By Chris Groobey

Ethanol is a significant and growing part of the energy infrastructure of the United States.  There are currently 73 ethanol production facilities in operation in the US.  These facilities produced 3.1 billion gallons of ethanol in 2003, a 32% increase over the production level in 2002.  Another 14 facilities are currently under construction and will add 500 million gallons a year to production capacity.  Many more plants, in more than 20 states, are under development.

Ethanol is an octane-enhancing additive to gasoline.  It increases the oxygen content of the fuel and reduces harmful emissions from internal combustion engines.  Ethanol is now blended into 30% of the gasoline sold in the US.

Demand for ethanol is expected to increase significantly through at least 2010.  Gasoline refiners currently add either ethanol or a petroleum by-product called MTBE to gasoline.  However, California, New York, Connecticut and other states have either banned MTBE or are moving to do so.  In addition, Congress has been debating a renewable fuels standard that would create a domestic market by law of at least five billion gallons of ethanol a year by 2012, a 60% increase over current production capacity.

Why Ethanol?

A series of federal, state and local incentives are key to making ethanol projects economic.

Chief among them is a federal ethanol tax incentive benefiting gasoline wholesale marketers that may be claimed in one of two ways.

The first method is a partial exemption from the federal gasoline excise tax.  The US government collects a tax of 18.4¢ a gallon on gasoline.  The tax is collected from the refiner or wholesale distributor that last handles the blended fuel in bulk form.  However, the tax is reduced by 5.2¢ a gallon on gasoline that contains at least 10% ethanol.  This gives the refiner or distributor an incentive to blend ethanol with his gasoline if the cost to him of doing so is less than 5.2¢ a gallon.

The second method is by claiming a credit against federal income taxes.  The credit can be claimed by the company that blends the ethanol with gasoline.  The credit is 52¢ per gallon of ethanol that is blended into the gasoline.  This is economically equivalent to the 5.2¢-a-gallon excise tax exemption for 10% blend gasoline.  However, the amount of the credit must be reported as income by the blender — which has the effect of clawing back part of the benefit — and a blender cannot use credits to reduce his regular tax liability by more than 25%.  It cannot be used at all against liability under the alternative minimum tax.  Blenders usually prefer the excise tax reduction rather than the tax credit because of these restrictions.

There is also a separate tax credit of 10¢ a gallon for small ethanol producers.  A company can qualify if it produces fewer than 30 million gallons of ethanol a year.  The credit is capped at $1.5 million per producer per year so it only applies to the first 15 million gallons of production.  It may not be claimed by an entity that has already taken advantage of the excise tax reduction.  In other words, if an ethanol producer also blends the ethanol with gasoline, he will have to chose the small producer credit or the excise tax exemption.  He cannot have both.  As with the blender credit, the small producer credit must be reported as income, and it cannot be used against liability under the alternative minimum tax.  Most new ethanol plants are designed to produce more than 40 million gallons a year and some plants are owned by farmer cooperatives that cannot take advantage of this credit.  Congress is considering legislation that would allow plants to produce 60 million gallons a year and still qualify as “small ethanol producers.” The legislation would also enable farmer cooperatives to benefit from the credit.

Finally, businesses may take a credit of 52¢ for each gallon of ethanol (not blended with gasoline or other fuel) that is sold at retail for use as vehicle fuel or that the producer uses directly as fuel in his own business.  Only specially-modified vehicles can use pure ethanol as fuel so this credit has a limited market.

The current exemption and credits expire in 2007, but a number of bills moving through Congress would extend them through 2010.

The federal government also supports ethanol projects through a federal grant program administered by the US Department of Agriculture.  The Commodity Credit Corporation — which is part of the Agriculture Department — provides up to $150 million a year in grants to encourage increased ethanol production.  To qualify for these payments, the ethanol producer must enter into an agreement with the CCC and report its production on a quarterly basis.  The CCC makes payments to producers who increase ethanol production over the previous year.  Proceeds are generally used to construct new ethanol facilities or to secure financing for new ethanol producers.  Payments are prorated at the end of the government’s fiscal year so that the aggregate amount of the grants (including separate bio-diesel grants) remains within the $150 million budgeted.  For fiscal year 2003, the CCC paid more than $130 million to 44 ethanol producers for an average payment of $2.95 million.  Congress has authorized the CCC program through 2006.

Other, smaller USDA grants are available to defray costs incurred during the early stages of developing an ethanol plant.  These grants are available through the rural development office in the US Department of Agriculture.

