Economic Aspects of Biofuels Production:A Feasibility Approach to Project Evaluation

Shannon L. Ferrell1, Philip Kenkel2, Rodney Holcomb3

1 532 Agricultural Hall, Oklahoma State University, Stillwater, Oklahoma USA 74078, shannon.l.ferrell@okstate.edu

2 516 Agricultural Hall, Oklahoma State University, Stillwater, Oklahoma USA 74078, phil.kenkel@okstate.edu

3 114 FAPC, Oklahoma State University, Stillwater, Oklahoma USA 74078, rodney.holcomb@okstate.edu

Keywords: biofuels, economic engineering, feasibility assessment, regulation

ABSTRACT

Determining the economic viability of a biofuels project is a complex process that must take into account both the potential costs and revenues from the project and the regulatory environment in which it must operate. This paper discusses the steps necessary to evaluate the economic viability of a biofuel venture, focusing on include economic engineering and feasibility assessment. Economic engineering ties the physical parameters of the facility with assumed cost factors for materials, labor, utilities, and supplies. The economic engineering analysis will then serve as a foundation for a feasibility assessment. Feasibility assessment includes market assessment, project scoping, financial projections, and risk analysis. Market analysis of feedstock availability and costs may be complicated if an existing market for the feedstock is not available. In the scoping and financial projection stage of the assessment, components from the prior analyses are examined to coordinate key project milestones and to evaluate profitability. Sensitivity analysis can determine if the project will meet its feasibility criteria (which may often be simplified to a given rate of return), which will, in turn, drive the capital availability analysis which will compare the estimated financial performance of the project to the needs of various capital and debt financing sources.

Beyond the financial environment of the biofuels project, the regulatory environment will also have an important impact on the configuration and operation of the facility. While securities regulations may pose costs on capital formation, significant federal tax incentives can also serve as an inducement to potential investors and, the Federal Renewable Fuels Standard presents the possibility of an improved biofuels market. However, biofuels facilities must also contend with a broad array of environmental regulations including detailed requirements for handling air, water, and waste emissions, as well as a host of other novel issues such as alcohol production registration in the case of ethanol plants.

Fortunately, the factors impacting the economic performance of biofuels facilities continue to be the subject of widespread research. An important product of this research has been feasibility templates that help prospective biofuels project developers to quickly examine several key variables of their project and its sensitivity to changes in input and output markets. One such tool is the Cellulosic Ethanol Feasibility Template created by Oklahoma State

University. Results from the template are presented later in this paper to illustrate an example of biofuel economics.

INTRODUCTION

Most discussions of biofuel technology eventually come to the question of “what are the economics?” When most people refer to the economics of biofuel, they are interested in whether the project is economically feasible and could attract the equity, debt capital and community support to make it a reality. Economists address these questions through economic engineering and feasibility analysis. Additionally, since fuel production is also one of the most intensely regulated industries, an overall feasibility analysis must also consider the legal, policy, and regulatory systems that must be satisfied if a project is to be approved for construction and operation.

ECONOMIC ENGINEERING AND FEASIBILITY ASSESSMENT

Economic engineering models are mathematical or computer-based representations of production processes in which engineering and economic information are combined. The engineering information includes the specifics of building (or facility) construction and equipment, but also includes quantitative information on such items as labor, utilities, and supplies. The economic component of the model involves determining costs for all plant inputs (Criner 1992). For example, utility costs are estimated based on motor horsepower and process heat requirements, while labor costs are determined by the equipment and infrastructure compliment. Economic engineering depends on a detailed engineering design, and/or accepted cost formulas. An economic engineering analysis of a biofuel production process would use engineering information to specify the equipment compliment and use standardized cost formulas to estimate the costs of tanks, buildings, and other infrastructure. Economic engineering information is an important component, but by no means the only important component, of feasibility assessment.

As the name implies, a feasibility assessment determines if a business venture or project is viable. More specifically, the feasibility study determines if the project will generate adequate cash-flow and profits, withstand the risks it will encounter, remain viable in the long-term, and meet the goals of the founders (Hofstrand and Holz-Clause 2006). The feasibility study incorporates economic engineering information to determine production costs and capital requirements, but also considers many other components such as market demand and access, raw material supply, technical feasibility, financial projections, including risk analysis and personnel and management, feasibility criteria, and legal, policy, and regulatory issues. The feasibility study must also consider the costs, time path, and working capital requirements for the entire project development process.

In the past, standardization in first generation ethanol and biodiesel plants simplified the process of feasibility assessment. A few prominent equipment firms, as their experience in biofuels grew, developed a standardized design technology that cut construction costs in half while reducing project development time by six to nine months (Crooks and Dunn 2005). Technology standardization in grain-based ethanol production resulted in the development of

“cookie cutter ethanol plants,” which minimized construction time while offering predictable construction costs and operating performance. The standardization made it possible for project developers to work with a single company that would offer a firm price for a turn-key plant and guarantee start-up performance. However, developers of second generation biofuel plants face a much more difficult and less predictable development process, particularly when ascertaining the feasibility and sustainability of the project.

Market FeasibilityThe first component of a feasibility study is to determine market demand, market

requirements, and market access. Biofuel markets are somewhat defined, and daily price reporting gives an indication of current market values, but forecasting biofuel prices is still a major area of uncertainty. The value (or disposal costs) of the co-products streams are much more difficult to determine. As an example, production of ethanol from sweet sorghum generates bagasse (residual stalk material) and vinasse (residual liquids from the juice extraction). Technically, burning bagasse to create process heat and/or cogenerate electricity is possible (Monti and Venturi 2003); Gnansounou, Dauriat, and Wyman 2005). The value of vinasse based on fertilizer value is in the neighborhood of $2.50/ton, but some recent studies have assumed a livestock feed value for vinasse, with a higher solids content, closer to $40/ton (Morris 2008). Any of these assumptions implies a local market will exist, and that transportation and handling costs do not erode the entire value of the co-products.

