April 17, 2008 | General

Biggest Bang From The Biogas Production Buck

BioCycle April 2008, Vol. 49, No. 4, p. 37
Review of considerations and costs for selling biogas from on-farm anaerobic digestion systems through the electrical grid or the natural gas pipeline.
Norma McDonald and Diane Greer

WHEN Fennville, Michigan-based Scenic View Dairy decided to expand its anaerobic digesters, it faced a decision on how to maximize the value of the additional biogas produced. One option called for converting the excess biogas into electricity for sale to the grid. But a second option, upgrading the biogas to pipeline-quality renewable natural gas (RNG), produced a higher rate of return on invested capital.
Any farm installing an anaerobic digestion system producing more biogas than required to meet its own energy needs faces a similar dilemma. Will sale of electricity to the grid or sale of RNG yield a greater return on investment? Capital requirements, operating expenses and revenue generated determine the answer. These factors, in turn, depend on site-specific considerations, business requirements, local regulations and regional energy sources.
The Energy Independence and Security Act of 2007 (EISA2007), signed into law by President Bush in December 2007, promises to improve the revenues received by waste energy recovery projects selling electricity. Before EISA2007, regulated utilities operating under the Public Utility Regulatory Policy Act of 1978 (PURPA) were required to purchase electricity from nonutility producers at “avoided costs.”
PURPA didn’t define avoided costs but instead delegated this task to state utility commissions. State definitions frequently omitted relevant costs such as overhead or capital-carrying expenses, resulting in prices paid to producers that were well below market rates. Low prices for electricity generated from biogas producers have been one of the factors negatively affecting the economic viability of anaerobic digestion projects.
EISA2007 gives producers of waste energy recovery projects more options for selling excess power. First, it requires utilities to purchase excess power from producers based upon an explicit formula. This provision essentially establishes a floor for purchase prices that is expected to be higher than the current definitions of “avoided costs.”
But EISA2007 also permits projects to seek higher prices by selling power directly to third parties. Utilities are now required to transmit a project’s excess power to up to three locations on the utility’s system for direct sale by producers. It also permits projects to install private wires, or microgrids, to three separate locations within a 3-mile radius of the project’s facility. If the utility transmits the electricity for sale to a third party, it can only charge a project transmission cost for delivering the power.
Provisions permitting the sale of electricity directly to third parties are likely to improve the bargaining position of projects and encourage utilities to become more aggressive in negotiating purchase prices for renewable power above the floor set by EISA2007. The option to set up microgrids will also broaden the number of kilowatts that a producer can use for its operations. For example, under PURPA, Scenic View Dairy wasn’t permitted to run power lines across the street to a newly purchased facility. Instead, the dairy was required to sell excess electricity to the utility at avoided costs. The utility then sold the power back to Scenic View’s new facility.
In states with renewable portfolio standards (RPS), biogas projects producing electricity can also earn revenues from the sale of renewable energy certificates (REC). An RPS mandates a minimum percentage of electricity sold by utilities for retail consumption be produced for renewable energy. Utilities can purchase RECs separately or in conjunction with renewable power purchases to comply with state RPS requirements.
The value of a REC is dependent on the percentage of renewable power required under the RPS and the type of power sources that qualify. REC pricing will be low in states with broad definitions of renewable sources and low percentage mandates.
In states without an RPS, biogas projects may receive revenues from the sale of carbon credits. Carbon credits are earned when projects reduce greenhouse gas emissions by capturing methane and replacing fossil fuel sources with renewable energy. The credits can be traded or bought and sold on established markets.
For producers of electricity from renewable sources, carbon credit calculations are available for every zip code in the U.S. and are based on the emission reductions resulting from replacing the area’s traditional source(s) of electricity generation. In Michigan, where electricity is generated from coal, producers will receive a larger number of carbon credits for generating renewable power from biogas than in Iowa, where electricity is predominantly produced from hydropower.
Costs to interconnect to the grid may add considerably to a project’s capital requirements. Major factors affecting interconnection costs are the proximity, size and vintage of the electrical substation closest to the project.
