Earlier today Tom Vilsack, Secretary of Agriculture; Steven Chu, Secretary of Energy; and Lisa Jackson, Administrator of the Environmental Protection Agency (EPA) held a conference call to discuss the Obama Administration’s commitment to biofuels. Highlights of the call were EPA’s issuance of the Renewable Fuel Standard Program (RFS2) Notice of Proposed Rulemaking and the Department of Energy’s (DOE) announcement of $786.5 million in Recovery Act funds to accelerate biofuels research and commercialization.

Secretary Chu indicated that of the $786.5 million in Recovery Act funds, $480 million will go to soliciting integrated pilot- and demonstration-scale biorefineries; $176.5 million to commercial-scale biorefinery projects; $110 million to fundamental research in key program areas; and $20 million to ethanol research. Secretary Chu addressed questions about ethanol’s impact on food prices in the U.S., stating that our agricultural resources can provide food, both domestically and internationally, and much-needed energy.

Administrator Jackson focused on EPA’s commitment to the Energy Independence and Security Act (EISA) and stated that the proposed rulemaking implements EISA and grandfathers in 15 billion gallons of ethanol. She expressed the need for home-grown energy - specifically mentioning corn-based ethanol and cellulosic ethanol - to lower our dependence on foreign oil and our vulnerability to price spikes; reduce GHG emissions; create green jobs, especially in rural America; and meet the RFS of 36 billion gallons of ethanol by 2022. Administrator Jackson renewed her commitment to utilizing the best available science and indicated there would be a 60-day comment period on the proposal.

On the issue of indirect land use, which ClimateIntel previously examined, Administrator Jackson stated EPA is gathering peer reviews on satellite data, land conversion and other factors affecting GHG emissions. She added that EPA’s data shows that corn-based has 16% lower emissions than fossil fuel. She also stressed the need for development of new product technology for non-grandfathered, corn-based ethanol plants and new pathways for biodiesel to meet the 50% reduction required to comply with the EISA.

Secretary Vilsack discussed that USDA will work to create new biorefinery resources and convert existing refineries to biofuels. He indicated that the three agencies have drafted a memorandum that reflects Obama’s commitment to rural US, creates clean jobs and new opportunities, and creates additional income for farmers.

Today’s inter-agency commitment, backed by President Obama, to both corn-based and advanced biofuels is yet another boost to the ailing biofuels industry. In recent weeks, ClimateIntel reported on the Congressional Budgets Office’s report entitled “The Impact of Ethanol Use on Food Prices and Greenhouse-Gas Emissions,” and the E 15 waiver request. So far, at least, it appears that federal policy remains fully supportive of ethanol-based biofuels and reconciliation with the direction of the California-led effort to move away from such fuels remains for another day.

For further information about this topic, please contact Akin Gump.

In the past week, the ethanol industry received two pieces of positive news.  First, the Congressional Budget Office (CBO) issued a report, entitled “The Impact of Ethanol Use on Food Prices and Greenhouse-Gas Emissions,” finding that high energy prices had a much more profound effect on the price of food than increased ethanol production in the period April 2007 through April 2008.  Second, EPA published a notice and solicited comments on a waiver application to increase the amount of ethanol that can be blended into a gallon of gasoline to up to 15 volume percent (E15).

CBO Report

The CBO report concluded that, for the period studied, ethanol production accounted for only 10 to 15 percent of the estimated 5.1 percent increase of food prices.  By comparison, the increase in the consumer price index (CPI) for all urban consumers for energy accounted for 22 percent of the 5.1 percent increase in the price of food.

In analyzing ethanol production’s contribution to the increase in the price of food the CBO assessed how increased ethanol production contributed to increases in the price of corn, animal products and soybeans, and how higher prices for these commodities contributed to the prices of foods that are measured in the CPI-U.  Other contributing factors noted by the CBO include a growing demand for meat that increased the demand for animal feed, dollar exchange rate fluctuations that increased demand for U.S. corn exports and concerns about weather for spring planting that caused corn prices to rise during the spring of 2008.

