Exhibit 99

	H A R V A R D | B U S I N E S S | S C H O O L
	N9-903-403 SEPTEMBER 19, 2002

RAY A. GOLDBERG
LAURE MOUGEOT STROOCK

Environmental Power Corporation: Changing Manure Into Gold?

     Joe Cresci and Donald “Andy” Livingston, the two founders of Environmental Power Corporation (EPC), a small company developing renewable energy projects with $53.5 million revenues in 2001, were wrapping up the presentation of their “manure-to-money” digester system, a facility that extracted methane from animal waste through anaerobic digestion and used it to generate electricity. The dozen dairy farmers from Wisconsin who seemed so quiet when Cresci and Livingston had begun, now assailed them with questions about the technology and the financial feasibility of their Product.

     In the spring of 2002, the mood of farmers involved in large Concentrated Animal Feeding Operations (CAFOs) was one of caution. Under a new regulation from U.S. Department of Agriculture (USDA) and the Environmental Protection Agency (EPA) coming into force at the end of 2002, all CAFO operators would have to develop and implement technically sound, economically feasible, and site specific nutrient management plans for properly managing the manure produced at their facilities. To comply with these new dispositions, they might have to reduce their herd size, buy new land for additional manure spreading, or invest in a digester. Digesters reduced odor and converted organic compounds into methane and plant nutrients. Either way, this meant additional costs that would hurt many farmers who were already heavily leveraged.

     Several features in Cresci and Livingston’s demonstration had caught their attention. First, unlike other digesters, the EPC digester not only helped manage farm wastes, but also produced large amounts of utility grade electricity that could be delivered at peak hours. Hence, in addition to recouping capital costs, farmers could make profits from multiple revenue streams including electricity sales at a premium rate, pollution offset credits, heat, refrigeration, and residual co-products such as compost or fertilizers. Second, EPC had packaged its product to remove most of the burdens associated with financing and operating the facilities. Finally, as a pollution prevention tool as well as a renewable energy producer, the project was likely to benefit from support programs of the EPA, the USDA, and the Department of Energy (DOE).

     Yet, Cresci and Livingston still had several obstacles to overcome to achieve their aggressive target of 226 facilities operating by 2006. EPC’s facilities used a Danish technology with a spotless track record, from both an engineering and an economic standpoint. But the Danish digesters were significantly smaller in size and benefited from advantageous national support programs. Could EPC replicate the Danish model at a larger scale under less favorable political and economic conditions?

Professor Ray A. Goldberg and Research Associate Laure Mougeot Stroock prepared this case. HBS cases are developed solely as the basis for class discussion. Cases are not intended to serve as endorsements, sources of primary data, or illustrations of effective or ineffective management.

Copyright © 2002 President and Fellows of Harvard College. To order copies or request permission to reproduce materials, call 1-800-545-7685, write Harvard Business School Publishing, Boston, MA 02163, or go to http://www.hbsp.harvard.edu. No part of this publication may be reproduced, stored in a retrieval system, used in a spreadsheet, or transmitted in any form or by any means—electronic, mechanical, photocopying, recording, or otherwise—without the permission of Harvard Business School.

     EPC digesters were significantly more expensive than simple waste-control digester systems primarily because they required more capital-intensive power generation equipment. The significantly increased biogas production required larger generators, and also justified the construction of storage facilities in order to provide power at peak periods. Adequate financing was therefore crucial to the success of the project. In a context of low electricity rates, a sluggish economy, and growing distrust in the electricity trading business after the Enron scandal, lenders were reluctant to grant loans without the guarantee of a firm long-term power contract with utilities at high enough rates to secure decent returns. Meanwhile, local utilities, concerned with the volatility of the electricity market and their own future in the ongoing deregulation, resisted long-term commitments. How would lengthy power contract negotiations with the utilities affect EPC’s deployment objectives?

     Finally, although farmers’ initial response to EPC’s product had been positive, some challenges remained. Could EPC’s product be made visible fast enough to undercut competing digesters? Would farmers be willing to become power producers and take on the risks associated with the electricity business? If demand took off as expected, did EPC have the capacity to manage a multiple location growth? And, how would a small company with limited cash flow finance such ambitious growth plans?

Company

     Headquartered in Portsmouth, New Hampshire, EPC was an independent developer of electric generating facilities powered by non-commodity fuels and renewable energy sources. The company was established in 1982 by Cresci, the chairman and CEO, and Livingston, the president and COO. Cresci and Livingston had met while creating tax-enhanced investments for an investment banker. “We felt we could do a better job by going out on our own,” explained Livingston. EPC’s first renewable energy project came in 1983, redeveloping and financing a small hydropower facility in Maine. EPC successfully completed several more hydropower projects and began taking on larger waste-to-energy projects. As of 2001, the company had developed seven hydroelectric plants, two municipal waste-to-energy projects, and three waste-coal-fired generating facilities. The company pioneered the use of tax-exempt project financing for independent power projects including the first non-recourse, non-credit enhanced, tax-exempt project debt.(1) The company had also sold emissions allowances from its facilities and received several prizes for environmental excellence. The company went public in 1986, and was quoted on the Over-The-Counter Bulletin Board market (POWR.OB symbol).

     Historically, EPC sold its projects during development or at completion, before operations began. However, the company had retained a 22-year leasehold operating interest in Scrubgrass, a 83 megawatt(2) (MW) waste-coal-fired power plant in Pennsylvania in operation since 1994.(3) From 1994 to 2000, EPC’s activity drastically decreased, as their niche became crowded with big energy developers. “It was almost impossible for a small independent developer to do any business, unless as subcontractors for small pieces of energy projects,” Livingston recalled. To preserve shareholder value, Cresci and Livingston shrank the company to four employees (see EPC’s stock fluctuations in Exhibit 1). With revenues of $54.3 million in 2000, “Buzzard”, the subsidiary that held EPC’s lease in Scrubgrass, was the company’s sole source of revenue. Buzzard contributed 100% of EPC’s cash flows that year, but required only management of Scrubgrass’ contracts, budget supervision, and oversight of financial strategies. Buzzard was expected to continue generating cash to EPC until 2016, but the flow might decline after 2005.(4)

(1) EPC, working with Goldman Sachs, was the first independent power developer to sell non-recourse, non-credit enhanced, tax-exempt project debt directly into the bond market.

(2) 1 megawatt =1,000,000 watts

(3) PG&E National Energy Group, Dana Corporation, and GE Capital were the lessor/owners of Scrubgrass. The plant was developed by EPC in a joint venture with PG&E Enterprises and Bechtel Enterprises and built by Bechtel Construction. The facility was operated and managed by PG&E National Energy Group under a long-term contract.

(4) The power contract signed with Scrubgrass was structured so that in 2005 cash flows would be adjusted based on inflation rates. EPC’s cash flow might decline with the expected downward adjustment.

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     In 2000, market conditions suddenly became more favorable to EPC, as skyrocketing electricity prices in California boosted the demand for new power development nationwide. “For the first time in years, our phone began to ring with people interested in power development projects, so Joe [Cresci] and I decided it was time to come out of our retirement and get back in the game,” Livingston remembered. Cresci and Livingston began to look for an acquisition in a power generation niche with potential for aggressive growth. “Rather than simply building another project, we wanted to build a business and shareholder value; so we looked for a type of project that could be built quickly, affordably and, most importantly, could be easily replicated with increased efficiency,” Cresci explained. EPC was approached to develop some gas cogeneration, waste coal, and solar power projects, but none appealed to Cresci and Livingston.

