Statement of Environmental Power Corporation

Good Morning, Mr. Chairman.  I am Joe Cresci, the Chairman of the Board of Environmental Power Corporation. EPC was founded in 1982 and is headquartered in Portsmouth, New Hampshire. Since its founding, Environmental Power has developed only generating facilities powered by non-conventional fuels and renewable energy sources, including hydro-electric and waste coal-fired generation.

The focus of my comments this morning is our subsidiary, Microgy, Inc., headquartered in Golden, Colorado.  Microgy develops biogas systems, utilizing anaerobic digesters, which are very efficient at extracting methane-rich biogas from a combination of livestock manure and other organic and food industry wastes.  To date, we have completed or announced projects in Wisconsin, California, Texas, and Nebraska. With appropriate public policy, we see large market opportunities in many other areas of the country, including large and small agricultural areas that are home to dairy and feed cattle farms as well as swine production areas.

We refer to our biogas as RNG – Renewable Natural Gas.  Our RNG is used to produce “green” pipeline-grade methane, thermal energy or electric power. Microgy, along with our Danish licensor, has significantly improved conventional anaerobic digestion technology, enabling us to generate RNG at volumes and costs that are commercially attractive.

Although SEC regulations and competitive considerations do not permit me to discuss cost and pricing matters in detail, I can say that we believe our RNG will be competitively priced compared to projected prices for LNG imports. At the same time, our technology and manure handling processes also significantly reduce greenhouse emissions, improve water quality and dramatically reduce odors around animal operations.

There are three areas where support from the government could allow this expanding technology to compete with the highly capitalized and government-subsidized existing energy infrastructures.

1)      First, a credit for the production of biogas from certain renewable feedstocks: this production tax credit should be on a parity with biodiesel from waste oil, which is the most comparable product for a renewable fuel already on the books. The credit also needs to be transferable under rules and regulations created by the Secretary of the Treasury. A tax credit which is not monetizable is significantly less valuable to a small, emerging industry which may not yet be turning a profit.

2)      Second, a counter-cyclical safety net program for biogas producers: this would be a payment first used to pay down loans and other obligations from the building of a facility if the average daily price of natural gas fell below a predetermined price for a prescribed period.

3)      Third, transportation incentives for smaller operators: these would help incentivize multi-farm collection and transportation of qualified energy feedstocks from smaller livestock operations to a qualified facility or for the purchase or construction of equipment or facilities for collection and transportation.

Why is this technology development so important? Anaerobic digesters (AD) are devices that capture, control and enhance the degradation of organic material.  Two principal benefits occur: production of energy and environmental benefits — including large scale greenhouse gas capture and manure management.    The biogas produced by anaerobic digestion is composed of about 60% methane, the principal ingredient of natural gas, with most of the rest being carbon dioxide.  Methane, which is 21 times more damaging as a greenhouse gas than CO2, would ultimately escape into the atmosphere if not captured in the AD process. Biogas can be used “as is” as a power source, or cleaned up to be used as a renewable substitute for natural gas, propane or other fossil fuels.  If to be used for interconnection with the natural gas pipeline, the biogas must be scrubbed until it is in excess of 95% methane.  It is worth noting that with current scrubbing technologies, the additional capital and operating cost is only justified in the case of larger-scale systems.

In the U.S., until recently, use of AD has been limited to old-generation, small-scale technology.  Currently, however, advances in technology have made AD more cost competitive with other types of energy.  While viability is well established at operating facilities, large scale deployment of this type of energy production requires support comparable to that provided to competing sources of energy in order to expand and develop the potential market into a significant renewable energy source that can truly impact the country’s needs for alternatives to fossil fuel.

Digesters are normally designed to process the feedstock available to them and can be scaled up and down in size.  However, in order to access the commercial mainstream – that is, to be economically viable and make a significant impact on our energy supply – larger-scale systems are necessary to achieve economies of scale in both production and market access, including access to the existing infrastructure for marketing, transportation and distribution of conventional fuels. 

Our on-the-ground experience and market research has shown us that the small-scale, single farm systems face a host of difficulties. They have relatively high expense due to a lack of economies of scale, and often, poor operational results. The systems are typically operated by the farmer, who is not and does not want to be an expert on AD and manure management. Smaller operations also have interconnection issues. The small energy producer is not worth a utility’s time and effort and have even more limited private sector financing opportunities. Their economic viability relies heavily on existing USDA and state grant and subsidy programs.

Larger-scale systems allow for professional management, negotiation of energy agreements with utilities and other energy end users, efficiencies and economies of scale, and especially, the volumes of output required for refinement into pipeline quality renewable natural gas for delivery via our nation’s existing transport and distribution infrastructure, the interstate pipeline system.  Such projects have numerous commercial financing options. The farmer, rather than diverting his efforts to his own system, can receive a slice of a larger pie, without a financial or management investment on his part. In Microgy’s business model, we seek to become the partner of the farmer, with our specialty being the day to day operation of the anaerobic digester.

AD utilizing animal and other byproduct materials can generate significant quantities of energy in the United States.  We estimate that AD systems on larger-scale dairy, swine and beef farms, if fully operational and with a complete supply of all feedstock materials, could produce well over 340 billion cubic feet of natural gas equivalents per year. Note that 1000 cubic feet of natural gas equals approximately 1 million btus. The potential production of 340bcf has the energy equivalent of approximately 2.5 billion gallons of heating oil per year.

