became involved in 2002 to help bring the system to commercial-scale. Allen says bench-and pilot-scale testing was previously conducted in Prichard, Ala.

Imports to Meet Targets
The EPA admits that because cellulosic ethanol production technology is still developing, production plants will be considerably more complex and expensive to build than corn starch-based ethanol plants, thus requiring much more capital funding as well as design and construction resources. “Although technologies needed to convert cellulosic feedstocks into ethanol (and diesel) are becoming more and more understood, there are still a number of efficiency improvements that need to occur before cellulosic biofuel production can compete in today’s marketplace,” the EPA renewable fuel standard report says. “Additionally, because cellulosic biofuel production has not yet been proven on a commercial level, financing of these projects has primarily been through venture capital and similar funding mechanisms, as opposed to conventional bank loans.”

Alternatively, the EPA suggests that usage targets might be met using cellulosic biofuel that is produced internationally, for example, from feedstocks such as bagasse or straw.

Indeed, as much as 21 billion gallons per year of cellulosic biofuel might be produced outside the U.S. by 2017, the EPA says, the majority from bagasse, but also from forest products, and mostly from Brazil.

A recent report from Novozymes describes how Brazil might produce more than two billion gallons of cellulosic biofuel from bagasse by 2020, which would represent an additional $4 billion in export revenue for that country. Like in the U.S., the development of cellulosic biofuels in Brazil will depend on the industry’s ability to attract the needed investments and political support, Novozymes says.

Despite a slow start for cellulosic biofuels in the U.S., some in the industry are bullish about the future. “Advanced biofuel companies are ready to deploy their technology and begin meeting the requirements of the [RFS],” says Brent Erickson, executive vice president of the Biotechnology Industry Organization’s Industrial and Environmental Section. “Now that the rules of the program are finally moving forward and the Obama administration has demonstrated a firm commitment to the industry, companies are prepared to build the next generation of biorefineries.”

Ryan C. Christiansen is the assistant editor of Ethanol Producer Magazine. Reach him at rchristiansen@bbiinternational.com or (701) 373-8042.

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Independent U.S. Ethanol Producers Will Not Survive as Price Takers

Posted on September 5, 2009. Filed under: Advanced Biofuel, Blender's Tax Credit, Hydrous Ethanol | Tags: , , , , , , |

Chicago Board of Trade Dictates Price of Corn and Oil Companies Control Price of Ethanol
By Brian J. Donovan
July 28, 2009

The issue is whether the proper development of an advanced biofuel industry in the United States is feasible when: (a) independent ethanol producers in the U.S. are at the mercy of volatile commodities markets for feedstock; and (b) the price of ethanol is controlled by the oil companies.

Commodity Market Volatility
The corn-to-ethanol business is highly dependent on corn prices. The price paid for corn is determined by taking the Chicago Board of Trade futures price minus the basis, which is the difference between the local cash price and the futures price. The more corn-to-ethanol contributes to our nation’s energy supplies, the more it drives up corn feedstock prices and consequently its own cost. While increased ethanol production is partially responsible for the increase in corn prices, the main driving factors in the run-up in corn prices are: rising demand for processed foods and meat in emerging markets such as China and India, droughts and adverse weather around the world, a decrease in the responsiveness of consumers to price increases, export restrictions by many exporting countries to reduce domestic food price inflation, the declining value of the dollar, skyrocketing oil prices, and commodity market speculation. It is important to note that excessive speculation is not necessarily driving corn prices above fundamental values. Speculation can only be considered “excessive” relative to the level of hedging activity in the market.

The government’s announcement that it would resurvey corn acreage in several U.S. states launched a rally in Chicago Board of Trade corn on July 23, 2009, giving life to a market that appeared to be sinking toward $3 a bushel. September corn ended up 19 cents to $3.27 a bushel and December corn ended up 19 1/2 cents to $3.38 3/4 a bushel. Traders see the market moving toward the $3.50-$3.75 a bushel range in the December contract. Ethanol futures were also higher. August ethanol ended up $0.065 to $1.597 a gallon and September ethanol ended up $0.064 to $1.555.