     In early 2001, the CFO of Microgy Cogeneration Systems, Inc, a privately-held development-stage company based in Colorado, contacted Livingston about possibly working together to finance a biogas production project. Microgy held the exclusive North American license for a Danish technology allowing efficient extraction of methane from animal wastes through anaerobic digestion. “At first, I was skeptical. I could not see EPC being involved in the manure business,” Cresci recalled with a smile. “But after a closer look, we realized that this opportunity had real potential.” Cresci and Livingston subsequently went to Denmark to visit the facilities and hired an engineering consultancy to study the technology. In July 2001, Microgy became a subsidiary of EPC. By the end of 2001, EPC had a staff of seven executives, three administrators, and two engineers. In pursuing the Microgy opportunity, the company would rely on specialists in agricultural markets, technology, finance, renewable energy, as well as legal and investor relations advisors.

     EPC could also call upon its strong board of directors. Cresci and Livingston, the only two management directors, had brought together six independent members comprised of two former presidents of large lending institutions, a former CEO of a large utility company, a former utility commissioner of California, a former Undersecretary of the USDA, and the Chairman of the largest dairy cooperative in the United States. These men would not only add their expertise and contacts to the Company but also comfort investors in a market concerned with corporate governance (Exhibit 2).

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Anaerobic Digestion

     In the absence of oxygen, anaerobic bacteria broke down organic material into a gaseous mixture called biogas, which, while not of commercial quality, had the potential for use in cooking, heating, and power generation. Biogas was approximately 60% to 70% methane and the remaining 30% to 40% consisted of carbon dioxide and trace levels of other gases such as hydrogen, carbon monoxide, nitrogen, oxygen, and hydrogen sulfide.(5) The relative percentage of these gases in biogas depended on the feed material and management of the process. Anaerobic decomposition was a complex process. A variety of factors affected the rate of digestion and biogas production. The most important was temperature. Anaerobic bacteria communities could endure temperatures ranging from below freezing to above 135° Fahrenheit (F), but they thrived best at temperatures of about 98°F (mesophilic range(6)) and 130° F (thermophilic range(7)), depending on the particular strain of bacteria. To optimize the digestion process, the digester had to be kept at a consistent temperature, as rapid changes upset bacterial activity. Other factors such as pH, water/solids ratio, carbon/nitrogen ratio, mixing of the digesting material, the particle size of the material being digested, and retention time affected the rate and amount of biogas output.(8)

Digesters

     Anaerobic processes could be managed in a “digester” (an airtight tank) or a covered lagoon (a pond used to store manure) for waste treatment. Anaerobic digestion (AD) had traditionally been used for nutrient recycling, waste treatment, and odor control. In very large anaerobic digester systems however, biogas production could be sufficient for use as a fuel to heat and electricity. Biogas had about two-thirds of the fuel value of natural gas, as measured in BTU content.(9)

     Anaerobic digesters were made out of concrete, steel, brick, or plastic. They were shaped like silos, troughs, basins or ponds, and could be placed on or under ground. All designs incorporated the following basic components: a pre-mixing area or tank, a digester vessel, a system for capturing or disposing of the biogas, and a system for distributing or spreading the effluent (the remaining digested material).

     In the United States, the availability of inexpensive fossil fuels had limited the development and use of anaerobic digesters.(10) The 1970s oil shocks led to the creation of several government programs designed to encourage the use of manure AD for on-farm energy production and utilization. However, a variety of factors, including high costs, poor design, operational complexity and premature failure of construction materials and equipment slowed the field’s development. Only 20 of the 70 commercially operated digesters built in the 1970s were in operation in 2001.(11) In the 1990s, recognition of the environmental benefits of manure AD, concerns over rising energy prices, and the development of a number of federal and state programs encouraging the adoption of this technology drew the attention of the farm and agricultural finance communities anew. The number of engineering firms, contractors, and equipment suppliers engaged in promoting this technology increased.

(5) “Biogas and More!” Report from IEA Bioenergy, July 2001. (http://www.ieabioenergy.com/IEABioenergy.php), accessed May 31, 2002.

(6) In the mesophilic range, decomposition was slower than in the thermophilic range, and digesters were larger to accommodate longer decomposition periods within the tank. The process, however, was less sensitive to changes in the operating regimen.

(7) In the thermophilic range, decomposition and biogas production occurred more rapidly than in the mesophilic range, but the process was highly sensitive to disturbances such as changes in feed materials or temperature. The higher temperatures of thermophilic digestion resulted in more complete destruction of weed seeds and disease-producing (pathogenic) organisms.

(8) “Methane (Biogas) from Anaerobic Digesters,” Energy Efficiency and Renewable Energy Network (USDOE), EREC Reference Briefs. (http://www.eren.nrel.gov/consumerinfo/refbriefs/ab5.html), accessed on June 6, 2002.

(9) When burned, a cubic foot of biogas yielded about 10 BTU of heat energy per percentage of methane composition. For example, biogas composed of 65% methane yielded 650 BTU per cubic foot. By comparison, natural gas yielded 1,030 BTU per cubic foot.

(10) The nation’s first farm-based digester, the McCabe farm-digester in Mount Pleasant Iowa, was developed at the end of the 1960s to control odor of the farm’s hog operation. “Farm-Based Anaerobic Digestion Practices in the U.S.,” from the BiogasWork Web site. (http://www.biogasworks.com/Index/AD%20Farm-based%20AD%20Practices.htm), accessed on May 30, 2002.

(11) Jerome Goldstein and Kurt F Roos, “Commercial infrastructure takes shape for anaerobic digestion,” BioCycle, November 1, 2001, P.25.

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EPC’s Approach

     EPC’s approach was to use proven Danish AD technology to turn the costs of manure pollution management into an economic benefit by producing renewable electricity production and reducing odor, methane emissions, and ground water contaminants generated by manure.

Technology

     EPC intended to design, build, sell, and operate facilities based upon Microgy’s anaerobic digester licensed technology. The licensor of Microgy’s anaerobic digester technology was Danish Biogas Technology A/S, or DBT.(12) Denmark had the most experience with large-scale farm digestion facilities. DBT designed, built, operated, and marketed a unique type of biogas plant that used animal manure together with small amounts of other organic waste to produce 1.5 to 4.0 times more biogas than other AD systems.(13) Biogas was used in a Combined Heat and Power (CHP) generator to produce “green” electricity and heat or refrigeration (Exhibit 3). The resulting electricity was introduced as utility-grade electricity to the distribution grid through a discrete interconnection system that in most instances required no upgrades to the utility system receiving it.

     DBT had more than 15 years of experience with anaerobic digestion and was Denmark’s leading digester manufacturer. In 2001, the company operated 28 of the country’s 50 to 55 digesters (Exhibit 4). Facilities had been built at a rate of approximately six new facilities per year in Denmark, as well as in Sweden, Germany, and Spain. Most of DBT customers were sophisticated farmers who carefully controlled the biological quality of the input manure to achieve the highest biogas yield.(14)

     Microgy’s license included the design, manufacture, and implementation of all components of the DBT anaerobic digestion and power production system. EPC adopted DBT’s operational strategy which freed farmers from the responsibility of monitoring and controlling the process, including biogas production, storage, and electric generation. This strategy addressed a common failure mode for digesters in the US due to a lack of understanding and operations capabilities on the farm. The digester/storage tanks and the CHP were conventional equipment available through domestic and international manufacturers. The license was perpetual and exclusive in North America, and non-exclusive for all but the European Union countries.

(12) DBT was 50% owned by Schouw & Co., a Danish multi-national public company.

(13) Two times more biogas on average than similar European digester systems, and up to four times more than other anaerobic digestion technologies. Dansk Biogas A/S Web site (http://www.dkbiogas.com), accessed June 14, 2002.

(14) From Professor Ray Goldberg’s interview with Mr. George Aboagye-Mathiesen, founder of DBT, on September 9, 2002.

