|A Veterans Affairs (VA) facility in Ann Arbor where SSOE has assisted in installing a natural gas-fired cogeneration system|
How does a developer assess the viability of a proposed cogeneration scheme in the US? Here, Tom Fitzpatrick and Ron Lutwen take us through a typical process to examine overall feasibility, permitting hurdles, fuel costs and contracts, energy sales and financial strategy issues.
Approximately 4% of the electricity produced in the United States of America comes from privately and publicly-owned cogeneration plants. Manufacturers are the largest group of cogenerators, with 40% of the nation’s facilities. But other cogenerators include municipalities with steam or hot water district heating, as well as healthcare concerns and also colleges and universities.
Cogeneration makes sense for municipalities, healthcare operations and educational institutions because they can accept a 15–20-year payback period. But manufacturers typically demand a 2–5-year payback period, which can make cogeneration impractical for some commercial organizations.
What is cogeneration? How does an organization determine whether or not it would be worthwhile to cogenerate? Perhaps most importantly, what will it take to finance a plant?
The key to the feasibility of cogeneration is the cost of electricity and fuel in a particular geographic area. If prices for electricity are low – 3–5 US cents/kWh – cogeneration will probably not be economical.
Provided the cost of fuel is reasonable, cogeneration begins to become practical as rates rise to 7 US cents/kWh and above. In some regions of the US, the cost story is easy to read. In New York City, for instance, electricity prices typically run to about 15 US cents/kWh.
As time goes by, organizations in more and more regions of the country will find cogeneration becoming more attractive as electricity prices rise. Some experts project that prices will increase by as much as 30–50% in coming years. The process has already begun. One major Midwestern utility recently applied for a 15% rate hike.
POLLUTION CONTROL AND OTHER PERMITTING CONSIDERATIONS
The decision to cogenerate can also hinge on other factors such as air pollution control regulations in different regions of the country, the availability of natural gas, and the potential for using other kinds of fuel to heat boilers.
Cogenerators located in non-attainment areas as defined by the Environmental Protection Agency (EPA), for instance, will generally face more onerous air pollution control regulations than those in areas that have attained the EPA’s clean air goals.
In fact, it may be necessary to go to extraordinary lengths to get a permit in a non-attainment area. For instance, some cogenerators have found manufacturing plants in their area that were closing and petitioned to be allowed to use those plants’ allowances – with some reductions.
In other cases, cogenerators have proposed tight emissions control systems in order to be viewed favourably by regulators, with the hope of decreasing the permitting schedule. But these cases are more the exception than the rule and, in any case, the cost of the pollution control systems may make the project too costly to bother with. Acquiring an air pollution permit may also take too long for a project to be viable. Some applicants have had to wait as long as 18 months.
The air pollution permit to install is typically the most difficult permits to obtain, but other permits can become stumbling blocks as well. In some parts of the country National Pollutant Discharge Elimination System (NPDES) and/or storm water runoff permits can be difficult to obtain. Then there are the zoning and construction-related permits.
FUEL COSTS AND CONTRACTS
Prospective cogenerators in some areas of the country may find it difficult to negotiate long-term contracts for natural gas at favourable prices. In these areas, the competition for natural gas may be heightened by the replacement of coal-fired plants with new natural gas-fired plants.
If expensive natural gas is a deal breaker, it may be possible to switch from natural gas to one or another so-called opportunity fuel – biomass, landfill gas, municipal solid waste, tyre derived fuel, waste wood and others. But opportunity fuels may raise other roadblocks. They typically emit more pollutants than natural gas, thereby complicating and lengthening the permitting process. It can also be difficult to find opportunity fuel sources that provide homogenous supplies. A homogenous fuel delivers a relatively constant heat value, so that the fuel’s heating value falls within a fairly small range.
Municipal solid waste is among the least homogenous fuels. Paper, cardboard, wood, plastic and other materials in solid waste each give off different amounts of heat when burned – although some waste-to-energy plants process the waste into pellets before burning it to improve the homogeneity.