Engineers like to envision next generation bio-refineries with a broad portfolio of co-products; however, complicated trade-offs occur in processing the co-products to generate additional revenue streams or to decrease waste handling costs. For example, the possibility of co-generation raises regulatory issues, and the value of surplus electricity varies widely depending on access to the power grid and the utility company policies. As another example, next generation bio-refineries may also produce a number of other alcohols and chemical compounds in addition to ethanol, each with a recognized use but requiring considerably more processing to separate. Separately, these chemical compounds have market value, but collectively, they are a volatile waste product.

Raw MaterialThe next component of a feasibility study relates to the adequacy, consistency, and costs

of the raw material supply. For grain-based ethanol and biodiesel derived from oilseeds (such as soybeans, canola/rapeseed, sunflowers, and cottonseed), the feedstock markets coincide with food/feed markets for these grains and oilseeds. Procurement of the raw materials in an area of considerable corn or soybean production may only be a matter of establishing an existing elevator as a delivery point, with the plant’s feedstock procurement costs simply being the current market price plus a handling/delivery charge. Biofuel production in feedstock-deficit regions may be more challenging, as local producers may have to be enticed to adopt the feedstock in their crop rotations (Kenkel and Holcomb, 2006).

Designated biofuel crops represent additional challenges to the economic viability of a venture. As an example, no daily price reporting points or futures markets exist for switchgrass, nor are there valuable alternative uses (food or feed) for this crop compared to corn. Unlike corn or other grains, switchgrass is a perennial plant with a 10-year production horizon, and

without the decades of agronomic research associated with most grains and oilseeds. Because of limited information on yield potential and variability, producers need financial incentives to dedicate their land to the production of one crop for an extended period (Popp 2007). These factors require a plant to contract production of the crop, possibly with some portion of the payment provided up front, to overcome the opportunity costs of foregoing more “traditional” crops (Epplin et al. 2007, Khanna and Dhungana 2007, Bangsund, DeVuyst, and Leistritz 2008; Kenkel and Holcomb, 2009).

The geographical density of production in relation to the biofuel refinery location and the contractual structure of the raw material purchase have major implications on the plant gate cost. Unless the biofuel crop has an alternative use, the refinery must be sized to accommodate the highest expected yield. This necessity implies that the biofuel plant will typically operate at significantly less than full capacity, a factor that must be considered in cost forecasting. The consistency of raw material and the effect on throughput is also often a risk factor. Projects considering multiple feedstocks must analyze the increased equipment needed to handle different input streams and the downtime needed to change operations.

Technical FeasibilityThe previously described economic engineering information is used to determine the

technical feasibility of a biofuel production process. The technical feasibility aspect of the feasibility study includes a review of technology options including heat and material balances. Scale economies must be determined or estimated, and the basic design and capabilities of the technology must be determined. The analysis of technical feasibility must also consider the activities and associated costs of project development.

Project Development CostsThe first stage of project development, often called the scoping stage or front end

engineering design, expands on the technical requirements to determine the costs for a specific site. Key process equipment, utilities, infrastructure (such as roads, docks, and rail), and other major factors must be identified and budgeted. For unique or long-lead equipment such as a distillation tower, the size of the tower, materials of construction, internal packing material, and other factors necessary to determine how a specific piece of equipment will function must be finalized. Regulatory and permitting issues must be determined as early as possible so these activities can begin concurrently with the other project development steps (see the discussion of regulatory issues below).

The next step in the development process is to create a detailed design. In this phase of the project, the scoping documents are refined so that a contractor can construct the facility. The engineering team must design foundations, instruments, building structures, electrical supply systems, and other ancillary equipment that, when added to the engineered equipment, form a fully functional operating facility. The detailed design stage creates a set of specifications and construction drawings that are used in procurement. Because process designs for second generation biofuel production processes have not been standardized, this phase of the project development can involve large investments in both time and money.

Key engineered equipment must be specified and purchased early in the process to allow the detailed design to be completed. Items such as gasifiers, reactors, distillation towers, heat exchangers, large tanks, distributed control systems, and other items that are not “off the shelf” items are part of this procurement cycle. A significant down payment is required with an engineered equipment order, with milestone payments along the way. The timeline of the project is often driven by the vendors’ ability to supply the shop drawings previously noted, since they are necessary for the detailed design to move forward. Other key construction materials (concrete, structural steel, pipe, valves, and other related items) are typically purchased by the construction contractor within their scope of work (Warner 2009).

Construction of large-scale projects is typically managed by a general contractor who is responsible for the overall project, even though that contractor’s company may sub-contract major portions of the work. The construction phase of the project ends in “mechanical completion,” which is the point when the facility is fully constructed and operable, but has not been charged with raw materials or tested (Warner 2009). Contractors for second generation biofuel projects are unlikely to provide performance guarantees, nor will they manage or guarantee the start up process.

When the project is mechanically complete, the start up or commissioning process must be performed. Equipment is often tested with water and inert gasses to make sure basic functions are confirmed (for example, pumps are able to pump, tanks do not leak, and boilers produce steam), and instruments are calibrated. Once each of the systems has been commissioned, raw materials will be introduced, and the plant begins operation. The first few months of operation are referred to as the “shakedown” period, when product is being made but usually at less than the nameplate capacity of the plant (Warner 2009). At this point, a formalized, third-party-administered performance test is generally required by financial institutions to confirm that the key operating parameters within the project pro-forma are justified. These parameters include demonstration of plant production capacity, along with usage of key raw materials and utilities. This test is normally run for a seven-day period and is overseen by an independent engineering firm. As this discussion has suggested, biofuel project development involves a complex and inter-related set of activities. All of these steps involve costs, time, and risk that must be factored into the feasibility assessment.

Financial ProjectionsThe next step in feasibility assessment is to create the financial projections. The overall

capital needs must be determined, and the equity and credit needs must be forecasted. Capital needs estimates must consider plant and equipment costs, project development costs, and working capital needs during both the start-up and operating time periods. Forecasts must account for the possibility of increased plant costs due to changes in steel and concrete prices. Capital needs are also heavily impacted by the delivery and installation costs for equipment, which may equal the price of the equipment. Lenders are increasingly limiting their exposure based on the dollars per gallon of production capacity. Project developers must therefore be prepared to raise additional equity capital to meet unanticipated development costs.