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Environmental Benefits

     Unlike plug-flow digester technologies which tended to be mesophilic, Microgy’s thermophilic process (135°F) effectively destroyed pathogens and weed seeds from manure. It also mineralized nutrients (nitrogen, phosphorus, and potassium) in the manure slurry, a form more appropriate for field crops.(15) Further environmental benefits could be achieved by subjecting digested manure slurry to other processing techniques. The slurry could be de-watered to produce useful by-products such as animal bedding, garden mulch, organic fertilizer, and solid bio-fuel. In critical watershed areas, additional processing techniques could remove nutrients that would otherwise contribute to water pollution. Although the equipment for such applications was expensive, in some regions, environmental values and markets for by-products could justify the investment.

Economics

     The key competitive advantage of EPC’s technology was its ability to generate greater amounts of biogas than other AD systems in the same time frame. Unlike other digesters and renewable energy sources, Microgy’s digesters could economically store as well as produce the biogas, thereby allowing farmers to sell peak utility-grade power.(16) On-peak electricity sold for a significantly higher rate than off-peak electricity. In Wisconsin, for example, on-peak electricity sold for $0.05 per kilowatt-hour (kWh) while off-peak sold for $0.018/kWh. Electricity from renewable sources such as biogas could also receive a premium of up to $0.015/kWh.

     Management’s hypothetical pro forma analyses suggested that, although a Microgy digester cost farmers approximately $200,000 more in equity than a mixed plug-flow digester,(17) it was likely to yield approximately 2.5 times more revenue. This was largely due to the fact that it could generate 2.2 times more electricity per year than its competition (Exhibit 5). With the low operating, maintenance, and fuel costs of these digesters, EPC could compete with any form of energy producer while providing air and water pollution mitigation benefits. However, the capital requirements dictated the need for creative financing to keep debt service payments low.

(15) In the AD process, many of the minerals that were previously bound in organic molecules were reduced to the inorganic forms that were usable by crops. In undigested manure, the breaking down of the organic nutrients took several years. Residual minerals that were left over in the soil from previous years’ manure applications entered in the manure application rate calculations, resulting in less manure being spread on the same amount of cropland. By providing the minerals in readily usable forms, plant uptake was greater and digested manure had lower potential to produce a residual. Therefore, over time, more manure could be spread on an acre of cropland.

(16) Peak periods were customarily defined as the sixteen-hour period encompassing the daytime hours, Monday through Friday. Utilities highly favored peak period generating capacity and were willing to pay a premium for this capacity.

(17) EPC’s digester was more expensive largely due to the need for a larger generator that could produce peak-period power.

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The Animal Waste-to-Energy Market Opportunity

     The animal waste-to-energy opportunity addressed two convergent markets: the burgeoning market for waste management in the agricultural sector and the growing market for renewable energy.

Agricultural Waste Management Market

     The products of decomposing livestock manure included pathogens, nutrients (phosphorus, nitrogen, and potassium), methane, and ammonia. Untreated, these wastes could create surface and groundwater contamination (excess nutrients, disease-causing micro-organisms, and oxygen-demanding organics(18)) and surface air pollution caused by odors, methane, and ammonia.(19) Methane was one of the primary greenhouse gases linked to global climate change and was estimated to have an impact 20 times greater than carbon dioxide on global climate change. Methane emissions from agricultural activities represented 32% of total U.S. methane emissions (Exhibit 6). Livestock management accounted for 90% of such emissions, mostly attributable to enteric fermentation in ruminant animals (65%) and the anaerobic decomposition of livestock waste (33%).

     Beginning in the 1980s, U.S. livestock operations consolidated around the major production areas (Exhibit 7). As livestock production became more spatially concentrated, the amount of manure nutrients relative to the assimilative capacity of available farmland increased (Exhibits 8 and 9). A USDA study showed that average amount of excess nutrients per farm(20) more than doubled between 1982 and 1987 for both phosphorus and nitrogen.(21) Overall, it was estimated that the total cropland and permanent pasture controlled by operators of confined animal operations could only assimilate 40% of the nitrogen and 30% of the phosphorus being produced.(22) Most excess nutrient production came from large operations and CAFOs. Medium and large farms contributed 70% of excess manure nitrogen and 76% of excess manure phosphorus.(23) Contributions from CAFOs for excess manure nitrogen and phosphorus were 64% and 67% respectively. Land on which CAFOs operated had capacity to assimilate only 21% of the nitrogen and 12% of the phosphorus produced.(24)

(18) Nitrogen was easily soluble and transported in runoff. Phosphorus was only moderately soluble, and not as mobile as nitrogen, but erosion transported phosphorus-loaded sediments to surface and underground water, especially in areas where manure was applied on lands that had exceeded their soil phosphorus retention levels. Both nutrients accelerated algae production in water, clogging pipelines and killing fish. From “Confined Animal Production and Manure Nutrients,” Noel Gollehon and al., Resource Economics Division, Economic Research Service, USDA, Agriculture Information Bulletin No. 771. P.3. June 2001. (http://www.ers.usda.gov/publications/aib771/aib771.pdf), accessed June 30, 2002.

(19) Ammonia volatilization contributed to elevated nitrogen in precipitation, which led to excess nitrogen in water bodies and the acidification of soils.

(20) Farm-level excess manure nutrients measured the imbalance between assimilative capacity and the quantity of manure nutrients produces on the farm.

(21) “Manure Nutrients Relative to the Capacity of Cropland and Pastureland to Assimilate Nutrients: Spatial and Temporal Trends for the United States,” USDA, Natural Resource Conservation Service, December 2000. (http://www.nrcs.usda.gov/technical/land/pubs/manntr.html) accessed July 1, 2002.

(22) “Confined Animal Production and Manure Nutrients,” Noel Gollehon and al., Resource Economics Division, Economic Research Service, USDA, Agriculture Information Bulletin No. 771, June 2001. P.16. (http://www.ers.usda.gov/publications/aib771/aib771.pdf), accessed June 30, 2002.

(23) Medium farms were operations with 300 to 1,000 Animal Units. Large farms were operations with over 1,000 Animal Units. The definition of an Animal Unit depended upon the type of animal. For dairy cattle, 700 milking and dry cows were considered approximately equal to 1,000 Animal Units.

(24) “Confined Animal Production and Manure Nutrients,” Noel Gollehon and al., Resource Economics Division, Economic Research Service, USDA, Agriculture Information Bulletin No. 771, June 2001. P.16. (http://www.ers.usda.gov/publications/aib771/aib771.pdf), accessed June 30, 2002.

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     In 1999, the USDA and EPA announced a Unified National Strategy for Animal Feeding Operations, aiming at minimizing the impact of animal feeding on water quality and public health and at establishing a national performance expectation for animal feeding operations. Under the Unified National Strategy, Comprehensive Nutrient Management Plans (CNMPs), which until then had been voluntary, became compulsory for all CAFOs. CNMPs required farmers to show that they properly managed the animal wastes produced at their facilities, including on farm application and off farm uses. In limiting manure application from CAFOs, CNMPs were likely to raise on-farm cost of manure management from confined animal producers.(25) Such plans would be mandatory for operations that required a National Pollutant Discharge Elimination System (NPDES(26)) permit and voluntary for other producers. Hence, for the first time, the application of manure on land would require a federal permit. These new CAFO provisions were expected to enter into force by the end of 2002.

     With increased pressure for environmental compliance, manure management systems were likely to get farmers’ full attention. While AD did not eliminate the phosphorus, potassium, and nitrogen from manure, it allowed for more manure spreading on farmland as fertilizer. In many states, AD was formally approved as an acceptable nutrient management practice. This enabled a farmer to apply for some state funds available for implementing the designated agricultural practices.

Renewable Energy Market

     In 1999, renewable energy accounted for 7.4% of the total U.S. energy consumption (Exhibit 10). Power from renewable sources was growing at approximately 40% annually.(27) Hydropower and biomass(28) were the main sources of renewable energy, accounting respectively for 48% and 45% of U.S. renewable energy consumption (Exhibit 10). With 7,800 MW of biomass electric capacity installed at more than 350 locations, the United States accounted for half of the world’s installed capacity and derived 3.3% of its energy and 1.5% of its electricity from biomass. Milling and forestry were the main sources of biomass for power plants and combined-heat-and-power projects. Animal waste digestion projects were not yet commercially viable and energy crop plantations were still at an early stage of commercialization.