E15 Waiver Request         

The Clean Air Act authorizes EPA to regulate fuels and fuel additives to reduce the risk to public health from exposure to their emissions.  EPA’s regulations require that each manufacturer or importer of gasoline, diesel fuel or a fuel additive, register its product with EPA before “introducing the product into commerce.”  See generally, 40 CFR Part 79.  Since 1978, EPA has established a limit of ten volume percent ethanol (E10) for conventional (non flex-fuel) vehicles.  Growth Energy and fifty-four ethanol manufacturers submitted their E15 application on March 6, 2009.  After EPA’s Notice has been published in the Federal Register, stakeholders have 30 days to submit comments on the waiver application.  The Clean Air Act requires EPA to rule on the waiver application within 270 days of receipt, December 1, 2009.

There will almost certainly be comments submitted to EPA in opposition to the waiver request.  The National Petrochemical and Refiners Association, the American Lung Association, the Sierra Club, the Engine Manufacturers Association and other groups wrote former EPA Administrator Stephen Johnson on December 18, 2008, to oppose any increase in the 10% limit on ethanol in gasoline.  Among the concerns expressed, with respect to a higher blend, were potential machinery impacts, health and safety issues, emissions and compliance with the Clean Air Act.

EPA’s ruling on the waiver request could give an important signal on the direction the Obama Administration will take with respect to the ethanol industry.

For further information about this topic, please contact Akin Gump.

As noted in last Friday’s post, one of the technological gaps that must be filled to increase the percentage of energy supplied by renewable sources is the need for grid-level energy storage.  The 2007 Energy Independence and Security Act, combined with the 2009 American Reinvestment and Recovery Act (ARRA), makes billions of dollars available for development of new and improved energy storage systems.  This infusion of funding to promote grid reliability provides an important opportunity for the electric power industry to build energy storage into the national grid design.  As utilities, investors, and policymakers assess the best way to do so, however, they will be choosing among a broad suite of potential technologies looking to exploit that opportunity.  In a constantly changing technological environment, making the right choice will be no simple task.  Some of the major types of grid-level energy storage technologies currently in play include:

• Pumped Hydro Storage (PHS): PHS is the most mature and widely utilized energy storage technology in the world, with over 90GW of PHS in use worldwide. PHS generally consists of two reservoirs—an upper and lower—connected by a reversible turbine. During times of low demand, water is pumped from the lower reservoir to the upper; that flow is reversed during times of high demand. Because of the significant capital costs, long construction times, and highly site-specific nature of PHS, little additional construction of these facilities is expected, though using lagoons or other tidal resources to power PHS is an emerging field of research.
• Compressed Air Energy Storage (CAES): In a CAES system, off peak power is used to pump air into an underground storage formation, such as an abandoned mine or a salt cavern. That compressed air is used to turn gas turbines during peak power periods. CAES is the second most commercially mature technology after PHS; two plants—both with over 100MW of capacity—have been constructed, and a number of other projects are planned, including the Iowa Stored Energy Park (ISEP), which will use wind energy in concert with CAES, creating a 268MW/13,000MWh power plant, which will also provide 50 hours of energy storage.
• Thermal Energy Storage: Thermal storage is generally used in concert with concentrated solar power facilities, and involves the circulation of a heat-transfer fluid-generally molten salt, though other advanced fluids are under development-to produce steam during periods when the sun is unavailable to the plant. Examples include the thermal energy storage system storage systems constructed as part of the Solar Two Facility in Southern California, and the massive Andasol solar power plant in Southern Spain.
• Advanced Material Batteries: Advanced material batteries use materials like molten sodium or lithium to store energy. Currently, sodium-sulfur (NaS) and lithium-ion based batteries are the primary designs for these technologies. Currently, sodium-sulfur (NaS) batteries have more fully penetrated the market, as significant numbers have been installed in Japan (where the batteries are produced), including a 34MW battery-currently the largest in the world. Advances in lithium-ion batteries have mostly been directed towards applications in electric cars, but with recent advances in nanotechnology, these batteries are finding use at the utility scale as well.
• Flow batteries: Also known as redox flow-cell batteries or regenerative fuel cells, flow batteries store electricity through a reaction between two different electrolyte solutions. Because the capacity of these batteries is largely dependant on the volume of electrolytic liquid available, these batteries are highly scalable, giving them the potential to compete with bulk storage in terms of charge and capacity. Current battery designs exist around zinc-bromide, sodium-bromide/sodium polysulfide and vanadium solutions. Fewer flow batteries have been installed than the previously mentioned technologies—currently the largest in the U.S. is a 250kW/2MWh plant in Utah.
• Flywheel Energy Storage (FES): FES is another mechanical storage technology, where energy is stored in a rapidly spinning cylinder. When that outside source of energy is unavailable, the rotor for the flywheel acts as a generator. Flywheels are easily moved and have no environmentally reactive components , but have limited storage capacity and a short discharge period, limiting their applicability. The technology is just entering commercial viability: in September 2008, Beacon Power produced the first flywheel storage system for use on a utility scale.
• Superconducting Magnetic Energy Storage (SMES): SMES uses the magnetic field produced by cryogenically cooled superconductors to store energy. By utilizing superconductors, SMES maximizes efficiency (very little energy is lost in the storage process, and there is no conversion between the form the energy is stored in and its usable form—electricity). Like flywheels, however, an SMES system discharges its energy quite quickly, and therefore is useful mostly for short term applications.