Dr. David J. Peters, Assistant Professor of Sociology – College of Agriculture and Life Sciences at Iowa State University, has developed a calculator to determine the long-term economic viability of proposed ethanol plants. Dr. Peters was surprised to learn how sensitive the bottom line is to small changes in corn and ethanol prices. According to Dr. Peters, a typical 100 MGY corn ethanol plant built in 2005 (financing 60 percent of its capital costs at 8 percent interest per annum for 10 years, with debt and depreciation costs of $0.20 per gallon of ethanol produced, and labor and taxes at a cost of $0.06 per gallon) will lose money in the current market:

At $3.25 corn, the ethanol break even price is $1.76 per gallon.
At $3.50 corn, the ethanol break even price is $1.82 per gallon.
At $3.75 corn, the ethanol break even price is $1.88 per gallon.
At $4.00 corn, the ethanol break even price is $1.94 per gallon.

Oil Company Monopoly
U.S. oil companies are using ethanol merely as a blending component in gasoline (in the form of E10) rather than a true alternative transportation fuel (in the form of E85). The major obstacle to widespread ethanol usage continues to be the lack of fueling infrastructure. Only 2,175 of the 161,768 retail gasoline stations in the United States (1.3%) offer E85. These E85 fueling stations are located primarily in the Midwest. According to the U.S. Department of Energy, each 2% increment of U.S. market share growth for E85 represents approximately 3 billion gallons per year of additional ethanol demand.

While alleging an oversupply of corn ethanol, U.S. oil companies, due to a loophole in the Caribbean Basin Initiative, are currently allowed to import thousands of barrels of advanced biofuel (“non-corn ethanol”) every month without having to pay the 54-cent-per-gallon tariff.

Oil companies, or affiliates of oil companies, currently have a monopoly on blending fuel ethanol with unblended gasoline. Many states, e.g., Florida, allow only oil companies and their affiliates to blend and receive the 45 cents-per-gallon blender’s tax credit. This monopoly impairs fair and healthy competition in the marketing of ethanol blends. Independent U.S. ethanol producers have the legal right, and must be assured the availability of unblended gasoline, to blend fuel ethanol and unblended gasoline to receive the blender’s tax credit and be cost-competitive.

In short, independent U.S. ethanol producers do not have bargaining power on either end of the supply chain. Corn ethanol producers are price takers. A comprehensive advanced biofuel industry development initiative is required to disrupt the status quo and establish fair and healthy competition in the marketing of advanced biofuel blends in our nation.

The Louisiana Solution
Louisiana is the first state to enact alternative transportation fuel legislation that includes a variable blending pump pilot program and a hydrous advanced biofuel pilot program. On June 21, 2008, Louisiana Governor Bobby Jindal signed into law the Advanced Biofuel Industry Development Initiative (“Act 382”). Act 382, the most comprehensive and far-reaching state legislation in the U.S. enacted to develop a statewide advanced biofuel industry, is based upon the “Field-to-Pump” strategy.

It is the cost of the feedstock which ultimately determines the economic feasibility of an ethanol processing facility. “Field-to-Pump” does not allow an advanced biofuel producer to fall victim to rising feedstock costs. Non-corn feedstock is acquired under the terms of an agreement analogous to an oil & gas lease. It is not purchased as a commodity. A link exists between the cost of feedstock and ethanol market conditions. Farmers/landowners receive a lease payment for their acreage and a royalty payment based on a percentage of the gross revenue generated from the sale of advanced biofuel. “Field-to-Pump” marks the first time that farmers/landowners share risk-free in the profits realized from the sale of value-added products made from their crops.