(25) CNMPs limited manure application on land to the level determined by the more limiting of the two major minerals: nitrogen or phosphorus (depending on factors such as the region, the climate, the rainfalls, and the crops). In the past, manure management focused on nitrogen. Because of the fast built-up rate and slow depletion rate of phosphorus in the soil, shifting to a phosphorus-based standard required more land on which to spread the same amount of manure. From “Confined Animal Production and Manure Nutrients,” Noel Gollehon and al., Resource Economics Division, Economic Research Service, USDA, Agriculture Information Bulletin No. 771, June 2001. P.5. (http://www.ers.usda.gov/publications/aib771/aib771.pdf), accessed June 30, 2002.

(26) NPDES permits were required for all industrial facilities by point source before they could discharge in navigable waters. In 1974, EPA had extended the definition of point source to include some confined CAFOs meeting certain criteria. From “Confined Animal Production and Manure Nutrients,” Noel Gollehon and al., Resource Economics Division, Economic Research Service, USDA, Agriculture Information Bulletin No. 771, June 2001. P.3. (http://www.ers.usda.gov/publications/aib771/aib771.pdf), accessed June 30, 2002.

(27) “Market Trends- Electricity,” in Renewable Energy Annual Issues 1998: Issues and Trends, Energy Information Administration.

(28) Biomass designated plant matter (residues from forest, pulp and paper operation, or crops), animal waste (cattle, chicken and pig waste), and landfill gas from which energy could be provided in the form of electricity, heat, steam, and fuels.

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     Renewables provided many energy, economic, and environmental benefits that did not always readily translate to tangible dollar valuations. More than one-third of U.S. consumers had an option to purchase some type of green power and as competition spread in the electric power industry, their number was expected to grow.(29) Surveys showed that over 70% of consumers favored renewable energy and were willing to pay a premium for it, typically $0.015/kWh.

     Renewable energy incentive programs In 2002, utilities in 29 states offered green bioenergy to their customers. A number of states, including Arizona, Nevada, New York, Texas, and Wisconsin, mandated that their state-owned facilities purchase a significant portion of green power for their own use and/or offer a green power option to consumers. In Wisconsin, for example, regulated utilities were required to have 2.2% of their power loads supplied by renewable resources by 2012. Similarly, Arizona required that 2% of its electrical sales be generated from renewable energy resources by 2010. Since 2001, New York state agencies had to buy 10% of their energy needs from renewable sources, with escalation to 20% by 2010.

     Many states also developed incentive programs for renewable energy producers in the form of electric price supports, grants, or tax credits. California, for example, collected funds from charges paid by the customers of regulated electric utilities to invest in various renewable energy programs such as the New Renewable Energy Account, which paid renewable energy generators between $.0075 and $0.015 for each kWh produced. To foster biogas investments on dairy farms, California also provided “buy down grants” covering a percentage of the capital costs of biogas systems or incentive payments for generated electricity.(30) Connecticut, Illinois, Maryland, and Massachusetts had similar renewable energy funds. A number of states, such as Maryland and Utah, also granted tax credits of 10% to 15% on renewable energy projects.

     The Federal government also supported renewable energy generation, mandating that 2.5% of its own consumption come from “green” energy by 2005, with escalation to 7.5% by 2010. In 1994, the EPA created the AgSTAR Program with the DOE and the USDA to provide information, tools, and training to help farmers make informed decisions about farm methane recovery.(31) In addition, George W. Bush’s proposed Energy Policy Act of 2002 included tax incentives to renewable energy producers equivalent to approximately $0.015/kWh in federal tax credits.

     Green tags and pollution offset credits The “green” component of renewable energy in itself had a value that could be isolated and sold separately as “green tags” on trading markets or in private transactions.(32) While selling electricity on the electricity market, the producer of renewable energy received green tags in relation to the volume of electricity produced. He then had two choices: either he sold its electricity as green, and received a premium for it,(33) or he stripped off the green attribute, marketed the power as “brown” electricity, and sold the green tags later to a third party on a green tag market. The market for green tags was young but growing, and EPC managers believed that it would become a profitable business.

(29) “Renewable Electricity Purchases: History and Recent Developments,” in Renewable Energy Annual 1998 Issues and Trends, Energy Information Administration.

(30) In 2001, the California Energy Commission (CEC) was providing $9,640,000 for its Dairy Power Production Program for manure to methane developments. Funds were used to assist dairies in design and construction of digestion systems, purchase of equipment for biogas electricity systems, and to provide technical assistance to dairies with biogas systems. The CEC target was to install by summer 2002 a total of over five megawatts of dairy biogas systems capable of generating over 30 million KWh per year of electricity. Several California projects were in the pilot development stage with the Inland Empire Utilities Agency (IEUA) which served over 700,000 people in San Bernardino County. Source: “Commercial infrastructure takes shape for anaerobic digestion,” Jerome Goldstein; Kurt F Roos, BioCycle, November 1, 2001. P.25.

(31) In the 1996-2001 period, the AgSTAR program had contributed to the construction of about 15 on-farm digesters and 50 more were expected to be built in the following 5 years.

(32) The value was derived from the fact that the energy was produced in an environmentally friendly way.

(33) Typically $0.0075 to $0.015/kWh, sometimes more with stringent renewable energy programs. In Massachusetts, for example, utilities that did not fulfill the renewable energy requirement, had to pay a penalty of $0.05/kWh. In addition, the green power had to be sold in the New England region, thus restricting the amount of green electricity originating from other regions. In this market, green electricity producers could hope to receive a premium up to $0.03/kWh.

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     Green tags could also be disaggregated into “tradeable allowances” of their various components, such as sulfur dioxide (SO₂), nitrous oxides (NOx), CO_2, or methane, and sold separately. The United States already had a domestic SOx and NOx emissions allowance market. The government had issued benchmarks for acceptable levels of SOx and NOx emissions and then issued marketable allowances to be sold or accumulated by below benchmark producers. Non-compliant producers purchased these offsets in trading markets or private transactions.

     As potent contributors to global warming, US-sourced methane and CO₂ would likely become subjects of tradeable allowances, since the Kyoto Protocol of 1997 provided for the creation of an international market for greenhouse gases offset credits, expressed in “carbon dioxide equivalents.” Although the U.S. Administration had not ratified the Accord, some believed that US-based offset generators would eventually participate in this market. The EPA was also developing an excess nutrient offset trading program similar to the one used for air emissions, based on groundwater pollution from excess minerals.

     Overall, the market for air and water based pollution credits was projected to grow as stricter environmental regulations and pollution standards were adopted. EPC’s top management believed that their biogas installations should be able to sell carbon dioxide equivalent credits, nitrogen, and phosphorus credits, nutrient management credits or other pollution offset credits.

Business Model

     EPC management concluded that, while renewable markets were favorable, the need for agricultural waste management would be the key driver of its expansion. By creating a “Product” that included turnkey design, construction, financing, consortium organization, structuring, power off-take and co-product sales, operation, maintenance, and management services, it could build and grow a business that addressed the perceived market needs. Of these Product “elements,” EPC managers knew that securing power off-take contracts with utilities, reaching the farmers interested and able to invest in its Product, and providing a financing structure to help them pay for it, would be the most critical and difficult tasks.

Target Market

     EPC planned to sell its Product to large dairy and swine farmers in the United States, specifically CAFOs, with over 1,000 head of milk cows and 25,000 head of hogs and pigs. In 2001, the United States had approximately 1,500 such sites (Exhibits 11 and 12). Based on this target market of 1,500 operations and an average Product sales price of $4.2 million, EPC saw an estimated potential target market of approximately $6.7 billion in the United States alone. In the medium term, with additional economies of scale or additional revenue from higher power rates or federal tax credits, EPC hoped to serve smaller farms such as the 500 head milk cow farm or the 10,000 hog and pigs head operations, an estimated additional target market of approximately $7.5 billion.(34) Further, these installations would provide EPC with significant recurring revenues from operations and management services.