The current diversity of storage technologies under active commercial development creates both an opportunity and a dilemma for policymakers and market participants.  The opportunity is that because each technology offers different technical, financial, and political pros and cons, project developers have a broad selection of alternatives to choose from in pinpointing the ideal storage technology to fit the technical, financial, and political constraints facing a project.  The dilemma, in turn, is that given the relative scarcity of long-term performance information for many of these emerging technologies, and the uncertainty regarding whether and when federal policymakers will provide future incentives similar to those provided in the ARRA, policymakers granting funds and the project developers and investors requesting funds will want to get it right the first time.

For further information about this topic, please contact Akin Gump.

As reported earlier, the Department of the Interior (DOI) and Federal Energy Regulatory Commission (FERC) have been negotiating an agreement to outline and clarify the agencies’ respective jurisdiction and responsibilities for renewable energy projects in offshore waters on the Outer Continental Shelf (OCS).  On April 9, Secretary of the Interior Ken Salazar and FERC Chairman Jon Wellinghoff finally signed a Memorandum of Understanding (MOU) to facilitate development of a “cohesive, streamlined process” to accelerate wind, solar, and hydrokinetic (wave, tidal, and ocean current) energy projects on the OCS, ending a long dispute between the agencies.

In short, the MOU preserves the authority of DOI’s Minerals Management Service (MMS) over offshore wind and solar projects and gives MMS authority to issue leases, easements, and rights-of-way for OCS hydrokinetic projects, for which projects FERC will then have exclusive jurisdiction to issue construction and operating licenses or exemptions.  MMS had previously asserted jurisdiction over all energy projects on the OCS, including hydrokinetic projects, and even sought to block preliminary permits issued by FERC.  Specifically, the agencies agree that:

• MMS will retain exclusive jurisdiction over the production, transportation, and transmission of energy from non-hydrokinetic OCS projects;
• MMS will: (1) have exclusive jurisdiction to issue leases, easements, and rights-of-way for hydrokinetic OCS projects; and (2) conduct any necessary environmental reviews for those actions, including reviews under the National Environmental Policy Act (NEPA), while FERC has discretion to act as a cooperating agency in those reviews;
• FERC will not issue preliminary permits for hydrokinetic OCS projects, but will: (1) have exclusive jurisdiction to issue licenses and exemptions for those projects, with active involvement of federal land and resource agencies, including DOI; and (2) conduct any necessary environmental reviews for those actions, including under NEPA, while MMS has discretion to act as a cooperating agency in those reviews;
• The agencies will coordinate to ensure that: (1) hydrokinetic OCS projects meet the public interest, including adequate protection, mitigation, and enhancement of fish, wildlife, and marine resources and other beneficial public uses; and (2) any FERC license or exemption or FERC-regulated operations under an MMS lease, easement, or right-of-way are consistent with the Outer Continental Shelf Lands Act, the Federal Power Act, and other applicable laws;
• MMS may condition leases, easements, and rights-of-way for hydrokinetic OCS projects and FERC will include in any license or exemption for those projects a requirement to comply with the MMS conditions;
• FERC will not issue a license or exemption for any hydrokinetic OCS project until the applicant has obtained an MMS lease, easement, or right-of-way;
• MMS will provide in all leases, easements, and rights-of-way for hydrokinetic OCS projects that construction or operation cannot begin without a FERC license or exemption, unless FERC notifies MMS that no license or exemption is required;
• FERC may inspect hydrokinetic OCS projects to ensure compliance with licenses or exemptions and MMS may inspect those projects to ensure compliance with any applicable lease, easement, or right-of-way; the agencies will work to coordinate inspections through development of joint policies or regulations, as appropriate;
• Each agency will use its own appropriations to fulfill its respective responsibilities;
• The agencies will work together, to the extent practicable, to develop policies and regulations for hydrokinetic OCS projects, including processes to address “hybrid” (wind/hydrokinetic) projects or projects that straddle state waters and the OCS; and
• The MOU is “strictly for internal management purposes,” does not expand or alter the scope of either agency’s authority, and shall not be construed to create any legal obligation on either agency or any private right or cause of action.

The MOU is effective as of April 9, 2009, may be modified only upon further written agreement of the agencies, and can be terminated 120 days after written notice to the other agency.

In a joint press release, Secretary Salazar noted that the MOU “will spur the development of clean, renewable energy,” while Chairman Wellinghoff noted the MOU, “[b]y removing all the regulatory barriers to the development of hydrokinetic energy” on the OCS, “will advance the development of a promising renewable resource” that will benefit consumers.

As noted earlier, however, others have questioned whether the agencies’ agreement will be effective.  For example, Senate Energy and Natural Resources Committee Chairman Jeff Bingaman has expressed doubt that the agreement will actually streamline the development process and both Chairman Bingaman and Ranking Member Senator Lisa Murkowski have suggested that a more definite legislative solution could be included in a forthcoming energy bill.

Even if not fully effective to minimize delays and inefficiencies in developing renewable energy projects in OCS waters, the MOU does end the confusion over the respective jurisdiction of the two agencies.  Still, as suggested by other recent commentary, the MOU does not resolve how MMS will address criticisms lodged against its proposed regulations for alternative energy projects in OCS waters or when either agency will issue further proposed or final rules for their respective processes.  Secretary Salazar has suggested that MMS regulations could be ready in as little as a few months, while the timeline for new FERC rules, if any, remains to be seen.  Both issues will need to be resolved before either agency can begin siting projects.

For further information about this topic, please contact Akin Gump.

At both the federal and state level, expanding renewable energy generation has become a major focus of domestic energy, climate, and economic policy.  Today, twenty eight states and the District of Columbia have adopted some sort of Renewable Portfolio Standard (RPS).  President Obama has voiced his support for a national standard that would mandate a 25 percent share of renewable power by 2025 (up from 2.5 percent today, not counting hydroelectric generation), and that standard is included in a new energy bill introduced by  Congressman Ed Markey (D-MA) and 29 co-sponsors.  If the US is going to deliver on these pledges to increase renewable energy capacity and infrastructure, investments in generation technology will have to tackle an even greater challenge: electricity storage.