Smaller is better. “Field-to-Pump” establishes the first commercially viable large-scale decentralized network of small advanced biofuel manufacturing facilities (“SABMFs”) in the United States capable of operating 210 days out of the year. Each SABMF has a production capacity of 5 MGY. As with most industrial processes, large ethanol plants typically enjoy better process efficiencies and economies of scale when compared to smaller plants. However, large ethanol plants face greater supply risk than smaller plants. Each SABMF utilizes feedstock from acreage adjacent to the facility. The distributed nature of a SABMF network reduces feedstock supply risk, does not burden local water supplies and provides broad-based economic development. The sweet sorghum bagasse is used for the production of steam. Vinasse, the left over liquid after alcohol is removed, contains nutrients such as nitrogen, potash, phosphate, sucrose, and yeast. The vinasse is applied to the sweet sorghum acreage as a fertilizer.

Act 382 focuses on growing ethanol demand beyond the 10% blend market. Each SABMF produces advanced biofuel, transports the advanced biofuel by tanker trucks to its storage tanks at its local gas stations and, via blending pumps, blends the advanced biofuel with unblended gasoline to offer its customers a choice of E10, E20, E30 and E85. Each SABMF captures the blender’s tax credit of 45-cents-per-gallon to guarantee sufficient royalty payments to its farmers/landowners and be cost-competitive. In the U.S., the primary method for blending ethanol into gasoline is splash blending. The ethanol is “splashed” into the gasoline either in a tanker truck or sometimes into a storage tank of a retail station. The inaccuracy and manipulation of splash blending may be eliminated by precisely blending the advanced biofuel and unblended gasoline at the point of consumption, i.e., the point where the consumer puts E10, E20, E30 or E85 into his or her vehicle. A variable blending pump ensures the consumer that E10 means the fuel entering the fuel tank of the consumer’s vehicle is 10 percent ethanol (rather than the current arbitrary range of 4 percent ethanol to at least 24% ethanol that the splash blending method provides) and 90% gasoline. Moreover, a recent study, co-sponsored by the U.S. Department of Energy and the American Coalition for Ethanol, found E20 and E30 ethanol blends outperform unleaded gasoline in fuel economy tests for certain motor vehicles.

Hydrous advanced biofuel, which eliminates the need for the costly hydrous-to-anhydrous dehydration processing step, results in an energy savings of 35% during processing, a 4% product volume increase, higher mileage per gallon, a cleaner engine interior, and a reduction in greenhouse gas emissions. On February 24, 2009, the U.S. EPA granted a first-of-its-kind waiver for the purpose of testing hydrous E10, E20, E30 & E85 ethanol blends in non-flex-fuel vehicles and flex-fuel vehicles in Louisiana. Under the test program, variable blending pumps, not splash blending, will be used to precisely dispense hydrous ethanol blends of E10, E20, E30, and E85 to test vehicles for the purpose of testing for blend optimization with respect to fuel economy, engine emissions, and vehicle drivability. The Louisiana Department of Agriculture & Forestry Division of Weights and Measures will conduct the vehicle drivability phase of the test program. Fuel economy and engine emissions testing will be conducted by Louisiana State University in Baton Rouge, Louisiana. Sixty vehicles will be involved in the test program which will last for a period of 15 months.

Louisiana Act 382 ensures: (a) ethanol producers in the U.S. are no longer at the mercy of volatile commodities markets for feedstock; (b) farmers/landowners share risk-free in the profits realized from the sale of value-added products made from their crops (c) the price of ethanol is no longer controlled by the oil companies; (d) feedstock supply risk, the burden on local water supplies, and the amount of energy necessary to process advanced biofuel are minimized; and (e) rural development and job creation are maximized. Furthermore, due to the advantages of producing advanced biofuel from sweet sorghum juice, the use of sweet sorghum bagasse for the production of steam in the SABMF, and the energy savings of processing hydrous advanced biofuel, the Louisiana solution reduces field-to-wheel lifecycle GHG emissions by 100%.