Risk AnalysisThe financial analysis must also budget and project all costs and returns and determine

the expected net profit. Risk analysis is also a major component of the feasibility study. The sensitivity of profits to changes in key variables must be identified and the breakeven points determined. While a sensitivity analysis can highlight the raw material prices, biofuel prices, production levels, and other factors that must be achieved to maintain profitability, forecasting the likelihood of those levels is a difficult task. During most of the 2005 to 2008 period, ethanol plant profitability was fairly dismal due to unfavorable corn/ethanol price ratios. While modeling the impacts of changes in one or more prices or production factors is relatively simple, simultaneously predicting future raw material prices, biofuel prices, interest rates, and regulatory costs is extremely difficult.

Feasibility CriteriaA final component of the feasibility study is to identify an appropriate benchmark, such

as a minimally acceptable internal rate of return for the project, and determine whether the project is viable. Simulation analysis may also be incorporated to determine the probability of the project achieving the benchmark or maintaining specific cash flows. While project developers and equity suppliers are interested in generating return on investment, lenders are focused on risks and assurance of repayments. Lenders often demand that a project meet a separate set of criteria such as loan payment and fixed charge coverage ratios and working capital levels.

Capital AvailabilityThe availability and cost of capital is a key aspect of the feasibility of a biofuel project.

As the corn-based ethanol industry developed, specialized sources of debt financing arose. A key group of lenders developed the expertise to examine feasibility studies in great depth and analyze access to feedstocks, energy supply, transportation, water, and other project variables. As the capacity of these lenders was exhausted and the scale of projects increased, project developers were forced to turn to money-center banks and private equity firms (Alexander and Alcala 2006). These capital suppliers had a relative lack of experience with ethanol venture financing and did not have long-term relationships with the developers. As a result, these lenders demanded increased documentation with covenants (both affirmative and negative) that controlled critical aspects of business operations and applied a higher level of scrutiny to project contracts and to project-related risk management. All of these factors make it difficult to predict whether a particular project can access sufficient equity, long term debt, and working capital to assure the venture’s viability.

Financial troubles facing both grain-based ethanol plants and biodiesel plants over the past two years, due in large part to unfavorable grain-to-biofuel price spreads, have limited the involvement of “traditional” capital sources and lenders in biofuel ventures. Advanced biofuel ventures have likewise felt the impact of concerns regarding technology and cost issues on capital investment, but government mandates and assistance programs have sparked research and development investment (Rajagopal et al. 2006). Biofuel ventures have also started pursuing alternative sources of capital: grants, cooperative agreements, and loan guarantees through the U.S. Department of Energy (DOE); grants and loans through USDA rural development programs, hedge funds, insurance companies, and even foreign corporations. State and local

financing authorities may also be potential sources for “creative” capital through tax-exempt facility bonds used for the construction of solid waste disposal facilities, wherein the waste disposal relates to the operations of the biofuel facility (Morgan 2008).

LEGAL, POLICY AND REGULATORY CONSIDERATIONS

Regulatory and public policy issues are also another major factor impacting the economic viability of biofuel projects. Subsidies, tax credits, and biofuel usage mandates impact biofuel demand, price levels, and profitability. A wide range of regulatory and permitting issues impact the cost or even the possibility of developing a biofuel project in a particular location. Financing, building, and operating any large agricultural processing facility involves a confluence of several areas of law. This is most certainly true in the case of a biofuels facility, since anyone looking to establish such a project will face issues ranging from securities regulation to calculating available incentives and credits, and from environmental permits to alcohol production facility registration. While volumes could be written about any one of these areas individually, a brief overview of some of the critical issues follows.

Securities Registration

Unless a large, well-capitalized entity is looking to diversify into biofuels production on the strength of its own equity reserves or balance sheet, the construction of a biofuels facility likely requires a significant capital-formation effort that includes the sale of some form of “security” such as corporate shares, limited liability company (“LLC”) units, or similiar items. The issuance and initial sale of securities is regulated at the federal level by the Securities Act of 1933 (15 U.S.C. §§ 77a et seq.). Because the Securities Act was targeted at dealing with many of the bad practices leading to the stock market collapse of 1929, the act defines the term “security” quite broadly and thus encompasses a vast array of investment vehicles. Generally, securities must be registered with the Securities and Exchange Commission (“SEC”) prior to being offered for sale. This registration can be a long and highly complex process often costing registrants hundreds of thousands of dollars in legal fees (Gofourth 2002).

In some circumstances, however, groups looking to form a biofuel venture may potentially qualify for one of the Securities Act’s registration exemptions. However, although a federal securities registration exemption may apply, state securities regulations may also possibly apply to the offering). A handful of these exemptions are frequently used by ventures that will be at least partially or completely owned by the feedstock producers themselves. The first exemption is the “intrastate exemption” that requires that the security in question may only be offered and sold to residents of the same state in which the business operates. Although this exemption imposes no upward limit on the number of investors or the amount of capital that can be raised, it is also very fragile in that the subsequent sale of a security to an out-of-state resident can negate the exemption with respect to the entire offering (Hazen 2003). A second exemption is the “agricultural cooperative” exemption. This exemption also has no upward limits on the number of investors or amount of capital that can be raised, as long as the “issuer” satisfies all the requirements to meet the definition of an “agricultural cooperative” as found in Internal Revenue Code Section 521 (26 U.S.C. § 521) (Gofourth 2002). However, this exemption carries its own limitations because the Section 521 cooperative definition imposes restrictions on returns

to investment and allocation of voting rights that many significant investors may find unappealing and may even be at odds with the purposes of investors’ participation in the project (Ferrell 2002).

Credits and Incentives

At the federal level, three important incentive programs are targeted at biofuels production: income tax credits, excise tax credits, and the Federal Renewable Fuels Standard. Each program takes a slightly different approach to encouraging biofuels development.