There are also various state and local incentives for ethanol projects.  Some of these incentives are aimed at a larger class of infrastructure projects than just ethanol.  They include tax-increment financing (which segregates property tax revenues for the benefit of a specific project), property tax abatements, assistance in obtaining suitable project sites and similar support.  Other incentives are targeted only to ethanol.  Examples of these include a production incentive of 1.9¢ a gallon for ethanol in Minnesota and a sales tax exemption for ethanol in Illinois.  These types of ethanol-specific incentives are most common in farm-belt states, but other states — most notably on the West Coast and in New England — are aggressively courting ethanol producers to support their own agricultural economies.

The Ethanol Opportunity

Ethanol processing facilities have historically been owned by farmer-owned cooperatives or agri-tech conglomerates like ADM and Cargill.  Farmer cooperatives build ethanol facilities to create a captive customer for their grain and to profit from the sale of the ethanol produced from the grain.  Conglomerates view ethanol as another outlet for the grain they buy from farmers.  Ethanol production is the third largest market for corn after domestic consumption and exports.

Traditional project financing opportunities for facilities owned by cooperatives or conglomerates have been rare as cooperatives generally borrow from rural development banks, through municipal bonds or from government agencies, and conglomerates generally develop ethanol facilities on their own balance sheets.

However, this might change.  Both the institutional equity market and private equity firms have started to take an interest.  Ethanol projects are now seen as generating the same attractive returns — generally 12% to 15% before taking into account mezzanine debt and sub-debt structures — as affordable housing, big-ticket lease transactions, wind projects and other alternative investments that rely on tax advantages for a part of their total return.

Institutional equity investors in ethanol plants prefer to leverage their investments and to do so within a non-recourse, project-finance structure.  Developers are also starting to show an interest in mezzanine debt structures that have not been widely used to date for ethanol.

Project Finance

At first glance, ethanol facilities appear to be strong candidates for project financing.  Among other attributes, the process for distilling ethanol is well understood, so there is no technology risk.  The facilities themselves are simple to construct and operate, so it is likely that they will be delivered on time and operate on budget.  Corn and other feedstocks are widely available and easily transported so “fuel risk” is minimal.  The end products — ethanol, carbon dioxide and distillers’ grains — are readily sold and have multiple current and future uses.  For example, carbon dioxide can be used to make dry ice or carbonated beverages, and distillers’ grains are valuable as livestock feed.  The facilities are generally welcomed by the surrounding community and subject to minimal environmental and other regulatory oversight or potential liabilities.

However, some attributes of ethanol facilities give project finance lenders pause and prompt changes from the traditional project finance model.  Of these, the most important factor is that long-term, fixed-price, single-counterparty contracts are generally not available for either the inputs into the facility (corn and other feedstocks) or the outputs (ethanol, carbon dioxide and distillers’ grains).  The lack of such contracts — and the liquidated damages provisions that are normally contained in them — introduce uncertainty into both the price and availability of the “fuel” and the price and customer base for the “products” of the facility.  Given the inability to tie down future costs and revenues, and given banks’ current aversion to “merchant” facilities of any sort, project-finance lenders have been relatively conservative in the pricing and terms offered to the developers of ethanol facilities.

Crossing the Open Water

The realities of the supply and offtake markets for ethanol facilities create challenges for developers and financiers of such facilities.  Developers try to maximize their returns on investment by borrowing as much as possible against the project.  Financiers are constrained by their relative unfamiliarity with such projects and their concerns about uncertain expenses and revenues.  Both sides tend to focus on the following characteristics of the debt financing when determining whether a deal can be struck:

Equity Requirements: Debt-equity ratios for contracted domestic power plants can reach 80-20 for the strongest projects.  Ethanol facilities are generally limited to no more than 60% senior debt and more likely 50% (all percentages being of the total cost to develop the project to commercial operations).  Less leverage means lower returns on equity for the developers but greater certainty of repayment for the lenders.  Developers can increase their returns by inserting a tranche of subordinated or mezzanine debt into the capital structure, but such debt comes at the cost of higher interest rates and increased bank and legal fees in order to reach financial close.  Equity capital can also be contributed by, among other parties, the contractor that is constructing the project, thereby decreasing the initial cash outlays from the developers.

Construction Contingencies: In the lenders’ eyes, developers consistently underestimate the cost of bringing a project to commercial operation.  Developers should plan to include a budget line item of at least 5% of the project’s capital cost for unspecified “contingencies,” in addition to including the maximum amount of all potential incentive payments to the contractor and other amounts that could increase the delivered cost of the project.  A lesser amount will draw the attention of the lenders’ independent engineer (the opinion of whom lenders almost never overrule) and force a reworking of the capital budget for the project.  Note that where the contractor is also an equity participant in the project, a lender might find it more acceptable to have lower-than-market holdback and punchlist reserves.  However, lenders will expect that construction or design-build contracts will adhere to arm’s-length standards (including fully-developed definitions of “completion” and other milestone definitions and well-defined performance standards) even when the contractor will benefit from the long-term operations of the project.