Large farms producing substantial quantities of electricity can overwhelm small electrical substations. Many older substations with outdated equipment won’t support distributed power applications. Even newer substations may require equipment upgrades to handle the additional load and its distribution. In all cases, upgrades or replacement of substation equipment are paid for by the project as part of its interconnection costs.
Renewable power producers must also pay for metering equipment. Most utilities use remote telemetry units for metering, which are relatively expensive. In other cases, a project will need to install multiple data and voice lines to enable transmission of meter readings to the utility.
Information on the conditions and vintage of equipment at substations is not available to nonutility producers. Instead, a project must initiate and pay for an interconnection study to determine interconnection costs. Studies are typically priced as a percentage of the anticipated project costs and can run from $5,000 to $10,000.
Interconnection costs will obviously vary based on the factors cited above. But as a rule of thumb, projects generating 150 kW of power that are close to a modern substation can expect interconnection costs of about $50,000. Larger projects producing more than 500 kW of power that are more than a mile away from an older substation could easily see interconnection costs of $250,000.
Purchasing generators represents a significant capital expense for any project. Generator sets are sized in 25 kW increments and can be easily configured to meet a project’s specifications. Most electrical generators will require upgrading the biogas to prevent corrosion and damage to the system. This typically involves investment in systems to condense out some of the water and to remove hydrogen sulfide (H2S) to some minimum level.
Certainly a major benefit of producing electricity is the recovery of waste heat from the generator set for use in heating the digester and, in some cases, further conditioning of the biofiber from the digester to reduce the level of microbial activity and moisture. With proper planning, any waste heat not used to heat the digester can be used effectively on a farm. Dairies can utilize the additional waste heat to run absorption chillers to chill milk and other dairy products. Other types of farms may have requirements to store materials in cooler conditions.
The cost of upgrading biogas to pipeline quality specifications – to make renewable natural gas (RNG) – is significantly higher than the cost of cleaning biogas for use in a generator. Upgrading entails the reduction of water, H2S, carbon dioxide, oxygen, nitrogen, dust and related materials that can interfere with proper operation of the pipeline. The gas must also be compressed to the proper pressure range for insertion, which is dependent on the type and size of the pipeline.
Moisture removal generally requires a cooling process to extract the water from the gas. Less expensive passive approaches, such as ground cooling and water traps typically used for cleaning up gas for electrical generation, are not sufficient.
H2S levels need to be reduced well below the levels typically required for electrical generation. Projects can choose between several types of H2S removal systems. Some are capital intensive while others raise variable costs based on the raw materials needed for ongoing operation of the system.
Technology choices for upgrading biogas include physical absorption, pressure swing absorption, water scrubbing, amine scrubbing and membrane separation. Each process has advantages, disadvantages and relative costs. Some options will work better for smaller projects and others for larger projects. The capacity requirements of the upgrading system are dependent upon the quality of gas produced by the digester. Systems can handle a higher volume of gas at 65 percent methane than 55 percent methane. For richer gas, the separation efficiencies are greater and the capacity and throughput of the systems increase.
On the cost side, pipeline insertion of RNG can substantially increase capital costs, depending on the distance, size and type of gas pipeline nearest the project. But pipeline insertion tends to be a little easier than interconnecting to the electrical grid, since the list of items to consider is shorter and gas utilities tend to be more receptive to new sources of supply.
One of the first considerations is the amount of pipe that needs to be run between the project and the point of insertion. One project in Idaho had to run 45-miles of pipeline, while a farm in Michigan needed to run only 500 feet.
As with electric utilities, gas utilities require metering equipment. But the gas utilities also require quality monitoring equipment to insure that each cubic foot of gas produced meets technical specifications. The project bears the cost of the metering and monitoring equipment.
For low to medium distribution pipe-lines, ranging from 15 to 150 pounds per square inch gauge (psig), insertion costs will range from $50,000 to $100,000. For a high-pressure line, the cost will be closer to $200,000. Due to the additional costs, it is difficult to economically justify a RNG biogas project for facilities producing 75 standard cubic feet per minute (scfm) or less of biogas.