Income Tax Credits: Income tax credits for ethanol producers consist of three components. 26 U.S.C. § 40 provides an “alcohol fuels credit” that consists of an “alcohol mixture credit,” an “alcohol credit,” and a “small ethanol producer credit.” The alcohol mixture credit provides a credit of $0.60 per gallon of alcohol used by a facility in producing a “qualified mixture” (a mixture of alcohol and gasoline sold by the facility for use as a fuel). The alcohol credit also provides a credit of $0.60 per gallon of alcohol (if the alcohol is not mixed with anything but a denaturant) that is sold by the alcohol producer “at retail to a person [using the alcohol as fuel] and placed in the fuel tank of such person’s vehicle.” In other words, the alcohol credit applies to facilities that both produce alcohol fuel and sell it directly to customers at retail. Lastly, the “small producer credit,” also called the “Small Ethanol Producer Tax Credit” (SEPTC) allows a credit of $0.10 per gallon of qualified ethanol fuel production to producers whose facilities have a productive capacity of 60 million gallons per year or less. “Qualified ethanol fuel production” means ethanol that is sold by the producer to another person for use as a fuel, as a fuel component, or for retail sale (26 U.S.C. § 40(b)(4)(B)(i)). While this credit is available to producers with a capacity of up to 60 million gallons per year, and the credit is only applied to the first 15 million gallons of production, a producer could only receive a maximum of $1.5 million in credits per year. At present, all three alcohol credits are scheduled to sunset after December 31, 2010.

The most recent revisions to the ethanol credits provide additional incentives for the production of biofuels from cellulosic processes, known as the “cellulosic biofuels producer credit.” If a facility produces cellulosic biofuel, then it may receive a $1.01 per gallon tax credit. If the biofuel is an alcohol, the credit is reduced by the amount of the alcohol mixture credit or the small producer credit as applicable (26 U.S.C. § 40(b)(6)). As with the alcohol credits, the cellulosic biofuels producer credit expires on December 31, 2010 unless Congress chooses to extend it.

The structure of the biodiesel income tax credit basically parallels that of the ethanol credit (albeit with more generous amounts), as 26 U.S.C. § 40A also provides a “biodiesel fuels credit” that consists of a “biodiesel mixture credit,” a “biodiesel credit,” and a “small agri-biodiesel producer credit.” The biodiesel mixture credit provides a credit of $1.00 per gallon for each gallon of biodiesel used by the facility in producing a “qualified biodiesel mixture” (a mixture of biodiesel and diesel sold by the facility for use as a fuel). The biodiesel credit equals $1.00 per gallon of biodiesel (if the biodiesel is not mixed with petroleum-based diesel) that is sold by the facility “at retail to a person [using the alcohol as fuel] and placed in the fuel tank of such person’s vehicle.” In other words, the alcohol credit applies to facilities that both produce

fuel and sell it directly to customers at retail. Perhaps the most significant difference between the ethanol and biodiesel credits comes from the small agri-biodiesel producer credit. While, as with ethanol, this credit provides $0.10 per gallon of biodiesel sold to another party and is limited to the first 15 million gallons of production per year from a facility with a capacity of no more than 60 million gallons from the biodiesel facility, the difference comes from the “agri-biodiesel” term. “Agri-biodiesel” means “biodiesel derived solely from virgin oils, including esters derived from virgin vegetable oils from corn, soybeans, sunflower seeds, cottonseeds, canola, crambe, rapeseeds, safflowers, flaxseeds, rice bran, mustard seeds, and camelina, and from animal fats.”

As with the cellulosic biofuels producers credit, 26 U.S.C. § 40A also provides a “renewable diesel” credit for diesel fuel converted from biomass so long as the fuel meets certain requirements under the Clean Air Act and satisfies American Society of Testing and Materials (“ASTM”) standards D975 or D396. The renewable diesel credit is $1.00 per gallon (26 U.S.C. § 40A(f)).

Excise Tax Credits: Excise taxes are typically imposed on gasoline and diesel fuels either when the fuels leave the refinery or terminal, or upon their arrival to the United States if they are imported. These taxes are $0.183 per gallon for gasoline and $0.243 per gallon for diesel (26 U.S.C. §§ 4081, 4083). Biofuels are not immune from these taxes, as 26 U.S.C. § 4041 also imposes the gasoline and diesel tax rates on ethanol and biodiesel, respectively. These taxes can be offset with the credits created by 26 U.S.C. § 6426, which creates the “alcohol mixture credit” (sometimes called the “blenders credit,” “Volumetric Ethanol Excise Tax Credit” or “VEETC”), and the “biodiesel mixture credit.” These credits amount to $0.45 per gallon for ethanol (minimum 190 proof) blended with gasoline for use as fuel and $1.00 per gallon for biodiesel mixed with petroleum-based diesel.

The excise and income tax credits are linked via 26 U.S.C § 40(c) so that the income tax credit will be “reduced to take into account any benefit provided with respect to such alcohol solely by reason of the application of” the excise credit provisions (26 U.S.C. §§ 4041(b)(2), 6426, and 6427(e)). Claiming these credits requires registration with IRS, and in the case of biodiesel, may also require certificates confirming the nature of the biodiesel (26 U.S.C. §§ 2426).

The Federal Renewable Fuels Standard: The federal Energy Policy Act of 2005 (“EPAct”) and the Energy Independence and Security Act of 2007 (“EISA”) respectively established and modified the federal requirements for the use of renewable fuels in the nation’s transportation fuel supply. The current version of this Renewable Fuel Standard (“RFS”) derives from § 202 of the ESIA and mandates the use of the volumes of renewable fuels in the U.S. fuel supply shown in Table 1 (with amounts taken from the most recent version of 42 U.S.C. § 7575(o)(2)(B)).

Table 1. Required Volumes of Fuels under EISA Renewable Fuels Standard

YearRenewable Fuel

[billion gal.]

Advanced Biofuel

[billion gal.]

Cellulosic Biofuel

[billion gal.]