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Act 382 Creates the Advanced Biofuel Industry Development Initiative

Posted on July 13, 2009. Filed under: Advanced Biofuel, Field-to-Pump, Hydrous Ethanol | Tags: , , , , , |

ACT No. 382








FUELS: Creates the Advanced Biofuel Industry Development Initiative


To amend and reenact R.S. 39:364(A)(1) and to enact R.S. 39:364(A)(4) and Chapter 23-B of Title 3 of the Louisiana Revised Statutes of 1950, to be comprised of R.S. 3:3761 through 3763, relative to the development of a biofuel industry development initiative; to provide for pilot programs; to provide for state incentives; to provide for the purchase or lease of fleet vehicles; to provide for the purchase of biofuels; and to provide for related matters.

Be it enacted by the Legislature of Louisiana:

Section 1. Chapter 23-B of Title 3 of the Louisiana Revised Statutes of 1950, comprised of R.S. 3:3761 through 3763, is hereby enacted to read as follows:



§3761. Legislative findings and definitions

A. The legislature hereby finds and declares that the development of an advanced biofuel industry in Louisiana is a matter of grave public necessity and is vital to the economy of Louisiana. The use of advanced biofuel will expand United States and Louisiana fuel supplies without increasing dependency on foreign oil. The development of an advanced biofuel industry will help rebuild the local and regional economies devastated as a result of hurricanes Katrina and Rita by providing: (1) increased value added to the feed stock crops which will benefit the producers and provide more revenue to the local community; (2) increased investments in plants and equipment which would stimulate the local economy by providing construction jobs initially and the chance for full-time employment after the plant is completed; (3) secondary employment as associated industries develop due to plant co-products becoming available at a competitive price; and (4) increased local and state revenues collected from plant operations would stimulate local and state tax revenues and provide funds for improvements to the community and to the region. Blending fuel-grade ethanol with gasoline at the gas station pump will offer the Louisiana consumer a fuel that is less expensive, cleaner, renewable, and more efficient than unleaded gasoline. Moreover, preliminary tests conducted in Europe have proven that the use of hydrous ethanol, which eliminates the need for the hydrous-to-anhydrous dehydration processing step, results in an energy savings of between ten percent and forty-five percent during processing, a four percent product volume increase, higher mileage per gallon, and a reduction in greenhouse gas emissions. Therefore, an advanced biofuel industry development initiative in Louisiana is vital to ensuring the broad-based rural economic development of Louisiana and is a matter of public policy.

B. The legislature finds and declares that the proper development of an advanced biofuel industry in Louisiana requires the following comprehensive “field-to-pump” strategy:

(1) Feedstock other than corn:

(a) Derived solely from Louisiana harvested crops.

(b) Capable of an annual yield of at least six hundred gallons of ethanol per acre.

(c) Requiring no more than one-half of the water required to grow corn.

(d) Tolerant to high temperature and water logging.

(e) Resistant to drought and saline-alkaline soils.

(f) Capable of being grown in marginal soils, ranging from heavy clay to light sand.

(g) Requiring no more than one-third of the nitrogen required to grow corn thereby reducing the risk of contamination of the waters of the state.

(h) Requiring no more than one-half of the energy necessary to convert corn into ethanol.

(2) The distributed nature of a small advanced biofuel manufacturing facility network reduces feed stock supply risk, does not burden local water supplies, and provides for a more broad-based economic development. Each small advanced biofuel manufacturing facility shall operate in Louisiana.

(3) Advanced biofuel supply and demand shall be expanded beyond the ten percent blend market by blending fuel-grade anhydrous ethanol with gasoline at the gas station pump. Variable blending pumps, directly installed and operated at local gas stations by a qualified small advanced biofuel manufacturing facility, shall offer the consumer a less expensive substitute for unleaded gasoline in the form of E10, E20, E30, and E85.

C. As used in this Section, the following terms shall have the meanings hereinafter ascribed to them:

(1) “Advanced biofuel” means hydrous ethanol derived from sugar or starch (other than corn starch) or anhydrous ethanol derived from sugar or starch (other than corn starch).

(2) “Anhydrous ethanol” means an ethyl alcohol that has a purity of at least ninety-nine percent, exclusive of added denaturants, that meets all the requirements of the American Society of Testing and Materials (ASTM) D4806, the standard specification for ethanol used as motor fuel.