According to a report by the American Institute of Chemical Engineers, absent changes to the current electrical grid, pushing renewable energy’s share of the grid above 15% may be technically impractical.  Traditional sources of base-load power—coal and nuclear—provide continuous power to the grid and constantly adapt to changing power demands during each 24-hour period.  In times of increased demand, additional units can be brought online, or the plants can utilize their “spinning reserve”—literally spinning their turbines faster to produce extra power.  Solar and wind power on the other hand, do not have this capacity.  If the sun is not shining (or the wind is not blowing), there is no power flowing from those sources.

The intermittent nature of wind and solar sources means that increasing renewable power’s share of the power flowing into the grid will also increase the grid’s instability, complicating the moment-to-moment process of matching the supply of electricity to the demand.  Absent a technical fix for resolving momentary discrepancies between grid supply and demand, the resulting overloads can lead to rolling or even involuntary blackouts.

One way to address renewable energy’s intermittency problem is through advanced energy storage technologies that can store electricity and release it at periods of high demand (or inconsistent supply), smoothing the peaks and troughs of the energy equation.  While large-scale energy storage is still an emerging technology, a number of companies have already taken steps to commercialize various storage technologies.  For instance:

• In 2006, American Electric Power installed the first large-scale advanced battery, with a 1.2-MW capacity, in West Virginia;
• In the spring of 2008, Xcel energy installed a 1-MW battery at a wind farm in Minnesota;
• In Fall 2008, Altair nanotechnologies, in partnership with AES Solar, announced that their 1-MW lithium-titanate battery had met standards for commercial use in the PJM Regional Transmission Organization, the first lithium battery to do so; (Both AEP and Xcel Energy have batteries based on Sodium-Sulfur technology.) and,
• In November 2008, AES Storage LLC installed a 2-MW battery at an AES facility in in Southern California.

Federal policymakers have also recognized the importance of developing energy storage solutions.  The 2007 Energy Independence and Security Act included a title on “Energy Storage Competitiveness” which authorized the spending of nearly $300 million in each of the next ten years on advanced energy storage technologies. The 2009 American Recovery and Reinvestment Act also included significant funding for advanced batteries, and appropriated another $4.5 billion for the Department of Energy’s (DOE) Office of Electricity Delivery and Energy Reliability for grid modernization efforts, including energy storage. Energy storage companies are already pursing those funds, and the DOE, through Sandia National Laboratories, has established partnership programs focused on advancing battery technology.

Investing in giant batteries, fuel cells, and other advanced energy storage systems designed for the power grid may not draw the same popular attention as is lavished on developments in advanced electric cars, but if the U.S. is to embrace renewable energy in a meaningful way—and meet the mandates it has set for itself—developing the country’s energy storage infrastructure is a must.

For further information about this topic, please contact Akin Gump.

Last week, Secretary of the Interior Ken Salazar and then-Acting Chairman (now Chairman) of the Federal Energy Regulatory Commission (FERC) Jon Wellinghoff announced an agreement between the Department of the Interior (DOI) and FERC to work together to facilitate development of renewable energy projects in offshore waters on the Outer Continental Shelf (OCS).

The agreement signals the end of a long jurisdictional conflict between DOI and FERC regarding oversight of offshore renewable resource development, and has the potential to streamline the regulatory process for development of such resources.  Under the Federal Power Act, FERC regulates hydropower projects in the navigable waters of the United States.  The Energy Policy Act of 2005, however, amended the Outer Continental Shelf Lands Act to expand DOI’s OCS energy resource development power and give DOI parallel permitting authority for the production, transportation, or transmission of non-fossil energy resources on the OCS, including renewable projects.  Since the change, DOI’s Minerals Management Service and FERC disagreed on which agency has primary jurisdiction over offshore hydropower projects, preventing progress in rulemaking and resulting in an absence of federal rules governing renewable energy project development on the OCS.