Biomass-based Diesel

[billion gal.]2009 11.1 0.6 -- 0.52010 12.95 0.95 0.1 0.652011 13.95 1.35 0.25 0.82012 15.2 2 0.5 12013 16.55 2.75 1 --2014 18.15 3.75 1.75 --2015 20.5 5.5 3 --2016 22.25 7.25 4.25 --2017 24 9 5.5 --2018 26 11 7 --2019 28 13 8.5 --2020 30 15 10.5 --2021 33 18 13.5 --2022 36 21 16 --

Understanding the RFS requires understanding the specific fuel types mentioned. 40 U.S.C. § 7545 provides the following definitions:

Renewable fuel means fuel that is produced from renewable biomass and that is used to replace or reduce the quantity of fossil fuel present in a transportation fuel.

Advanced biofuel means renewable fuel, other than ethanol derived from corn starch, that has lifecycle greenhouse gas emissions, as determined by the Administrator, after notice and opportunity for comment, that are at least 50 percent less than baseline lifecycle greenhouse gas emissions.

Cellulosic biofuel means renewable fuel derived from any cellulose, hemicellulose, or lignin that is derived from renewable biomass and that has lifecycle greenhouse gas emissions, as determined by the Administrator, that are at least 60 percent less than the baseline lifecycle greenhouse gas emissions.

Biomass-based diesel means renewable fuel that is a diesel fuel substitute produced from nonpetroleum renewable resources and that has lifecycle greenhouse gas emissions, as determined by the Administrator, after notice and opportunity for comment, that are at least 50 percent less than the baseline lifecycle greenhouse gas emissions.

Baseline lifecycle greenhouse gas emissions means the average lifecycle greenhouse gas emissions, as determined by the Administrator, after notice and opportunity for comment, for gasoline or diesel (whichever is being

replaced by the renewable fuel) sold or distributed as transportation fuel in 2005.

These definitions and the overall language of 42 U.S.C. § 7545(o) reveal three important considerations. First, the language of the standard reduces the overall applicable volume by the volume of “advanced biofuels,” with the implicit effect of capping the amount of corn-starch based ethanol that can be used to satisfy the RFS at 15 billion gallons. Second, a fuel derived from a given feedstock must do more than meet the RFS requirements; it must also satisfy the greenhouse gas reduction requirements relative to comparable petroleum-based fuels. The determination of these greenhouse gas thresholds is a topic of considerable scientific and political debate. EPA proposed its initial regulations for these determinations in late May, and a number of hearings and meetings have already been held debating their methodology (74 Fed. Reg. 24904, May 26, 2009). Third, while the ostensible purpose of the RFS is to provide something of a demand “floor” for biofuels to encourage their development, it also contains a provision allowing EPA to waive (after consultation with the U.S. Department of Energy and the U.S. Department of Agriculture) the RFS limits based on either a finding that potential economic or environmental harm would result from adhering to the standard, or a finding that there is insufficient domestic supply of the biofuels to satisfy the standard (42 U.S.C. § 7545(o)(7)). Thus, the RFS may not necessarily create the stable biofuels market policymakers and industry supporters intended.

Compliance with the RFS is tracked by the use of Renewable Identification Numbers (“RINs”). A renewable fuel facility that produces more than 10,000 gallons per year is required to register with EPA and to assign a RIN to each batch of fuel produced (40 C.F.R. § 80.1126). Refiners and importers of fuel are also required to register with EPA and participate in the RIN tracking program. These refiners and importers then demonstrate their compliance with the RFS by showing ownership of the number of RINs that correspond with the volume of fuel that the refiner or importer handled over the applicable compliance period (40 C.F.R. § 80.1127).

Environmental Permitting

A host of complex regulatory systems govern the operation of biofuels facilities. Perhaps more than any other area of law, these issues pose the greatest threat to derailing a project. This threat derives not from an onerous regulatory burden, but rather from the fact that a project developer must carefully coordinate the permitting processes to ensure that all necessary approvals are in place when the facility is ready to commence operations. Failing to do so can cause disastrous consequences if a regulatory agency requires the facility to shut down until approvals are in place or imposes significant monetary penalties. Both circumstances create crippling cash flow problems for a facility in its most economically vulnerable phase of operation.

The discussion of environmental issues that follows focuses primarily on federal laws that apply across all the United States. The reader is cautioned that many states have requirements in addition to these federal laws, and thus project developers should always consult state and local agencies with environmental jurisdiction.

Facility and Fuel Registration under the Federal Clean Air Act: Under Title II of the Federal Clean Air Act (CAA), a fuel-producing facility must determine if the facility itself must be registered with EPA and if the fuel it produces must be registered as well.

Most facilities producing ethanol or biodiesel that will either be used as highway motor fuel or may be blended with highway motor fuel will likely have to register the facility. Registration for both ethanol and biodiesel facilities is accomplished by contacting EPA’s Office of Transportation and Air Quality, with registration instructions available at http://www.epa.gov/oms/regs/fuels/fuelsregistration.htm.

While facility registration helps EPA maintain a listing of fuel producers, fuel registration addresses the environmental and health characteristics of the fuel products. 40 C.F.R. Part 79 requires “fuel manufacturers” to register with EPA and submit data regarding the emissions characteristics of their fuels (and the health impacts thereof). A “fuel manufacturer” is defined at 40 C.F.R. § 79.2(d) as “any person who, for sale or introduction into commerce, produces, manufactures, or imports a fuel or causes or directs the alteration of the chemical composition of a bulk fuel, or the mixture of chemical compounds in a bulk fuel…” Since most biofuels facilities produce ethanol or biodiesel for use either as a fuel or as a fuel additive, the vast majority of such facilities must then register their fuel products.

Determining the emissions and health characteristics of a fuel product can be a time-consuming and highly expensive process. Fortunately, EPA regulations allow trade groups and other associations to work collectively in compiling data for similar fuels (40 C.F.R. § 79.56). Some trade organizations, such as the National Biodiesel Board, have already compiled such data and provide their members with access to it for the purposes of registering their products. EPA’s Office of Transportation and Air Quality manages the fuel registration system, and more information regarding forms and procedures can be found at http://www.epa.gov/otaq/regs/fuels/fuelsregistration.htm.