The homogeneity of the fuel affects the efficiency of the power generating process. Engineers must tune the combustion design to the heat units available from the fuel. A fuel that delivers varying BTUs will require the boiler design to accommodate the lowest number, which may make the entire cogeneration system less efficient.
Opportunity fuels may have volatile prices as well. For instance, one cogenerator may arrange for a constant flow of green wood waste, a homogenous fuel that provides 4000 to 5000 BTUs/lb (2.6 – 3.2 kW/kg). But if someone else builds a nearby facility that uses wood waste the price of wood waste across the region will rise.
ENERGY SALES AND INCOME
In addition to reducing – or at least controlling – energy costs, a feasible cogeneration plan may generate an appreciable level of income on energy sales to corporate energy users and to utility companies. Cogenerators can also sell energy in the form of steam, chilled water, hot water, and compressed air.
Revenue from outside sales of power and/or energy helps to pay for the plant. Perhaps more importantly, outside sources of revenue may help in acquiring reasonable financial terms if managed strongly enough through contractual agreements. Lenders typically want to see long-term agreements. In the case of a corporate customer, lenders will discount the value of that income on the assumption that the corporation might close the plant or move it somewhere else.
Contract negotiations can deal with this in the form of a clause that covers 20 years (or some other lengthy term) of energy payments, plus a lump sum buyout if the plant closes or moves.
Agreements between cogenerators and utility companies also help smooth the way with lenders. However, such agreements might be difficult to negotiate, depending upon the utility.
As of today, 27 states plus Washington, DC, have legislated something called Renewable Portfolio Standards (RPS). Five more states have instituted voluntary standards. States with RPS require utilities generating electricity within their borders to obtain a certain percentage of that electricity – from 10% to 25% – from renewable fuel sources.
Many utilities will comply with RPS requirements by purchasing renewable energy from other sources – such as cogenerators – and will make long-term agreements to ensure that they continue to meet their renewable energy obligations. Indeed, RPS can in many cases make cogeneration possible.
A high-enough cost of electricity can combine with manageable permitting requirements, the availability of reasonably priced fuel, willing corporate energy users and RPS requirements to make a cogeneration plant feasible by ensuring that lenders will take an interest in the project.
Real estate and construction lenders typically finance everyday construction projects such as apartment complexes, hotels, manufacturing plants, office buildings, retail shopping centres and warehouses. When lenders deal with unusual projects such as cogeneration plants, they often require a higher percentage of self-funding, along with any number of conditions that may seem onerous.
Requirements will typically include a firm capital cost for construction in the form of a signed engineering, procurement and construction (EPC) contract. This means that a prospective cogenerator will have to have engineering and permitting developed to a point where it can attract firm EPC bids. And that is just the beginning. Before completing financing, lenders will require procurement of all permits, including the all-important air quality permit.
A looming regulatory issue is the question of capturing carbon dioxide. While this has not been done on full-scale installations, researchers are testing the technology, which will ultimately be very expensive. Carbon capture and sequestration is not mandatory at this time but it may be required in the future. When carbon capture does become obligatory, it will also figure into the financing equation.
Then comes the preference for long-term contracts for fuel. If the fuel is something other than natural gas – an opportunity fuel of one kind or another – prospective lenders may also require alternative pro formas based on natural gas, just in case supplies of the preferred fuel are compromised.
Lenders may also require the review of a contract with a third party operator and maintenance provider: a competent, experienced service provider who will run the plant and keep it in working order.
Finally, lenders will typically ask for a fairly large equity contribution. How much? It could range between 5–10% and 50–60%, depending upon how well a proposal satisfies the components of this list of lending requirements.
Although experienced engineers can usually carry out feasibility and basic cost studies in short order for reasonable costs, when the process moves beyond those into design, clean air permitting, the specification and acquisition of capital equipment, construction and commissioning, costs will rise quickly and remain high until the plant comes online.