Coverage Ratios and Reserves: Developers should expect relatively stringent requirements relating to debt service reserve accounts and coverage ratios.  Debt service reserve accounts will typically have a required balance equal to the principal and interest payable on the senior loan for the next 12 months.  Debt service coverage ratios, which measure the relationship between project revenues and debt service both retrospectively and prospectively, will usually have a trigger level of 1.2:1 or higher for the suspension of dividends to equity and a level of 1.5:1 or higher for the resumption of dividends.

Collateral Issues: Lenders to ethanol facilities benefit from substantially the same collateral package as do lenders to power plants, including a mortgage on the project site, pledges of the equity in the project company, liens on all of the tangible and intangible assets of the project company, consents from the counterparties to the project’s major contracts and a series of “locked” waterfall accounts through which all of the project’s revenues must flow before being distributed to the developers.  Ethanol projects do have one unusual asset that is important to capture in the lender’s collateral package, namely the project company’s license to use the specific process utilized to produce ethanol.  This license is usually a companion document to the construction or design-build contract for the facility, but lenders should be certain to keep in mind that the license must be kept in effect for the full working life of the facility, in contrast to the construction contract that usually terminates relatively early in the life of the facility.

Working Capital Facilities: Working capital facilities, which generally take the form of an “evergreen” revolving loan, can be an important component of the overall financing package for an ethanol facility.  Such facilities are unusual in other project finance structures but developers of ethanol projects often wish to be able to take advantage of unexpected (and unbudgeted) opportunities to purchase feedstock at lower-than-normal prices.  A traditional project finance structure without a working capital facility would make this impossible as available cash is only distributed for budgeted expenditures or at the end of each quarterly or semi-annual payment period.  However, for ethanol plants, a small working capital facility can be drawn upon from time to time at minimal cost to the project company to purchase low-priced feedstock as it becomes available and, therefore, improve the economics of the project in a manner that is beneficial to both the developer and lender.

Hedges: It is unlikely that an ethanol facility will benefit from long-term, fixed-price, single-counterparty contracts for the supply of feedstock and the purchase of ethanol and other products.  This is the greatest source of concern to a lender.  Feedstock can be plentiful, but there may be significant competition for the same feedstock from other potential purchasers (including other ethanol plants) and replacement feedstock from other regions can be prohibitively expensive due to transportation costs.  Most lenders will require that developers retain the services of a commodities broker to source feedstock rather than rely on in-house personnel, and will also specify that forward contracts be entered into for at least a minimum percentage of the project’s total requirements for any given year.

With respect to offtake arrangements (meaning the sale of ethanol, carbon dioxide and distillers’ grains produced by the facility), lenders will generally include in their economic models only projected revenues from ethanol sales as it is rare to find a purchaser for the carbon dioxide produced by a facility.  Similarly, distillers’ grains — which are useful as livestock feed — are generally sold into the local spot market with unpredictable long-term economic results.  Ethanol can be sold into local, regional and national markets, and lenders will prefer that the project company retain the services of a marketer to ensure relatively constant prices and distribution to the various markets.  Lenders may also require that a minimum percentage of the ethanol output of the project be sold pursuant to relatively long-term forward contracts, even if such ethanol might be expected to command a higher price if sold purely on the spot market.  Marketers charge roughly 3¢ to 5¢ a gallon of ethanol sold and their commissions must be included in the financial model.  Finally, depending on the location of the ethanol project and its access to utility infrastructure, the lenders may require that the developers enter into long-term, agreed-price contracts for the electricity, natural gas and water required to run the facility if they are not available from municipalities or utilities at regulated rates.

State/Federal Incentives: Both lenders and developers will want access to the proceeds from grants and abatements associated with the project, especially as these generally become available early in the life of the project.  For example, a project might expect to receive a “bioenergy” grant from the Commodity Credit Corporation or a rebate of local property taxes paid in connection with the purchase of the project site.  Developers will want the payments for their own account so as to lock in a portion of the return they expect to receive on their investments.  In contrast, lenders will want the proceeds of such grants and abatements applied as mandatory prepayments of the outstanding loans.

Basic Market Due Diligence: Due diligence is key to understanding the expected market conditions for the plant.  For example, a for-profit facility owned by an institutional equity or private equity fund might be at a disadvantage to another plant owned by the local farmer cooperative.  A project might expect to ship a significant portion of its ethanol to the new, seemingly insatiable markets of California, New York and Connecticut, only to have those needs met by future projects located in those states.  Since the projects are dependent on government incentives, due diligence should also be done on the likelihood that such incentives might be withdrawn from the project.  For example, the federal excise tax exemption is subject to periodic renewal.  Project financings are an exercise in risk allocation.  It is important to have a complete catalog of all the risks.