(34) Assuming a Product sales price of $3.2 million and 2,350 operations.

10

Farm Consortium Model

     Initially, EPC managers planned to lease a piece of land on a farm, install a digester, collect the manure, and produce electricity from the resulting biogas. Under this scenario, EPC would own the facility and pay the farmer a rent. However, EPC’s agricultural consultants, discouraged them from this model, arguing that farmers would probably be reluctant to lose control over a part of their own property. “Farmers need to be more involved in the business, and not just ensure the quality of manure waste stream; they need to own some equity and participate in the benefits of the project,” explained the consultants to the project.

     EPC therefore developed a new business model in which the farmers would own the facility. EPC would provide the engineering, procurement, construction, and the operation and maintenance of the facility and arrange for the sales of electricity, green tags, pollution offset credits, and co-products. EPC would also be responsible for financing the project (Exhibit 13). A high percentage of non-recourse financing was crucial, as the estimated capital costs of Microgy’s technology ranged from $2.8 million to $5.3 million per facility, a hefty investment for a single farmer.(35)

     EPC’s top management therefore decided that they would bring together groups of neighboring farms into farm consortia, in the form of cooperatives or limited liability companies. A typical consortium project would be a $20 to $30 million capital investment representing six to eight facilities of variable sizes with a combined power capacity of 10 to 15 MW. Each farmer would be an equity investor in the consortium which would own all the facilities. The consortium would lease the land for the digesters from the farmers. The farm consortium model presented several advantages. First, it would promote cost efficiency in design, manufacture, and construction of the facilities. Second, it would allow attractive power sale offerings to utilities and trading markets. And above all, it created cost effective access to large agricultural lenders and bond markets.

Financing Structure

     EPC’s Product was intended to include pre-established financing programs, which offered access to specialized agricultural industry lenders and tax-exempt bond markets. Each farmer in the consortium would provide 10% to 20% of the equity while the remainder would come from non-recourse public tax-exempt debt. Hence, if the facility failed, the farmer’s liability, as an energy producer, would be limited to the equity he had initially supplied (refer back to Exhibit 5). This financing method was another key advantage of Microgy’s digesters over its competitors. A farmer investing in any AD technology without a reliable revenue stream would have to take out recourse loans and would be liable to the amount of the whole debt if the facility went bust.

(35) Initial studies estimated the sales price as ranging from approximately $3.5 million for a 1.5 MW peaking capacity digester to $5.3 million for a 3 MW peaking capacity digester.

11

     EPC also considered a structure whereby it would sell its systems to municipalities, state agencies, and/or rural electric cooperatives. These organizations had access to other capital sources that would be able to provide the financing on behalf of their constituents, the farmers. The municipalities would own the equipment and lease it to the operators, but ownership, or at least many of its benefits would revert back to the farmers or cooperatives after the debt had been repaid.

Power Off-take Contracts

     For each consortium, EPC needed to negotiate a power contract with a utility for 10 MW or more of electric power capacity. At the time of the case, EPC had won a first power sales agreement with Wisconsin Public Service Corporation (WPS) for up to 15 MW of firm peak period power. The company had a conditional letter of intent with six large dairy farms in Wisconsin that were able to provide the resources to generate most of WPS’s 15 MW. The company was also seeking to negotiate additional power contracts in California, Wisconsin, Illinois, New York, Vermont, Maryland, and Florida.

     Overall, EPC hoped to have five facilities in operation by the end of 2003, 40 by the end of 2004, 114 by the end of 2005, and a total of 226 by the end of 2006 (equivalent to 25 to 35 consortia and approximately 450 MW of power off-take contracts). Facilities would most likely be concentrated in four or five regions. EPC’s management expected that the first five facilities would take about a year to build, and that subsequent facilities would only take nine months, as volume and standardization drove down the time and the cost of permitting, component manufacture, construction services, and transaction overheads. “Our goal is to have a standard financing package and a standard “cookie-cutter design, so that it is one-stop shopping for the farmer,” concluded Cresci.

Revenues

     At the anticipated biogas levels, EPC could offer a packaged Product at a significant profit to the company while also providing an attractive return to farmers.

     EPC    In the short term, nearly all of Microgy revenues would come from the sale and installation of the facilities. Sale of operating and management services would provide the remainder. However, EPC’s top management hoped that revenues from Microgy would enable EPC to achieve a target aggressive growth approximating 125% compound annual growth rate by 2006. Once the debt was paid, EPC would share in the power revenues with the farmers. The size of the share would be negotiated with each consortium. With adequate maintenance, Microgy’s digesters were expected to last at least 30 years and to provide significant cash flow with the debt repaid and continued low operating expenses.

     Farmers     Revenues for the farmers would come from the sale of electricity to the grid, as well as the sale of green tags, and pollution offset credits. Farmers could also avoid the costs of buying electricity and heat for
on-farm use. If the farmer had invested in de-watering equipment, sales of residual co-products (bedding, compost, fertilizers, and solid bio-fuels) would also enhance revenues. In the initial years, all of the energy income from the power contracts would go to pay off the debt and the equity investors, including the farmers.

12

Competition

     EPC took a broad view of competition and identified two main classes of competitors: opportunity competitors and power producers.

Opportunity Competitors

     Farmers had several ways to handle their pollution problems, ranging from acquiring more land for additional manure spreading, to reducing herd sizes, to employing other digester technologies such as plug-flow digesters. The other anaerobic digestion providers, such as Enviro-Energy Corporation and RCM Digesters essentially commercialized custom-designed plug-flow digesters with pollution control functions similar to Microgy’s digesters but lower methane and electricity production capacity. Electricity generation and heat from such facilities were generally used to run the farm. In some cases, small quantities were sold to the grid to provide some revenues. However, according to the engineering experts hired by Cresci and Livingston to study the market, none of these competitive systems could produce sufficient energy revenues to recoup their costs. Yet, they remained EPC’s competitors because farmers who might purchase them would not be available to purchase EPC’s Product. “These competitors may limit our potential target market, not because they are superior technologically, but because they exist and may be better known to farmers,” noted Cresci.

Power Producers

     EPC faced competition from commodity power producers selling electricity on the price competitive electricity market. Many of EPC’s competitors were well established, more experienced, and better capitalized. However, EPC’s facilities had some unique features. First, Microgy’s digesters had no fuel cost. Increased demand and increased costs of fuel were the two main factors driving up the cost of electricity. Because EPC did not share fuel cost risks, its electricity would be more attractive to utilities. Second, Microgy’s digesters could generate utility-grade power during peak demand periods. Only natural gas-fired generation was a serious competitor on this peaking electricity segment of the power market. Finally, EPC’s facilities would be located in remote rural areas that utilities valued because such facilities assisted with load balancing of the transmission and distribution system, allowing reduction in line loss and increased reliability for end-users.(36)

     EPC facilities also competed with renewable energy producers in the sale of renewable energy and green tags, and for participation in green pricing programs and state incentives for renewable energy. EPC’s top management had mixed feelings about the impact of renewable subsidies on their project. On the one hand, inflated electricity prices, grants, and tax credits increased the profitability of their Product. On the other hand, it enabled renewable energy producers who could not survive without subsidies to compete with EPC for power contracts. “Our projects do not always need the renewable energy subsidies to be profitable,” explained Cresci. “Subsidies actually hurt us from a competitive standpoint, even though economically they improve our profitability.”

(36) The flow of electricity through transmission lines could result in line losses as significant as 5% or more. Quality of service was consequently diminished for electric consumers who were at the end of a utility distribution network, meaning that when demand exceeded supply, electricity cuts often occurred in the areas at the edge of the network, though excess power might have existed in neighboring areas. Utilities understood that to balance their load, they needed to have some generating capacity at the outer reaches of their distribution network.