Air Permitting: Under the federal Clean Air Act (“CAA,” 42 U.S.C. §§ 7401 et seq.), facilities that have potential emissions above the following threshold amounts require construction and/or operating permits (sometimes called “Title V” permits from the title of the CAA that contains the permit requirements):

(1) Emitting ten tons per year of any individual hazardous air pollutant (HAP) or 25 tons per year of any combination of HAPs (note, a “hazardous air pollutant” is a substance found on EPA’s list of particularly dangerous air pollutants; this list is found at 42 U.S.C. § 7412(b));

(2) Or emitting 25 tons per year of any combination of hazardous air pollutants; (3) Or emitting 100 tons of any “regulated” air pollutant (these pollutants include

volatile organic compounds, nitrogen oxides, certain classes of particulate matter, nitrogen oxides, sulfur dioxide, and lead).

(42 U.S.C. § 7661a(a), 7661(2)). Facilities exceeding these thresholds are called “major sources.” In determining whether a facility will exceed the thresholds above, EPA calculates the facility’s emissions as though the facility would operate at its maximum capacity for 24 hours a

day, 365 days per year (40 C.F.R. § 70.2) to determine a facility's "potential to emit.” In some circumstances, a facility can limit its operations by obtaining a “minor source” or “synthetic minor” permit that contains federally-enforceable limits to the hours of operation, volume of production, or other parameters that keep the facility’s emissions below these thresholds, thus eliminating the need for a “major source” permit. Consequently however, the facility must abide by the minor source permit’s restrictions. Typically, Title V sources must receive construction approval from the requisite permitting entity prior to construction of load bearing components of regulated pollutant emitting equipment.

Another air permitting system that can impact biofuels facilities is the “Prevention of Significant Deterioration” (“PSD”) program. Applicability of the PSD program is based on a facility’s emissions of “regulated new source review (“NSR”) pollutants, which include the criteria pollutants noted above as well as a number of other specific materials. Ethanol plants emitting more than 250 tons of NSR pollutants and biodiesel plants emitting more than 100 tons must conduct a PSD review of their operation and receive a construction permit before commencing construction of the facility. EPA defines “construction” to include preparing to build a facility’s foundation, which underscores the need to determine the applicability of the PSD applications to a potential facility as soon as possible in the design process.

Air permitting and review under the Title V and PSD programs can be a time-consuming and expensive process, frequently costing in excess of $100,000 and taking a year or more from the date of permit application to a final permit decision. Project developers should work closely with their engineering consultants and legal staff to determine potential facility emissions early in the design process so that necessary applications are started as promptly as possible. Also, project developers should evaluate whether operations can employ specific controls and/or permit conditions to keep emissions to below “minor” source levels, thus minimizing application and compliance costs.

Water Issues: Generally, the federal Clean Water Act (33 U.S.C. §§ 1251 et seq.) requires a permit for the discharge of any pollutant into a body of water from a discrete point (such as a pipe, conduit, ditch, or channel). Even if an operator believes that the water discharged from their facility will consist of little more than water with some biological matter, the discharge could still constitute pollution, since the federal Clean Water Act’s definition of “pollutant” encompasses an immense range of possible pollutants (33 U.S.C. § 1362(6)). To discharge its liquid wastes, a biofuels facility needs a National Pollutant Discharge Elimination System (NPDES) permit. NPDES permits are issued pursuant to 40 C.F.R. Part 122, which provides that such permits must take into account the nature of the pollutants emitted by the facility, the existing quality of the water receiving the discharge from the facility, the uses of the receiving water, and the technology that could be used to treat the discharge. Given that many biofuels facilities have the opportunity to use different strategies for handling the water they generate (such as irrigating nearby fields and using evaporation ponds,), facility developers should consult the permitting agency early in their planning process to determine if such alternatives may be approved. Generally, an applicant must submit their materials no later than 180 days prior to commencing a discharge, but in some circumstances the application must be submitted 90 days prior to construction of the discharge equipment (40 C.F.R. § 122.21(c)).

A biofuels facility may also need a permit for discharges of pollutants that occur from industrial storm water runoff (rainfall that runs off from the facility carrying potential pollutants with it). Depending on the configuration of the facility and the jurisdiction in which it operates, the discharge requirements may come in the form of the facility’s NPDES permit, a separate storm water permit, or a “general permit” applicable to a number of similar facilities (40 C.F.R. §122.26). If applicable to the facility, a general permit often provides coverage at a lower cost and with less needed “lead time” than other permits.

Yet another facet of the storm water issue comes from the NPDES “construction storm water” regulations, which requires permit coverage for potential runoff discharges from construction sites that will disturb more than one acre of land. (40 C.F.R. 122.26(b)(15)). As with industrial storm water permits, individual or general permits address these requirements, and in many jurisdictions, general permits cover the overwhelming majority of construction projects, making such permits much easier and much less expensive to obtain.

Waste: The processes used to derive fuel from agricultural materials generate a number of additional byproducts, some of which may fit the definition of “solid waste” under the Resource Conservation and Recovery Act (“RCRA,” 42 U.S.C. §§ 6901 et seq.). As with the definition of “pollutant” discussed above, the definition of “solid waste” encompasses almost every waste material generated by an industrial process. Such wastes must be disposed of at a RCRA-compliant landfill or by another RCRA-permitted method. Additionally, 40 C.F.R. § 261.3 defines some solid wastes as “hazardous wastes” by both listing specific substances always considered hazardous and by setting forth chemical characteristics deemed “hazardous.” Biofuels facilities likely will generate at least some quantities of these materials. While all hazardous wastes require special storage and disposal procedures, the facility itself may face additional registration and reporting requirements if it generates more than 1,000 kilograms of hazardous waste in a month (40 C.F.R. § 260.10, 40 C.F.R. Part 262).