(3) “Hydrous ethanol” means an ethyl alcohol that is approximately ninety-six percent ethanol and four percent water.

(4) “Small advanced biofuel manufacturing facility” means an advanced biofuel manufacturing facility operating in Louisiana that produces no less than five million gallons of advanced biofuel per year and no more than fifteen million gallons of advanced biofuel 1 per year with feedstock other than corn derived solely from Louisiana harvested crops.

§3762. Pilot programs

A. The blending of fuels with advanced biofuel percentages between ten percent and eighty-five percent will be permitted on a trial basis until January 1, 2012. During this period the Louisiana Department of Agriculture and Forestry (LDAF), office of agro-consumer services, division of weights and measures, will monitor the equipment used by a qualified small advanced biofuel manufacturing facility to dispense the ethanol blends to ascertain that the equipment is suitable and capable of producing an accurate measurement. Since there are no ASTM standards for evaluating the quality of the product, the LDAF, office of agro-consumer services, division of weights and measures, will take fuel samples to ascertain that the correct blend ratios are being dispensed and follow the development of standards. Provided that no negative trends are observed during the trial period and fuel standards have been developed or work continues on developing them, the LDAF, office of agro-consumer services, division of weights and measures, will consider extending the evaluation period.

B. The use of hydrous ethanol blends of E10, E20, E30, and E85 in motor vehicles specifically selected by a qualified small advanced biofuel manufacturing facility for test purposes will be permitted on a trial basis until January 1, 2012. During this period the LDAF, office of agro-consumer services, division of weights and measures, will monitor the performance of the motor vehicles. The hydrous blends will be tested for blend optimization with respect to fuel consumption and engine emissions. Preliminary tests conducted in Europe have proven that the use of hydrous ethanol, which eliminates the need for the hydrous-to-anhydrous dehydration processing step, results in an energy savings of between ten percent and forty-five percent during processing, a four percent product volume increase, higher mileage per gallon, a cleaner engine interior, and a reduction in greenhouse gas emissions.

§3763. State incentives

A. The Louisiana commissioner of agriculture and forestry, conditioned upon the availability of funds, is authorized to award demonstration grants to persons who purchase advanced biofuel variable blending pumps which dispense E10, E20, E30, and E85. The demonstration grant shall be for the purpose of conducting research connected with the monitoring of the equipment used to dispense the ethanol blends to ascertain that the equipment is suitable and capable of producing an accurate measurement. The grantee shall also develop guidelines for the installation and use of advanced biofuel variable blending pumps by complying with applicable National Type Evaluation Program (NTEP) and National Institute of Standards and Technology (NIST) requirements and ASTM standards.

B. The Louisiana commissioner of agriculture and forestry, conditioned upon the availability of funds, is authorized to award demonstration grants to persons who purchase vehicles which operate on advanced biofuels. A grant shall be for the purpose of conducting research connected with the fuel or the vehicle and not for the purchase of the vehicle itself, except that the money may be used for the purchase of the vehicle if all of the following conditions are satisfied:

(1) The Department of Agriculture and Forestry retains the title to the vehicle.

(2) The vehicle is used for continuing research.

(3) If the vehicle is sold or when the research related to the vehicle is completed, the proceeds of the sale of the vehicle shall be used for additional research.

C. An income tax credit of ten cents per gallon of advanced biofuel is available to qualified small advanced biofuel manufacturing facilities as defined in R.S. 3761(C)(4). The credit applies only to the first ten million gallons of advanced biofuel produced in a tax year and expires on December 31, 2012.

Section 2.   R.S. 39:364(A)(1) is hereby amended and reenacted and R.S. 39:364(A)(4) is hereby enacted to read as follows:

§364. Purchase or lease of fleet vehicles; use of alternative fuels; exceptions

A.(1) The commissioner of administration shall not purchase or lease any motor vehicle for use by any state agency unless that vehicle is capable of and equipped for using an alternative fuel which results in lower emissions of oxides of nitrogen, volatile organic compounds, carbon monoxide, or particulates or any combination thereof which meet or exceed federal Clean Air Act standards, including but not limited to hybrid vehicles. Alternative fuels shall include compressed natural gas, liquefied petroleum gas, reformulated gasoline, methanol, ethanol, advanced biofuel, electricity, and any other fuels which meet or exceed federal Clean Air Act standards.