13

Challenges

Replicating the Danish Model in the United States

     The economic performance of the Microgy’s digester as well as those in Denmark depended on the cost of electricity. However, Danish biogas producers benefited from more generous subsidy programs than their American counterparts. The Danish government sponsored a special electricity subsidy and indirect support in the form of tax exemptions for the consumption of heat generated from biomass. Electricity rates in Denmark were higher than in the United States. Until the Danish renewable energy reform of 2000, the price paid for green electricity was about DKK 0.6/kWh ($0.069/kWh). Since then, the price was allowed to oscillate between DKK0.43/kWh and DKK0.60 ($0.054-$0.069/kWh).(37) In addition, Danish biogas producers were paid for some of the other waste they used to feed their digesters.(38)

     These subsidies and high electricity rates allowed Danish farmers to operate DBT digesters profitably on a smaller scale than was currently possible on an economic basis in the United States. EPC still had to prove the technical, financial, and environmental performance of its Product at a larger scale and under less favorable economic subsidy conditions.

Securing Adequate Electric Prices

     Except for sudden regional on-peak price hikes, electricity prices across the United States had remained generally flat or declining due to a slower economy and lower cost of conventional fuels. Hypothetical calculations by EPC’s agricultural consultants showed that, with a blended electricity rate at $0.056/kWh(39), a Microgy digester could provide an IRR of about 23%. If the electricity rate dropped to $0.045/kWh, i.e. a 20% drop, the IRR would fall to 5% (refer back to Exhibit 5). Stagnant or decreasing electricity prices in EPC’s target farming regions could adversely affect the profitability of its project.

     EPC had several ways to cope with lower electricity prices. One way was to negotiate a longer power contract, allowing for a longer debt repayment period. “If we can finance the debt for 30 years, instead of 15, we reduce the yearly principal amount due, and then we do not need as much revenues on the power side,” explained Ed Chapman, EPC’s senior VP of Finance. Another way was to reduce the capital cost by taking advantage of the economies of scale in the size of the Microgy’s digesters and the farms they were on. Because they had bigger generator sets, Microgy’s digesters installed on large farms could produce more on-peak electricity and allow these farms to withstand lower power rates. Larger farms also had lower break-even points, as they could recoup the cost of equipment faster than smaller ones. Another solution was to adopt one Danish model in which several medium-size farms trucked their manure to the facilities. If farms were too distant from one another though, transportation could create its own costs in spill liabilities and in biosecurity.(40)

(37) The tariff for selling electricity was fixed at DKK0.33/kWh, to which was added a Green Certificate (equivalent to the U.S. green tag). A framework was established for the certificates’ price fluctuation. The certificates had a minimum price of DKK 0.10 per kWh. If utilities did not fulfill their quotas of green power in their offering, they had to pay a tax of DKK 0.27 per kWh, which constituted an indirect price ceiling.

(38) As a way to increase gas production, DBT biogas plants added 2–5% waste fish oil or other fats found locally, or imported from Hamburg and Rotterdam. From “Biogas, a Coming Success,” Preben Maegaard, Director, Folkecenter for Renewable Energy (Denmark). Proceeding of the Pan-European Sustainable Energy NGO Seminar in Denmark, September 2001. (http://www.orgve.dk/inforse-europe/sem01p.htm), accessed June 14, 2002.

(39) The blended electricity rate was an estimation of the average electricity rate blending off-peak, on-peak, and green electricity rates.

(40) Pathogens from one farm had the potential to be transferred to other farms by the trucks visiting several farms every day.

14

     Hence, in the absence of sufficient electricity rates, EPC might have to narrow its target markets to the largest CAFOs or to geographically concentrated medium-size farms. “The single biggest challenge of EPC is to negotiate power contracts within our target regions at rates and length of time allowing to pay off all the debt and equity of the farms based on their scale,” concluded Chapman.

Arranging Project Financing

     Product financing depended on the terms EPC negotiated in the power contracts with the utilities. The higher the electricity rate negotiated in the power contract, the higher the return on investment, and the easier it would be to obtain advantageous loans and get farmers on board.

     Securing long-term power contracts    To protect themselves against power rate fluctuations after the 2000-2001 electric industry turmoil, bankers demanded a firm power contract before they agreed to grant loans. Utilities, however, were reluctant to make long-term commitments while the industry was still deregulating. Moreover, the mild winter of 2001 and the sluggish economy created surplus power capacity which had driven down the forward market for power. Utilities were not eager to buy additional power. The Enron scandal of 2002 had also damaged trust in the whole electric trading business. “It is no longer a generic power market where you can sell electricity without a contract and have the lenders recognize that there is value. Instead the market now has to be custom-fitted to power projects,” Cresci explained.

     To avoid the costly and time-consuming process of negotiating each power contract with local utilities, EPC had several options. It could try to obtain a firm long-term contract with a national energy firm. It could attempt to convince lenders that with no fuel risks, low operating costs, proven technology, and power generation sold at valuable on-peak electricity rates, the project had low risks and did not need a power contract. It could also price long-term contracts attractively for utilities and hope that market improvements and incentives, such as the production tax credit, fell into place.

     Financing farmer’s equity Some farmers might not be able to bring the equity that each Microgy’s digester required. EPC needed to have flexible financing arrangements to accommodate them. One solution was to bring outside equity investors into the consortium. Alternately, the renewable energy production tax credits from the Energy Policy Act of 2002, if adopted, would provide significant revenues that could help in this financing.

     Another solution was to apply for government grants. EPC’s agricultural consultants had identified several possible sources of federal funding for which EPC’s Product qualified. However, many of these specific regulations were new and it might take one or more years before the government actually implemented them. EPC needed to structure a financing scheme to address its market and could not afford to wait such a long time. “We do not know if and when these specific grants will apply to our projects, but it is worth filing these applications early, making them as general as possible, and wait until these agencies enact these regulations,” explained Chapman.

15

Convincing Farmers Before Competitors

     EPC had to change farmers’ opinion of the performance of anaerobic digesters. Anaerobic digesters were perceived as costly and inefficient. Even though EPC’s Product was thought to be superior to any other digester on the market, convincing farmers would take time and efforts, especially for specialists in energy project development with little exposure to farming. Approaching farmers was all the more difficult in that many of them denied that they even had a pollution problem. Hence it was unclear if EPC should position its Product as “pollution control equipment at no cost” or as “an energy/power business”.

     EPC had little time to lose. The new CAFO rules would came into force at the end of 2002. In the meantime, farmers unaware of EPC and its alternative solution to their manure problem might adopt cheaper competing digesters. EPC needed to have the technology, the economics, and the financing of its Wisconsin project in place and running as a tangible proof of its concept. “We need to make ourselves visible in the market fast enough so that farmers do not put on other pollution control. It will be much easier when we have installations running in various regions to create a jungle drum,” underlined Cresci.

Managing Growth

     Although the construction, supervision, and operations of the Microgy digesters demanded neither extensive management nor significant amounts of manpower, EPC’s aggressive expansion would require a significant coordination effort across geographically scattered facilities. Given the low reputation of digesters and the looming competition, EPC had no room for failure in managing operation and maintenance. Although the company would subcontract some of the operation and maintenance, it still planned to hire about 170 additional staff by 2006, assuming EPC’s target growth was accomplished. “The challenge here is to stop being a project developer and start being a successful growth business, so Joe and I may consider replacing ourselves in a not too distant future with corporate management experienced in the issues raised by multiple location growth,” Livingston explained.

Funding Company Expansion

     EPC had a small float on the Over-The-Counter Bulletin Board (OTCBB) and was subject to the machinations of a few market makers who increased the bid-ask spread to make up for the low trading volumes. EPC management was concerned that these conditions would limit the public interest in the firm and its ability to fund the growth of the company. However, the OTCBB was being phased out in favor of a new exchange, the BBX, which promised to eliminate the use of market makers and allow a more transparent market. Cresci and Livingston wondered whether the new market would help them overcome these obstacles or whether they should seek other ways to tap into the capital markets.