Under the agreement, Interior will cede primary responsibility to FERC to manage licensing of offshore hydropower projects (e.g., wave and ocean current) using procedures developed for hydropower projects under the Federal Power Act and with the involvement of federal land and resources agencies, including DOI.  DOI will retain jurisdiction over wind projects.  The joint announcement notes that DOI and FERC are preparing a Memorandum of Understanding that will outline the principles of the agreement and the new permitting and licensing process for offshore renewable energy projects.

While Salazar and Wellinghoff, along with various renewable energy groups, praised the agreement for its promise to provide greater regulatory certainty for offshore energy developers and speed project development, others are skeptical that the agreement will be effective.  For example, Senate Energy and Natural Resources Committee Chairman Jeff Bingaman has expressed doubt that the agreement will actually streamline the development process and Bingaman and Ranking Member Senator Lisa Murkowski both have suggested that a more definite legislative solution might be included in a forthcoming energy bill.

For further information about this topic, please contact Akin Gump.

In yesterday’s installment, ClimateIntel discussed California’s draft Low Carbon Fuel Standard (LCFS), which is designed to reduce greenhouse gas emissions in the state by over 16 million metric tons by 2020-nearly 10% of the total reduction goals set by the state. In the draft proposal, California Air Resources Board (CARB) staff set forth an analytical means of calculating relative “carbon intensity” of the competing fuelstocks.  As part of that analysis, CARB staff included a factor for “indirect land use changes” (ILUC). The logic for considering ILUC is that if increased production of a specific type of biofuel in the United States causes a shift in land use, the immediate and future GHG emissions resulting from that land use change should be included in the life-cycle GHG emissions for that biofuel.  The theory for including indirect effects in measure of carbon intensity is generally not controversial.  Difficulties arise, however, when the theory is put into practice.

The debate with respect to the CARB draft proposal centers on the indirect effects of increased demand for certainly biologically-derived fuels and the resulting change in land-use patterns, both locally and globally.  As the report states, “A land use change effect is initially triggered by a significant increase in the demand for a cop-based biofuel.”  That increase demand changes the market dynamics for that particular crop, stimulating increased production, which, “if [it] takes place on land formerly in non-agricultural uses,” results in land use change impacts, such as “the carbon released to the atmosphere from the lost cover vegetation and disturbed soils in the periods following the land use conversion.”

When these land use changes are taken into account, as some studies show, total emissions from biofuels are significantly higher, calling in to question their effectiveness as a barrier to further climate change. This assertion, however, has been fiercely debated, as it requires a number of assumptions about how supply and demand dynamics affect land use, and what practices are used in the production of crops for fuel stocks.

The crux of the debate seems to derive from the notion that many factors drive land use changes.  Other factors that influence land use changes includes urbanization, economic growth that drives demand for land-based food, population growth, feed and fiber production, and extracting lumber or mineral resources.  Perhaps even more important, the modeling of indirect effects should consider the different and rapidly evolving land use policies of the United States and other nations.  The land use impacts of these factors are difficult to quantify and there is considerable uncertainty about predicting their future magnitude and effects.  

In California, the LCFS is determined by examining the carbon intensity of various fuels. When examining corn and sugarcane based biofuels, the analysis included emissions due to indirect effects-to the dismay of some researchers and biofuel executives, who argue in a letter to the California Air Resources Board that the land use analysis is over sensitive and weighted against crop-based fuelstocks.

With indirect land use change included in the analysis, three production methods for creating ethanol (called “pathways” in the report) had comparable or higher emissions than traditional fuels. All three were produced with Midwestern corn stock, though the bulk of their emissions came from direct effects, such as the transport of the products into California.

Actions in California may provide a template for national action: the U.S. Environmental Protection Agency (EPA) has also proposed to consider these indirect land use changes in its national Renewable Fuel Standard, though it has not yet decided how to make those calculations. As with the decision by the state of California, EPA’s decision has also engendered both criticism and praise.

For further information about this topic, please contact Akin Gump.