In addition, a significantly larger market would be available if expanded to smaller farms: over 90% of all the cows in the U.S. are on farms smaller than 2,000 head.  However, in order for energy production to be cost-effective on such farms the manure from these farms would be combined for use in larger, centralized facilities.  In this way smaller farms can also benefit from economies of scale and the other benefits accruing to larger-scale systems.  Without support, however, today’s transportation costs could limit their opportunities to participate.

Processing manure and other materials by AD also creates significant environmental benefits, including greenhouse gas emissions reductions, as methane that would otherwise have been released into the atmosphere is captured.  Note that methane is 18-21x more powerful a greenhouse gas than CO2. Other air quality improvements include significant reductions in odor, ammonia and particulates. Utilizing AD also generates water quality improvements, including reduction of excess nutrient run-off – such as occurs with phosphates, nitrates, and BOD materials, and help to farmers in addressing significant water pollution challenges.  In addition, the systems produce value-added products.  Each one million gallon digester would also generate 100 tons NH3; 153 tons P205 and 184 tons K20 fertilizers, as well as approximately 10 cubic yards of bedding, compost or mulch. At full development of the potential AD to Energy market, these value added products would equal over 500,000 tons of NH3, 800,000 tons of P205, 900,000 tons of K20 and 52,000 cubic yards of bedding, all per year.  Note also that many of the synthetic products such as fertilizers that would be replaced by the residuals from AD energy production are themselves produced from petroleum.

These projects bring significant economic benefits to the areas where they are built, normally in rural often isolated regions.  Although we realize that real “economic gain” is not part of the Congressional scoring process, we believe it is extremely important to point out that, based on our experience we conservatively estimate approximately $3 to $30 million dollars in direct development and construction investment as well as annual direct spending of up to $2.5 to $4 million per year.  Applying the standard 5 to 1 multiple to account for the “ripple effect” of regional economic impact, we estimate construction period impact in each project area of $15 to $150 million and annual extended economic impact of up to $20 million.  Specifically we expect large, eight-tank AD projects such as the one in Stephenville, TX to incur about $2.5 million in annual direct spending with a $12-15 million ripple effect and about 1/8 of that on smaller projects like our AD at the Norswiss farm in Wisconsin.  These are big impacts in the generally small regional communities where they are located.

A variety of renewable (as well as non-renewable) fuels receive Federal Government assistance.  This government assistance is expressed in a variety of terms, depending on the fuel and/or end product produced, such as per gallon of fuel produced, per kwh of electricity generated, etc.  In order to compare these subsidies, it is useful to express them all in terms of dollars of subsidy per units of energy (mmbtu) produced.  When viewed in this manner, it is apparent that renewable liquid fuels receive greater support than others.  For example, biodiesel produced from agri-fuels receives approximately $8.55 per mmbtu; ethanol receives $6.16; and biodiesel from waste oil receives $4.27.  On the other hand, generating electricity from renewable sources, such as wind or solar, receives substantially less, in a range of $2.57 per mmbtu.

Biogas is akin to a renewable liquid fuel and, from a support perspective, should be treated similarly to biodiesel and ethanol:

• Biogas and biodiesel are derived from the processing of similar feedstocks.
• Renewable liquid and gas fuels have more flexible end uses: pipeline delivery as a fossil fuel alternative in industry and homes, local applications as a fossil fuel substitute, or power generation.
• Liquid and gas fuels are efficient from a micro perspective.  Producing electricity from a liquid or gas fuel results in significant energy losses. For example, only 35% or so of the energy content of a fuel ends up as electric power.  The rest is wasted as lost heat.
• Liquid and gas fuels are efficient from a macro investment point of view.  For example, because wind generates power intermittently (only when the wind blows), utilities must also keep available significant extra generation capacity fired by conventional fossil fuels. Digesters, in contrast, run 24 hours per day, 7 days per week.

In sum, the production and use of biogas as a replacement for fossil fuels could potentially provide numerous benefits such as:

• Use of biogas as a replacement for significant quantities of fossil fuels and deliverable via conventional fuel distribution infrastructure
• Reduced greenhouse gas emissions
• Potential reduction in criteria air pollutant emissions
• Improved water quality through better manure management
• Less dependence on declining fossil fuel supplies
• Better energy security (through a reduced dependence on imported energy), and
• Stimulation of rural economies

These are benefits to society rather than merely financial benefits for the farmer who produces the biogas.  Consequently, it is appropriate for the government to provide support for the development of the biogas industry, an industry that did not exist when legislation was written for other renewable fuels.

If the biogas industry is to prosper, government must help launch policy initiatives that will provide the same direct financial incentives or tax credits that are now earned by programs that focus on renewable ethanol, biodiesel, and electricity.

Three areas are key:

• Monetizable production tax credits for biogas from certain renewable feedstocks.
• A counter-cyclical safety net for biogas producers and their lenders.
• Transportation incentives for biogas production for small operators.

We look forward to working with the Committee, and I would welcome you to visit our facilities around the country, particularly in Texas, where we are delivering RNG (our trademarked substitute for natural gas) to the pipeline.  Thank you for your careful consideration and support.

Market Size

More easily accessible larger-scale systems:

• Beef cattle: Herds with over 10,000 head:               268
• Dairy farms:            Farms with over 2,000 head:                 380
• Swine:                    Farms with over 20,000 animals:           452