     EPC was already consuming all of its cash flow in the ramp-up of Microgy. Therefore, management concluded that, despite a share price that was believed to be undervalued, some additional capital was desirable immediately. Management had engaged a public and investor relations consultant to help raise public awareness, and, hopefully, the market price of its shares. However, Cresci and Livingston were aware that this would be a slow process, and that the plummeting stock market in the first half of 2002 was discouraging to potential investors (refer back to Exhibit 1).

16

     Management needed to maximize its options and recognized that it could not be certain which funding strategy might ultimately work. One thing was clear, if a modest amount of capital could be raised immediately, precious time could be added to the financing equation. More time added more financing possibilities and a chance to see EPC’s share price improve. Chapman suggested that they should raise as little as possible and try to make a private placement among potential accredited investors already known to the Company, including officers, directors and others with existing relationships or who had been especially supportive of the Company.

     Management was able to enhance this strategy by securing an option on a large block of EPC shares from a former Microgy employee.(41) As the option price was well below current market, it permitted the Company, if it desired, to sell many fewer new shares to generate the needed capital.

     The funding from the private placement gave management time to seek additional capital from institutional or strategic investors while working to document the value of EPC through some further successes with the Microgy Product. The company could now consider delaying for some months any effort to raise additional corporate capital, and perhaps, even gamble that exceptionally favorable terms could be achieved in project financing. This could even further extend the time before capital was an absolute necessity. It was at this crossroad that the company stood in September 2002.

(41) He recognized that any attempt to sell a large block of stock in the market could collapse the stock price and hurt the Company, which in turn, would lessen the value of his remaining holdings.

17

Exhibit 1  EPC’s Stock Price Fluctuations (01/1997 to 07/2002)

Source: Datastream International.

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Exhibit 2  Current Directors of Environmental Power Corporation

Peter J. Blampied was President of Corcoran Management Company, Inc., a real estate company managing

8,700 residential apartment units in New England and the southeast U.S. Formerly, he was Chairman, President and CEO of Boston Five Bancorp which was acquired by Citizens Financial Group in 1993. He had been involved with numerous national and local business and real estate organizations in various capacities. He also served as a trustee of Northeast Investors Trust and as a director of Access Capital Strategies and A.W. Perry, Inc. He was a director of the Nellie Mae Foundation and an overseer of Beth Israel Deaconess
Medical Center.

Robert I. Weisberg was the President and Chief Executive Officer of Alco Financial Services, LLC and the

former President and Chief Executive Officer of Pro-Care Financial Group, Inc. He formerly held the position as President and CEO of Fleet Credit Corporation and as Executive Vice-President of Fleet Financial Group. A graduate of Northeastern University, he received the Executive Award from a joint program sponsored by Williams College and the Harvard Graduate School of Business. Past Chairman and President of the Commercial Finance Association, he was a member of the Commercial Finance Association’s Education Foundation. Mr. Weisberg was a trustee of the Monterey Mutual Fund and had served on numerous public, corporate and non-profit community boards. He was a Governing Member of the Reed Union School Board and Chair of Fundraising.

Thomas M. Matthews had thirty years of senior executive experience and expertise in all aspects of the energy

industry. He was the former Chairman and CEO of Avista Corporation, a diversified Fortune 500 company that specialized in independent power, energy trading and marketing, and information and technology. Prior to his tenure at Avista, Matthews served as President of Dynegy, Inc. whose subsidiaries market and trade electricity, natural gas, coal and other energy products in North America, The United Kingdom and continental Europe. He also held positions as Vice President of Texaco, Inc, President of Texaco’s Global Gas and Power Division and spent eight years with Tenneco as President of Tennessee Gas Pipeline Company and Executive Vice President of Tenneco Gas. Mr. Matthews had served on the boards of a number of organizations, including the Washington CEO Roundtable, the Advisory Council for Texas A&M University, Nature Conservancy of Idaho, Hospice at Texas Medical Center, and Texas A&M Vision 2020 Committee.

Jessie J. Knight, Jr. was President and CEO of the San Diego Regional Chamber of Commerce and is

Executive Vice President of Navillus Associates, LLC, a real estate development partnership located in San Francisco. From 1993 through 1998, Mr. Knight served as Commissioner of the California Public Utilities Commission as Managing Commissioner over the electric and telecommunication industries of the State. Mr. Knight was the Vice President of Marketing for the San Francisco Chronicle and San Francisco Examiner newspapers for sever years. He spent ten years in senior management positions in finance and marketing for the Dole Foods Company and as Director of Marketing for its US and Canadian businesses and its Latin American operations. Mr. Knight served on the boards of Blue Shield of California, DBS Industries, Inc. and Avista Corporation. He was former Vice Chairman of the World Affairs Council of California and was a standing member of the Council on Foreign Relations.

Herman Brubaker, the Chairman of the Board, was also chairman of the board for Dairy Farmers of America

(DFA) and served as chairman of the executive committee. He served as national chairman of the board for the United Dairy Industry Association (UDIA) and chairman of Dairy Management, Inc. (DMI). Herman previously served on the executive committee for the National Milk Producers Federation (NMPF) and as a vice president and member of the NMPF board; and chairman of ADADC Mideast. He had also served on many cooperative organizations, which included board president of Milk Marketing Inc. (A DFA predecessor) and a member of the boards of directors for Central Valley Milk, Inc.; Great Lakes-Southern Milk, Inc.; and the Hoosier Milk Marketing Agency. He was also past director of the Ohio Dairy Farmers Federation.

August Schumacher, Jr. had served as the third-highest ranking official in the United States Department of

Agriculture in the Farm and Foreign Agricultural Service from 1997-2001 and President of the Commodity Credit Corporation. He also directed the Department’s Foreign Agricultural Service. Mr. Schumacher was the Senior Agricultural Project Manager for World Bank and was Commissioner of Food and Agriculture for the Commonwealth of Massachusetts. In 2002, he was a consultant for W.K.K. Kellogg Foundation and the Managing Director of SJH and Co.’s Washington D.C. operations.

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Exhibit 3  Microgy’s Digester Facility System

Source: Adapted from EPC’s Business Plan 2001 and “EPC-DBT in U.S. dairy and Hog CAFOs,” Presentation from SJH&Company, May 2002.

20

Exhibit 4  Example of Danish Biogas Technology Generating Plants

		Biomass (m3/y)		Manure		Digester Volume (m3)		Biogas Production (m3/y)		Electricity Production (MWh/y)		Farm Electricity Consumption (MWh/y)		Heat Production (MWh/y)		Construction Year
Tinggard		10,000		18,000 slaughter pigs/y		600		722,000		1,645		208		1,944		12/2000
Hegndal		16,425		900 sowers (21,000 piglets/y and 15,000 slaughter pigs)		800		1,000,000		2,600		430		3,120		06/2000
Oestenfjeld		9,125		650 sowers (14,000 pigs/y)		600		750,000		1,650		279		2,310		06/2000
				160 milking cows
Bording		6,570		180 young stock		600		536,100		1,533		157		1,839		06/2000
Uhrenholtgaard		12,000		650 sowers (21,000 piglets/y and 15,000pig/y)		600		831,420		2,377		324		2,853		07/2000
Hvims		18,250		Mink manure and waste from feed and local industries		800		1,277,500		2,938		2,604		3,120		12/2000
Brunshoejgaard		14,600		1,000 sowers (24,000 piglets/y)		600		750,000		1,400		543		1,960		03/1998
Dalsgaard		4,380		6,500 slaughter pigs		400		350,000		1,000		150		1,200		12/1999

Source: Adapted from Dansk Biogas A/S Web site (http://www.dkbiogas.com), accessed June 14, 2002.