So-called first and second generation biofuels share a common challenge—how to show that biofuels represent life-cycle greenhouse gas emissions savings as compared to traditional fossil fuels. The issue also causes breaches in the biofuels industry because the greenhouse gas emissions savings of different biofuels can vary substantially.  A universally accepted regulatory tool for answering the question is “life cycle analysis.” Life-cycle analyses for renewable fuels seek to quantify the greenhouse gas emissions created by the manufacture of the fuel, including its inputs, through transportation to the consumer, use and disposal.  Under the 2007 Energy Independence and Security Act, biofuels qualify for the new renewable fuels standard (RFS) only if all carbon emissions associated with their production and use result in emissions savings of at least 20 percent.  California Assembly Bill AB 32 and the Governor’s Executive Order S-01-07 call for a reduction of at least 10 percent in the carbon intensity of California’s transportation fuels by 2020.  These projected emissions savings thresholds face technical challenges in measuring life cycle emissions savings and political battles as the various stakeholders jockey for position.  The resulting uncertainty contributes to limitations on investment flows in biofuels.

Under the 2007 Energy Independence and Security Act, renewable fuels must meet life-cycle emissions reduction targets for renewable fuels to qualify for the Renewable Fuel Standard (RFS).  Any renewable fuel produced in a facility under construction as of December 2007 must meet a threshold 20 percent reduction from a 2005 baseline, which is generated by measuring the 2005 life-cycle greenhouse gas emissions of traditional fuels.  Beginning in 2009, the subcategories of renewable fuel created by the act (cellulosic biofuel, advanced biofuel and biodiesel) must meet life-cycle greenhouse gas emissions reductions of between 50 percent and 60 percent from the 2005 baseline before consideration for the RFS.

In California, the California Environmental Protection Agency is required to coordinate activities between the University of California, the California Energy Commission and other state agencies to develop and propose a draft compliance schedule to meet the 2020 target.  Furthermore, the California Air Resources Board (CARB) identified the establishment and implementation of the Low Carbon Fuel Standard (LCFS) as an early action item with a regulation to be adopted and implemented by 2010.

As we reported on ClimateIntel, on March 5, 2009, (CARB) released its proposed regulation for establishing an LCFS. The proposed “cradle to the grave” regulation takes into account emissions associated with the full life-cycle of transportation fuels, including (1) direct emissions associated with producing, transporting and using the fuels, and (2) indirect emissions associated with other effects, such as those caused by land use changes.   The U.S. Environmental Protection Agency (EPA) is in the process of developing a similar rule as part of the development of a federal RFS

Compliance with these thresholds requires resolution of just how to measure life-cycle greenhouse gas emissions.  The sheer complexity of the analysis, including disagreements as to the appropriate methodology for measuring greenhouse gas emissions, has made LCFS rulemakings a difficult endeavor.  In 2007, as part of its rulemaking establishing the 2005 RFS, EPA determined that “the current state of scientific inquiry surrounding life-cycle analyses is not sufficiently robust to warrant its use.”  The science has not developed sufficiently since to allow for consensus on this issue, and rulemaking establishing a uniform methodology is likely to be controversial.

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Broadly speaking, biofuel refers to any solid, liquid or gas fuel that has been derived from biomass. It can be produced from any carbon source that is easy to replenish—such as plants.  One of the main challenges when producing biofuel is to develop energy that can be used specifically in liquid fuels for transportation. The most common strategies used to achieve this are to grow plants that naturally produce oils, grow sugar crops or starch that can be fermented into ethanol, or converting “wood” products. 

Over the past year, significant controversies have developed over biofuels related to the extent to which biofuels actually result in reduced carbon emissions, which led to efforts to make “life cycle analyses” to determine the net carbon footprint of biofuels.  Spot food shortages in 2008 led to calls for analyzing whether increased biofuels production leads to food shortages.  In a multi-installment series, ClimateIntel will analyze several issues related to biofuels and the legal and regulatory challenges biofuels face.