* * *

(4) A governmental body, state educational institution, or instrumentality of the state that performs essential governmental functions on a statewide or local basis is entitled to purchase E20, E30, or E85 advanced biofuel directly from a qualified small advanced biofuel manufacturing facility at a price equal to fifteen percent less per gallon than the price of unleaded gasoline for use in any motor vehicle. The price of unleaded gasoline will be the prevailing average price for the locality on the date of purchase.

* * *

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Small-scale Distributed Energy in Wisconsin Benefits Farmers, Local Communities

Posted on July 12, 2009. Filed under: Rural Development | Tags: , , , |

Small-scale distributed energy in Wisconsin benefits farmers, local communities

by Lisa Gibson

Biomass Magazine

April 29, 2009


If Wisconsin would take advantage of “low hanging fruit” and cash in on the state’s biomass potential via small-scale distributed energy systems, advantages would reach both the agricultural sector and rural communities, according to a recently released Program on Agricultural Technologies (PATS) policy perspective. ‘How Could Small Scale Distributed Energy Benefit Wisconsin Agriculture and Rural Communities?’ was published in late April. 

Authors Gary Radloff, director of policy and communications with the Wisconsin Department of Agriculture, Trade and Consumer Protection, and Alan Turnquist, outreach specialist at the Program on Agriculture Technology Studies at the University of Wisconsin-Madison, say a distributed energy system in the state might curb logistical challenges that come along with large-scale, industrial production, such as biomass feedstock aggregation, short-term storage and transportation. “In policy discussion, we need to keep in mind policy incentives for smaller-scale operations,” Radloff said.

“For me, the thing that struck home was that all of these logistics behind biomass are so dependent on location,” Turnquist said of his research. The small-scale distributed energy option is obvious, he said, creating a marriage between the idea of hundreds of thousands of producers and smaller-scale uses.

Wisconsin has almost 15 million tons of potential biomass, the paper states, and if smaller local operations use that feedstock, it could increase energy production opportunities and increase returns for rural communities. It’s not just the scale of biomass potential that makes distributed energy a powerful tool in Wisconsin, but also its diversity, Turnquist said. “The single biggest benefit is that we have the capacity to do it right now,” he said.

Small-scale operations are starting to pop up around the state, according to Radloff, mostly at rural schools. Starting small and building out might be a way to build the biomass-to-energy infrastructure in the state, he added. Some larger projects also are in the works such as Governor Jim Doyle’s order for four university campuses in the state to “come off the grid” and switch to biomass, Radloff said. If more energy is produced locally and used locally, it can complement other renewable energy sources such as wind and solar, Radloff said. The two researchers compare local energy production to something most Wisconsinites can relate to, a local farmer’s market; the money locals spend goes to other locals they might know personally.

It is possible to construct a system in which a portion of the renewable energy dividend stays at home and the long-term benefits are shared by the landowner, farmer, forester or local community, Turnquist and Radloff write, as several biomass technology options can be economically efficient when located in rural settings, as indicated by studies and real world examples.

But what if local people don’t want the energy systems in their communities? According to Radloff and Turnquist, local systems would require local participation, including organization and decision making, that could eliminate the Not In My BackYard (NIMBY) opposition wind farms and new ethanol plants have met. If the payoff and decision-making process stay in the community, locals may rally more support toward community renewable energy products, they said. “It’s not just about natural resources and infrastructure,” Turnquist said. “It’s also about people and communities.”

Opportunities also exist for small-scale projects to partner with larger-scale operations, according to the authors. They cite as an example Xcel Energy’s 2008 proposal to add a biomass-to-energy burner to their existing plant in Ashland, which already uses woody biomass.