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Exhibit 5  Hypothetical Comparison of Microgy’s Digester and a Typical Plug-flow Style Digester

			Microgy’s Digester			Mixed Plug-flow Digester
Farm size Period Discount rate				2,500 head dairy farm 15 years 8
Total Capital Cost			$4,592,000			$1,847,500
Equity			$918,400			$739,000
Debt			$3,678,600 (nonrecourse loans)(a)			$1,108,500 (recourse loans) (b)
Producer’s liability			$918,400			$1,847,500
Negotiation of the Power Contract			EPC			Producer
Power output (kWh) per year			13,730,862 (c)			6,307,200 (d)
Blended fates(e)			$0.056/kWh			0.048/kWh
Gross Annual Energy Revenues			$750,000 (+3% per year)			$300,000 (+3% per year)
Operating costs			$220,000 (+2% per year)			$90,400 (+2% per year)
IRR			23%			2.5%
Sensitivity of IRR to Power Rates
Power rates (per kWh)	$0.056		$0.055	$0.050		$0.045
IRR	23%		21%	13%		5%

Source: Adapted from “EPC-DBT in U.S. dairy and Hog CAFOs,” Presentation from SJH&Company, May 2002.

(a) Assumes 80% financing at 6% blended rate, based on EPC’s experience with debt financing.

(b) Assumes access to 60% financing at 7% blended rate, typical of historic farm access to debt capital.

(c) Assumes 2,350 kWh, 16 hours per day on-peak 5 days a week and 16 hours off-peak 2 days a week.

(d) Assumes 800 kWh, 24 hours per day on-peak, 7 days a week.

(e) Wisconsin Power Service published tariff rates for conventional electricity: $0.018/kWh off-peak, $0.05/kWh on-peak. A premium of $0.015/kWh for "green” electricity was also considered a strong possibility.

Note: The hypothetical comparison in this chart is based on various assumptions, including those referenced in the footnotes. Actual figures and results may vary significantly from hypothetical figures and results.

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Exhibit 6  Principal Source of U.S. Anthropogenic Methane Emissions, 1990-2000 (million metric tons of methane)

	2000		%
Energy	11.0		39.0
Waste Management	8.0		28.4
Agriculture
Enteric fermentation of livestock	5.5		19.5
Anaerobic decomposition of livestock wastes	3.0		10.6
Of which:
Cattle	1.4
Swine	1.4
Poultry	0.2
Others(a)	0.6
Total Agriculture	9.1		32.2
Industrial Processes	0.1		0.4
Total Methane Emissions	28.2		100.0

Source: “Emissions of Greenhouse Gases in the United States 2000,” Energy Information Administration. (http://www.eia.doe.gov), accessed May 31, 2002.

(a) Crop residue burning and wetland rice cultivation.

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Exhibit 7  Location of Confined Animals, 1997

Source: “Confined Animal Production and Manure Nutrients,” Noel Gollehon and al., Resource Economics Division, Economic Research Service, USDA, Agriculture Information Bulletin No. 771, p. 15, June 2001. (http://www.ers.usda.gov /publications/aib771/aib771.pdf), accessed June 30, 2002.

Note: Some counties are combined to meet disclosure criteria.

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Exhibit 8  Excess On-farm Manure Nitrogen as a Share of Recoverable Nitrogen, 1997

Source: “Confined Animal Production and Manure Nutrients,” Noel Gollehon and al., Resource Economics Division, Economic Research Service, USDA, Agriculture Information Bulletin No. 771, pp. 25-26, June 2001. (http://www.ers.usda.gov/publications/aib771/aib771.pdf), accessed June 30, 2002.

Note: Some counties are combined to meet disclosure criteria.

25

Exhibit 9  Excess On-farm Manure Phosphorus As a Share of Recoverable Phosphorus, 1997

Source: “Confined Animal Production and Manure Nutrients,” Noel Gollehon and al., Resource Economics Division, Economic Research Service, USDA, Agriculture Information Bulletin No. 771, pp. 25-26, June 2001. (http://www.ers.usda.gov /publications/aib771/aib771.pdf), accessed June 30, 2002.

Note: Some counties are combined to meet disclosure criteria.

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Exhibit 10  U.S. Energy Consumption by Energy Sources, 1999 (quadrillion BTU)

	1999		%
Fossil Fuels	81.56		84.57
Nuclear Electric Power	7.73		8.02
Renewable Energy
Hydropower	3.45		3.58
Geothermal energy	0.37		0.39
Biomass	3.21		3.33
Of which:
Wood energy	2.56		2.65
Waste energy	0.54		0.56
Alcohol fuels (ethanol)	0.11		0.12
Solar energy	0.07		0.08
Wind energy	0.05		0.05
Total Renewable Energy	7.15		7.41
Total Energy Consumption	96.44		100.00

Source: “Renewable Energy, Annual 2000,” Energy Information Administration. (http://tonto.eia.doe.gov/FTPROOT/ renewables/060300.pdf), accessed May 31, 2002.

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Exhibit 11  Total Number of Large Dairy Operations in the United States and Percentage of Inventory (500 to 2,000+ Heads of Cow)

	500-999 Head					1,000-1,999 Head					2,000+ Head
Year	# of Operations		% of Inventory(a)			# of Operations		% of Inventory			# of Operations		% of Inventory
1998	1,500		10	%		680		9.6	%		235		7.4	%
1999	1,600		11	%		695		10.0	%		255		7.9	%
2000	1,700		12	%		695		10.1	%		280		9.2	%
2001	1,700		12	%		770		11.5	%		325		11.1	%

Source: EPC Analysis of USDA data on dairies maintained in the Agricultural Statistics Database (http://www.nass.usda.gov:81/ipedb), accessed on September 4, 2002.

(a) Percentage of inventory represents the percentage of all dairy cows in these operations.

Exhibit 12  Total Number of Large Hog and Pig Operations in the United States and Percentage of Inventory (10,000 to 50,000+ Heads of Hogs and Pigs)

	10,000-19,999 Head					20,000-49,999 Head					50,000+ Head
Year	# of Operations		% of Inventory(a)			# of Operations		% of Inventory			# of Operations		% of Inventory
1998	472		5	%		181		4	%		181		28	%
1999	466		5	%		199		5	%		181		30	%
2000	490		5	%		235		5	%		207		34	%
2001	513		5	%		266		6	%		209		36	%

Source: EPC Analysis of USDA data on swine farms maintained in the Agricultural Statistics Database (http://www.nass.usda.gov:81/ipedb), accessed on September 4, 2002..

(a) Percentage of inventory represents the percentage of all hogs in these operations.

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Exhibit 13  EPC’s Project Model

Phase 1: Business Development		Phase 2: Facility Development and Sale		Phase 3: Facility O&M
EPC develops and negotiates the following:		EPC supervises construction and monitor compliance with all contracts, which includes the following:		EPC operates the facility under a long-term operations and management contract:
Power sales Contract-initial transaction sized to fit a 6-8 installation farm consortium with a $30 million capital cost		Permitting		Complete implementation of preliminary plan
Farm Group consortium organized as LLC or cooperative structure to supply electricity to power contract		Site development		Implement modification and changes based on actual experience
Engineering and design		Physical materials sourcing		Continue effort to market Co-products and Emission Offset Credits
Arrange contracts for construction and procurement		Construction management		Provide accounting and project reporting to consortium
Arrange and implement construction and permanent financing of the project		Develop preliminary operations and management plan, commence hiring and training of staff		Begin meeting commitments of operations and maintenance agreement
Develop marketing for Green Tags and unbundled Emission Offset Credits and Co-products		Facility start-up testing and connecting to the grid		EPC generates service revenues and profits as well as cash flow participation
		Complete facility sale transaction
		EPC recognizes sale revenues and reportable profit

Source: EPC’s Business Plan 2001.

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