The American Recovery and Reinvestment Act of 2009, the Stimulus Bill, includes significant funding and related incentives for development of second generation biofuels.  Earlier this year, the U.S. Departments of Energy and Agriculture  announced a joint funding opportunity pursuant to which $25 million would be awarded to fund biomass research and development.  The funding is directed to researching second generation biofuels, specifically the three technical areas specified in the Food, Conservation, and Energy Act of 2008:

1. “feedstocks development;”
2. “biofuels and biobased products development;” and
3. “biofuels development analysis.” 

Secretary of Energy Steven Chu noted that the biofuels industry should “focus[] on the next generation of biofuels.”  Despite the attention paid to second generation biofuels, however, first generation biofuels still figure prominently and are the only commercially available form of biofuels. 

Recently, the International Energy Agency produced a report comparing first and second generation biofuels.  First generation biofuels are mainly produced from agricultural crops used for food and animal feed, with the two most common sources being sugar cane and maize (corn).  The first generation biofuels market is relatively mature, particularly in the United States, Brazil, and Europe.  Of the three major forms of fuels currently produced, bioethanol, biodiesel, and biomethane, the market is largest for the liquid fuels bioethanol and biodiesel. 

Currently 80% of the world’s ethanol production is derived from sugar cane and corn, based on well-established conversion technologies.  Starch, the raw material from corn and other feedstocks, must first be converted to glucose through a hydrolysis process before ethanol may be produced.  Once the glucose is formed, it goes through a fermentation process during which it is metabolized by yeast cells.  Ethanol is then produced by distilling the product of the fermentation processes.  Sucrose is the raw material from sugar cane, and undergoes the same fermentation and distillation processes as glucose to form ethanol.  The difference is that pressed sugar cane yields sucrose, so it does not have to undergo the hydrolysis step required of starch. 

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Akin Gump Strauss Hauer & Feld: Renewable Energy Alert

President Obama‘s first budget provides an early demonstration  of his spending priorities dedicated to advancing renewable energy and climate change goals. While the president’s budget is not binding, it outlines policy priorities through the remainder of his term. The president’s energy priorities reflect a shift away from fossil fuels to lower-carbon and renewable sources. The budget seeks to double renewable energy capacity, support expansive energy efficiency investments and create millions of “green” jobs. The budget would impose additional costs upon fossil fuels beginning in 2011, after anticipated economic recovery. Specifically, the proposed budget establishes new leasing costs and fees on mineral development on federal lands and anticipates revenues from an economy-wide greenhouse gas cap-and-trade program beginning in 2012.

President’s Budget Seeks Spending to Strengthen the Renewable Energy Industry

The president’s budget characterizes investments in the renewable energy sector as providing three main benefits.

• First, as technology, it will allow the United States to shift away from foreign oil and other fossil fuels, providing a benefit to national security.
• Second, the budget looks to the sector as a catalyst for domestic innovation, international competitiveness and job growth.
• Third, it looks to renewable energy as a resource to limit greenhouse gas emissions.

The budget proposes to fund investments in clean and renewable energy primarily through Department of Energy (DOE) programs. The proposed DOE budget builds upon the approximately $39 billion in appropriations made through the American Recovery and Reinvestment Act of 2009 (stimulus bill) and seeks to position the United States as a world leader in clean energy and climate change technology. Within the DOE, the budget’s spending priorities mirror those established in the stimulus bill. Specifically, the budget provides support for loan guarantees for innovative energy technologies that will reduce greenhouse gas emissions. The budget would make funding available to modernize U.S. transmission and distribution infrastructure. The budget supports extensive research and development, demonstration, deployment and commercialization of clean energy technologies, including biofuels, renewable energy and energy efficiency projects.

The budget allocates additional funding to support the renewable energy industry to Departments other than DOE. The Department of Interior receives $50 million to conduct environmental impact assessments and other technical studies to allow for increased renewable energy development on federal lands. Funding is also made available to the Department of Labor to provide renewable energy job training programs. To support rural renewable energy programs, the Department of Agriculture receives $250 million for loans and grants for renewable energy projects, including wind energy and biofuel development.

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