The amount of biomass that can be produced and harvested in Wisconsin still is an open question, the paper states, along with how much the communities actually will benefit from bioenergy and other renewables. But, it adds, local energy production is an important part of the state’s economic future and policies should be crafted to ensure the economic and energy returns go to rural Wisconsin residents and that groups undertaking distributed energy projects can manage the risk in the bioenergy market.


About Renergie

Renergie was formed by Ms. Meaghan M. Donovan on March 22, 2006 for the purpose of raising capital to develop, construct, own and operate a network of ten ethanol plants in the parishes of the State of Louisiana which were devastated by hurricanes Katrina and Rita.  Each ethanol plant will have a production capacity of five million gallons per year (5 MGY) of fuel-grade ethanol.  Renergie’s “field-to-pump” strategy is to produce non-corn ethanol locally and directly market non-corn ethanol locally. On February 26, 2008, Renergie was one of 8 recipients, selected from 139 grant applicants, to share $12.5 million from the Florida Department of Environmental Protection’s Renewable Energy Technologies Grants Program.  Renergie received $1,500,483 (partial funding) in grant money to design and build Florida’s first ethanol plant capable of producing fuel-grade ethanol solely from sweet sorghum juice. On  April 2, 2008, Enterprise Florida, Inc., the state’s economic development organization, selected Renergie as one of Florida’s most innovative technology companies in the alternative energy sector.  On January 20, 2009, Florida Energy & Climate Commission amended RET Grant Agreement S0386 to increase Renergie’s funding from $1,500,483 to $2,500,000. By blending fuel-grade ethanol with gasoline at the gas station pump, Renergie will offer the consumer a fuel that is renewable, more economical, cleaner, and more efficient than unleaded gasoline.  Moreover, the Renergie project will mark the first time that Louisiana farmers will share in the profits realized from the sale of value-added products made from their crops.

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Measuring Corn Ethanol’s Thirst for Water

Posted on July 12, 2009. Filed under: Advanced Biofuel | Tags: , , |

Measuring Corn Ethanol’s Thirst for Water

Ethanol from corn consumes three times more water than previously thought.

By Phil McKenna

MIT Technology Review 

April 14, 2009

Ethanol derived from corn consumes up to three times more water than previously thought, according to a new study.

Prior studies have estimated, based on national production averages, that one liter of corn-derived ethanol should require 263 to 784 liters of water to both grow the crop and convert it into fuel. Now, researchers at the University of Minnesota have concluded that the amount of water used in ethanol production varies hugely from state to state, ranging from 5 to 2,138 liters of water per liter of ethanol, depending on regional irrigation needs.

Corn ethanol is already plagued by environmental concerns such as pollution from fertilizer, pesticides, and herbicides; soil erosion; greenhouse-gas emissions from production; and competition for agricultural land with food crops.

The new study, published in the journal Environmental Science and Technology, also found that as corn-based ethanol production has approximately doubled nationwide between 2005 and 2008, related water use has more than tripled.

“Ethanol consumes more water over time as corn production extends to regions that need extensive irrigation,” says Sangwon Suh, an assistant professor of biosystems engineering at the University of Minnesota and coauthor of the study. “That means more water is needed to produce a given unit of ethanol over time.”

Suh and his colleagues examined state and county records on irrigation use for growing corn, both as food and for fuel, as well as the location, production levels, and water usage of existing corn-ethanol facilities. The researchers found that more than 80 percent of the corn used to make ethanol is harvested within a 64-kilometer radius of the refinery where it is converted into fuel. Using this information and data on local rates of irrigation, the researchers were able to estimate the water requirements of individual corn-ethanol production facilities.

In some states, such as Ohio, Iowa, and Kentucky, where corn can grow with little to no irrigation, only five to seven liters of water are required to turn the foodstuff into fuel. Almost all of this water is used to boil, ferment, and distill the biofuel. As ethanol production has increased, however, more corn is being grown in western states such as Nebraska, Colorado, and California, where irrigation needs raise the fuel’s water requirements significantly.