Importantly, using byproducts or waste streams for some beneficial purpose such as co-products, fertilizer, (and in some cases, for energy recovery or burned to produce thermal energy) can exclude those materials from the definition of “solid waste.” Since this may significantly reduce the costs of waste management and/or provide additional cash flows, facility developers should carefully review their processes to determine how all the facility’s resources can be used or reused for maximum efficiency.

Tank Storage Issues: EPA regulates tank storage of chemicals through two main programs. First, EPA’s “Spill Prevention, Containment, and Countermeasure” (“SPCC”) program applies to above-ground storage tank facilities containing 1,320 gallons or more of “oil and oil products. (40 C.F.R. § 112(b)). For the purposes of the SPCC program, however, “oil and oil products” is defined as “oil of any kind or in any form, including, but not limited to: fats, oils, or greases of animal, fish, or marine mammal origin; vegetable oils, including oils from seeds, nuts, fruits, or kernels; and, other oils and greases, including petroleum...” (40 C.F.R. §§ 112.1(b), 112.2). Both ethanol and biofuels facilities may fall under this rule due to the storage of process materials; for ethanol facilities, a primary concern would be gasoline used as a denaturant, and for biodiesel facilities, the storage of the feedstock itself. Facilities subject to the SPCC regulations must prepare a spill prevention, containment, and countermeasure plan that may

include requirements to build “secondary containment” structures (such as curbs or berms) around tanks and contingency plans for responding to a spill of regulated materials. (40 C.F.R. §§ 112.3, 112.7).

The second tank storage program, the Underground Storage Tank (“UST”) program, regulates tank systems containing “regulated substances” constructed with ten percent or more of their volume underground (40 C.F.R. § 280.12). “Regulated substances” represents yet another broadly encompassing definition and includes substances regulated under a number of other regulatory programs including “hazardous substances” as defined at 42 U.S.C. § 9601(14) and petroleum products. Again, this definition includes many substances commonly stored at biofuels facilities. Owners of regulated tank systems must register with EPA or a delegated state agency, install and maintain leak detection and corrosion protection systems, and keep records of material inventories and maintenance operations (40 C.F.R. Part 280).

Community Right-To-Know Issues: Another potentially applicable regulatory system is the Emergency Planning and Community Right-to-know Act (EPCRA), also known as “SARA Title III.” EPCRA requires communication between a facility storing specified amounts of potentially dangerous substances and local emergency response agencies and establishes reporting requirements to help local emergency officials understand the inventories of such substances in their areas. One can find a list of substances that may trigger EPCRA applicability by consulting EPA’s “List of Lists,” available at http://www.epa.gov/ceppo/pubs/title3.pdf. Any prospective biofuels project should review its process design to determine if it will hold inventories of any EPCRA-covered substances.

Alcohol Regulations

Several regulations under the jurisdiction of the Bureau of Alcohol, Tobacco, Firearms, and Explosives (“ATF”) jurisdiction apply to the production of alcohol for fuel, even at relatively small facilities. 26 U.S.C. § 5181 contains a number of statutory requirements for fuel alcohol production facilities, which are then detailed in the regulations of 27 C.F.R. Part 19, Subpart Y.

26 U.S.C. § 5181 sets the broad framework for the ATF regulatory structure, requiring all “distilled spirits plants” that produce ethyl alcohol for fuel use to secure an ATF permit and post a bond. Permit applications are made on ATF Form TTB F 5110.74 (available at http://www.ttb.gov/industrial/forms.shtml). This application includes information about the owner, the facility, and facility operations (including the plant configuration and materials used). For approval of a construction permit, applicants must show that they will adhere to the requirements for construction of the facility and its security (27 C.F.R. § 19.965-19.966). Facilities must also use approved gauging devices for measuring and reporting fuel production (27 C.F.R. § 19.965-19.966). In addition to the permit application, each facility must post a bond to ATF to cover potential regulatory expenses or regulatory liabilities. 29 C.F.R. § 19.957 specifies a bond of $200,000 for any facility producing more than 1,240,000 “proof gallons” of alcohol. A proof gallon is “a gallon of liquid at 60 degrees Fahrenheit which contains 50 percent by volume of ethyl alcohol having a specific gravity of 0.7939 at 60 degrees Fahrenheit referred to water at 60 degrees Fahrenheit as unity, or the alcoholic equivalent thereof” (27 C.F.R. §

19.907). Thus, a facility producing 200-proof ethanol would cross the 1,240,000 proof gallon threshold with only 620,000 gallons of ethanol production. As a result, virtually all commercial-scale ethanol plants will be required to post the $200,000 bond amount.

Ethanol producers must also adhere to the ATF’s denaturant requirements. In order to qualify for treatment under the fuel alcohol exemption from alcohol excise taxes, produced ethanol must be rendered unfit for beverage use through mixing with a denaturant (26 U.S.C. §§ 5181(d), 5214(a)(12)). Denaturants must be mixed at a ratio of 2 gallons or more of denaturant to each 100 gallons of ethanol. 27 C.F.R. § 19.1005. Approved denaturants include gasoline, kerosene, deodorized kerosene, rubber hydrocarbon solvent, methyl isobutyl ketone, nitropropane isomers, heptane, or any combination of these denaturants. Id.

Lastly, while qualified fuel alcohol facilities are exempt from the alcohol excise tax, they remain subject to the “special occupational tax” imposed by 27 C.F.R. part 19, subpart Ca. This tax is basically a flat tax per distillation facility. If the gross receipts from sales of products from the facility are more than $500,000 per year, a tax of $1,000 is due (27 C.F.R. §§19.50, 19.907).

FEASIBILITY PROJECTIONS FOR AN EXAMPLE CELLULOSIC FACILITY

A wide range of studies have considered the feasibility of grain-based ethanol and biodiesel production, and a number of authors have also attempted to forecast the production costs of cellulosic ethanol. While explanations of the costs and returns of typical biofuel production processes are extremely useful, the results may not apply to a particular location or when price or cost factors have changed. A more limited number of studies provide a detailed economic engineering approach. Dale and Tyner provide a complete analysis of the ethanol dry milling process, discussing mass balances, electrical and thermal energy flow rates and volumetric sizing of tanks and equipment. Another contribution to the understanding of biofuel economics has been the development of feasibility templates and cost calculators. These decision tools, created by Oklahoma State University (Bowser et al. 2008, Holcomb and Kenkel 2008), Montana State University (McNew and Griffith 2003), University of Minnesota (Tiffany 2003), Iowa State University (Hofstrand 2006) and other sources, allow users to forecast the costs and returns of biofuel production processes under various cost, price and process assumptions.