Prices received for the sale of RNG to gas utilities are typically based on regional market indexes, such as NYMEX Henry Hub. Revenues for projects with uncertain biogas supplies or unwilling to commit to selling a minimum quantity of RNG will be variable due to the volatility of natural gas pricing both seasonally and on a year-to-year basis. Biogas producers willing to commit to selling a minimum quantity of RNG can often negotiate fixed or indexed price contracts for 5 to 10 years. The availability of longer-term agreements, generally not obtainable from electrical utilities, can be helpful during project financing discussions.
Projects selling RNG may also sell carbon credits. But the revenues received tend to be lower than from those for selling electricity because carbon emissions reductions from displacing natural gas are much lower than for coal, which is used to generate over 48 percent of the nation’s power. The lower value of carbon credits could be mitigated by higher prices paid for the gas.
Projects considering the production of RNG are often concerned that there will not be enough heat to keep the digester warm. Depending on the technologies employed, waste heat is available from heat exchangers on the gas compressors or the exhaust gas from pressure swing absorption systems. If insufficient waste heat is generated, a small amount of biogas can be used to power a boiler. Boilers to heat a digester cost around $10,000 and require minimal retrofitting to run on biogas.
Table 1 shows how these factors affect the rates of return for three options at a 1,000 cow dairy farm: Using the biogas only for on-farm energy requirements; Generating electricity from excess biogas; and Selling RNG produced from the excess biogas to a gas utility. The table uses a baseline estimate for the price received for the sale of electricity to the grid and gas to the utility. When analyzing options, it is prudent to run best and worse case scenarios for revenue generation by estimating low and high price ranges for the sale of electricity and RNG.
Under the scenario present in Table 1, the farm would choose to use biogas only for its own energy requirements, achieving the highest rate of return of 7 percent and recouping its capital investment in the shortest time, 7.1 years.
Electrical generation yields a lower rate of return due to the low price paid per kWh of electricity and the high capital and maintenance costs associated with adding additional generators to produce the electricity. Selling RNG resulted in an even lower rate of return. Higher revenues from the sale of RNG don’t offset the higher capital and operating expenses to clean and compress the gas for pipeline insertion.
The results of this analysis are highly dependent upon the amount of excess biogas produced by the system. Table 2 shows the same analysis except a 5 percent cofeed of other wastes is added to the digester, boosting biogas production over 75 percent. Cofeed options include syrup stillage from ethanol plants, glycerin and food wastes.
Remodeling the system with higher energy sales results in a very different picture. RNG production is now the best option. Capital costs for upgrading and compressing the gas for pipeline insertion remained the same, since the process better utilizes the capacity of the existing systems. Meanwhile, production of electricity from the additional biogas requires the installation of another generator set, increasing capital costs by $350,000. Revenues for RNG production increase by 88 percent versus 82 percent for electricity generation. The net result is that the rate of return for RNG production is higher and the payback period lower than the other two options.
This analysis, to some extent, is a function of the relative immaturity of the market supplying gas cleanup and compression equipment. Manufacturers currently don’t offer a wide range of equipment sizes. The net result is a project can spend the same amount of money to process 75 scfm of biogas as 200 scfm of biogas. Costs then double for jumping to the next increment in equipment size, which can handle 250 to 400 scfm. These results suggest that when configuring systems for the sale of pipeline RNG, it may pay to increase biogas production through the addition of cofeed to maximize the capacity utilization of the equipment.
Several other factors should be kept in mind that can affect the return on a system, including escalating construction and materials costs. In 2007, concrete price varied by 40 percent. Steel prices escalated due to worldwide demand.
New regulations can also impact project returns. For example, California recently mandated reduction in H2S emissions. As a result of the new regulations, any site using biogas to produce electricity will need to remove H2S first. It is no longer an option to just send the biogas directly to the generator. In all cases, it pays to do your homework and investigate all the options before deciding on the course that works best for your project.
Norma McDonald is Operating Manager of Phase 3 Renewables, based in Cincinnati, Ohio. Diane Greer is a Contributing Editor to BioCycle. She can be reached at greer@greerresearch.com.

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