“This is one more nail in the coffin for ethanol,” says David Pimentel of Cornell University, in Ithaca, NY, whose own studies have shown that ethanol requires more energy to produce than it releases when burned, and that the fertilizer used to grow corn for ethanol has contributed significantly to dead zones in the Gulf of Mexico (areas of the ocean with low oxygen content due to increases in chemicals in the water).

The U.S. Energy Independence and Security Act of 2007 mandates that ethanol produced using existing technologies will have to increase from the 34 billion liters produced in 2008 to 57 billion liters per year by 2015. This includes the more arid western states, where corn-based ethanol is currently produced.

Jerry Schnoor of the University of Iowa, in Iowa City, says that ethanol producers are already planning additional production facilities in all states to meet the 2015 goals. “We’re already in an unsustainable situation in terms of water use, already drawing down aquifers like the Ogallala,” Schnoor says of the vast underground water source stretching from South Dakota to northern Texas. “This would exacerbate that decline if we expand in these irrigation states.”

Geoff Cooper, vice president of research at the Renewable Fuels Association in Washington D.C., questions the researchers’ claim that water use has tripling as ethanol production has doubled. “The bulk of expansion from ’05 to ’08 occurred in the central corn belt–places that don’t irrigate corn,” he says. “There is a finite limit to how much ethanol you can put in water-constrained areas. We are not putting ethanol plants into areas where water is severely limited.” Suh is also optimistic that water use can be reduced while ethanol production continues to grow. He says that agricultural land that has been set aside for conservation in regions that do not require irrigation could be brought back into production, and genetically engineered corn could maintain high yields with lower water requirements.

“I’m very optimistic we can achieve the ethanol production mandate without sacrificing water security in the U.S.,” he says. Schnoor adds that ethanol production could expand to the south and east, where land is cheaper and water is more plentiful.

Pimentel, however, disagrees. “You read the paper and the conclusion is certainly that it will require more and more water, but [Suh] is from Minnesota, and you have to be cautious because in Minnesota they are promoting ethanol,” he says.

The study was funded in part by the Department of Energy and the state of Minnesota.


About Renergie

Renergie was formed by Ms. Meaghan M. Donovan on March 22, 2006 for the purpose of raising capital to develop, construct, own and operate a network of ten ethanol plants in the parishes of the State of Louisiana which were devastated by hurricanes Katrina and Rita.  Each ethanol plant will have a production capacity of five million gallons per year (5 MGY) of fuel-grade ethanol.  Renergie’s “field-to-pump” strategy is to produce non-corn ethanol locally and directly market non-corn ethanol locally. On February 26, 2008, Renergie was one of 8 recipients, selected from 139 grant applicants, to share $12.5 million from the Florida Department of Environmental Protection’s Renewable Energy Technologies Grants Program.  Renergie received $1,500,483 (partial funding) in grant money to design and build Florida’s first ethanol plant capable of producing fuel-grade ethanol solely from sweet sorghum juice. On  April 2, 2008, Enterprise Florida, Inc., the state’s economic development organization, selected Renergie as one of Florida’s most innovative technology companies in the alternative energy sector.  On January 20, 2009, Florida Energy & Climate Commission amended RET Grant Agreement S0386 to increase Renergie’s funding from $1,500,483 to $2,500,000. By blending fuel-grade ethanol with gasoline at the gas station pump, Renergie will offer the consumer a fuel that is renewable, more economical, cleaner, and more efficient than unleaded gasoline.  Moreover, the Renergie project will mark the first time that Louisiana farmers will share in the profits realized from the sale of value-added products made from their crops.

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« Previous Entries


    Renergie created “field-to-pump," a unique strategy to locally produce and market advanced biofuel (“non-corn fuel ethanol”) via a network of small advanced biofuel manufacturing facilities. The purpose of “field-to-pump” is to maximize rural development and job creation while minimizing feedstock supply risk and the burden on local water supplies.


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