Oklahoma State University recently created a Cellulosic Ethanol Feasibility template which is published by the Agricultural Marketing Resource Center. The OSU Cellulosic Ethanol Feasibility Template is designed to help producers, potential investors, rural community leaders, and other groups understand the factors that impact the feasibility of cellulosic ethanol project. In the example scenario, which used typical assumptions for plant cost, conversion rates, feedstock cost, and ethanol price, the project yielded a fairly unattractive return on investment. However the rate of return of a cellulosic ethanol project is very sensitive to changes in ethanol price, feedstock cost, and conversion rates. Feedstock transportation distance and plant costs are also important factors. The OSU Cellulosic Ethanol Feasibility template provides a convenient tool for decision makers to evaluate the factors important to their specific location or project. It is not designed to represent a specific conversion technology, but is instead designed to be customized by the user to reflect the conversion rates, feedstock costs, equipment costs and

operating inputs of a particular cellulosic ethanol project. The OSU Cellulosic Ethanol Feasibility Template can provide important insights into the factors that would make a cellulosic ethanol successful.

FeedstockFeedstock prices and transportation costs dramatically impact the feasibility of a

cellulosic ethanol product. If the example cellulosic plant described below could purchase feedstock at $40/ton rather than $45/ton, the internal rate of return would increase to 15%. Conversely the IRR would be .1% at $50/ton feedstock. Feedstock transportation distance also has an impact. A five-mile change in the average distance that feedstock is transported impacts the example plant’s IRR by roughly 2%.

Conversion RatesMuch of the current research and commercialization efforts for cellulosic ethanol

production systems are focused on maximizing conversion rates. The number of gallons of ethanol that can be produced per ton of feedstock has a direct impact on project feasibility. For the example plant, each 5 gallon/ton change in conversion rate impacts the IRR by slightly over 5%. If the conversion rate in the example plant fell to 70 gallon/ton the project would return a -4.8% IRR. At a conversion rate of 80 gallons/ton, the projected IRR is 11.8%.

Ethanol PriceThe price of ethanol is the most important factor influencing the profitability of a

cellulosic ethanol project. While ethanol prices are correlated with the price of unleaded gasoline they are impacted by a number of other supply and demand factors including transportation logistics. For the example plant, each $0.05/gallon change in ethanol price impacted the IRR by over 2%. At a ethanol price of $2.25 the project had an IRR of -10.5%, while an ethanol price of $2.75 increased the projected IRR to 21%.

Plant CostPlant, equipment and infrastructure costs for cellulosic ethanol projects are likely to be

significantly higher than equivalently sized grain-based ethanol projects because of the additional processes involved with pre-treatment and saccharification and the additional infrastructure needed to process feed stocks. Project costs have an obvious impact on economic feasibility. The example plant had a project cost of just under $2.50/gallon of capacity. A $.25 increase or decrease in the project cost per gallon of capacity impacted the IRR by approximately 3%. This is an important consideration since the construction cost for grain-based ethanol plants have been increasing rapidly due to escalating steel prices and other factors.

A Template ExampleFactors impacting the feasibility of a cellulosic ethanol project can be illustrated by

examining a typical scenario involving a commercial scale plant with a production capacity of 56M gallons. Construction costs are estimated at $139M or approximately $2.50 per gallon of capacity. Personnel requirements are estimated at 59 employees, including management and engineering staff, at a total personnel cost of $2.8M/year. The projections are based on an ethanol price of $2.50/gallon and the production of 2.42 KW of electricity per gallon of ethanol. Plant use of electricity is estimated at 1.3KW/gallon, which resultes in a surplus electricity co-

product of 1.12 KW/gal that is assumed to be available for sale into the commercial power grid at a value of $.056/KW. The baseline projections are based on 50% switchgrass and 50% corn stover inputs. The feedstock is assumed to have a farm value of $45/ton and an average hauling distance of 20-25 miles. Conversion rates of 76.24 gallons ton and 78 gallons/ton are assumed for switchgrass and corn stover respectively. At the baseline assumptions, the project has an internal rate of return of 8.8% and a payback period of over 10 years as shown in Table 2.

Table 2: Return on Investment / Sensitivity Analysis for an Example Cellulosic Ethanol Project

BaselineInternal Rate of Return 8.8%

Feedstock Price: [$/ton]35 40 45 50 55

Internal Rate of Return 21.3% 15.0% 8.1% 0.1% -11.4%Ethanol Price: [$/gallon]

2 2.25 2.5 2.75 3Internal Rate of Return < -20% -10.5% 8.1% 21.0% 32.2%

Feedstock Transportation Distance [miles]20 25 30 35 40

Internal Rate of Return 9.5% 7.9% 6.2% 4.5% 2.7%Conversion Rate [Gallons/ton]

70 75 80 85 90Internal Rate of Return -4.8% 5.0% 11.8% 17.3% 21.9%

Project Cost: [$/gallon of capacity]2.25 2.5 2.75 3 3.25

Internal Rate of Return 10.5% 7.9% 5.7% 3.8% 2.1%

CONCLUSIONS

As this discussion has indicated, determining the costs and returns and the overall viability of a biofuel venture is a complex question. Information on the technical conversions from the raw material to biofuel and co-products is but one aspect of the equation. Engineering information on process flows, material balances, energy requirement, and equipment design must be converted to cost estimates. Plant and equipment costs are also only one component of the total costs of developing a biofuel project. Regulatory, permitting, and capital acquisition costs must also be considered. This paper has attempted to provide a brief overview of these complex and inter-related issues. The feasibility example provided illustrates the importance of comprehensively analyzing a proposed biofuel project to understand risk factors.

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