A project as complex as a cogeneration plant will inevitably take a long time. Success requires a champion, a senior executive committed to the project with the authority to make his or her commitment stick. Without a champion, projects will flounder – especially when a recessionary economy dictates cutbacks in capital spending.
With a champion that sees the project through, an organization that can cut utility costs enough to pay for a plant in a few years can get it done. And after the plant is paid for, the organization will have seized economic control over utility costs, a position that will become increasingly enviable as the years pass.
Thomas Fitzpatrick is a Department Manager at SSOE Group who specializes in air pollution control Email: tom.fitzpatrick@SSOE.com Ronald Lutwen is a Senior Associate and Power Division Manager at SSOE Group who specializes in boilers Email: ron.lutwen@SSOE.com.
COGENERATION AND HISTORY
Cogeneration or combined heat and power (CHP) generation is the process of making two forms of energy – typically heat and power – from one fuel – natural gas, for example. When natural gas burns, for instance, the resulting heat turns water into steam. Steam can be used to generate electricity in a steam turbine generator and provide a heat source for process or a heating system.
Cogeneration can produce electricity and heat with 10% to 30% less fuel than is required to generate both forms of energy separately. In other words, cogeneration is a strategy for conserving energy.
Cogeneration is not a new idea. In 1882, Thomas Edison built the nation’s first power plant, a CHP facility. Between 1882 and the 1930s, cogeneration was common. There was no reliable power distribution network, and manufacturers in need of reliable power had to make their own.
Once a distribution network developed, utilities could provide large users with cheap power, and cogeneration largely died out. Today, with electricity costs rising steadily, cogeneration is making a comeback.
|The Sauder Woodworking Company has run a CHP system featuring a pulverized wood burner for 20 years, bringing estimated annual savings of $700,000 in electricity, $50,000 in steam and $1.7 million from wood recycling|
|The VA facility in Ann Arbor will host a 800 kV cogeneration system Source: Brandon Bartoszek|
Two SSOE cogeneration projects
Sauder Woodworking Company cogeneration facility, Archbold, Ohio
SSOE Group personnel were retained by Sauder Woodworking Company to study possible electrical and thermal energy cost saving measures. It was determined that by using Sauder’s waste wood as fuel, a wood-fired cogeneration facility would provide the lowest cost energy.
Staff obtained environmental permits and designed the facility. Various combustion methods were reviewed for burning the wood waste. The final choice was for a pulverized wood burner system of combustion. The design included two package boilers to be fired by wood waste and natural gas. Two 3.5 MW stream turbine generators with two steam extraction points produced the electricity. The extraction steam is used for heating and process.
Pollution control was provided by a mechanical dust collector, an electrostatic precipitator and a selective catalytic reduction system for nitrogen oxides (NOx). The balance of plant – including fuel handling, water treatment, a distributive control system, continuous emission monitoring system, cooling towers and the building – were all designed by SSOE personnel.
The installation has now been operating for 20 years and is estimated to provide annual savings of US$700,000 in electrical energy, $50,000 in steam energy and $1.7 million in wood waste recycling instead of landfill depositing. Particulate emissions average 3% (the EPA opacity limit for the area is 20%).
Veterans Affairs Medical Center cogeneration system, Ann Arbor, Michigan
SSOE Group has recently been selected as part of a design build team along with DeMaria Building Company Inc for an 800 kW cogeneration system to be located at the Veterans Affairs Medical Center in Ann Arbor, Michigan. SSOE Group will be responsible for all design aspects of the project including MEP (mechanical, electrical and plumbing), architectural and structural systems.
The new natural gas-fired cogeneration system will use combustion turbine generators along with a waste heat boiler to provide both steam and electricity to the campus of 14 buildings totalling 110,000 m2. The proposed system will be located adjacent to the existing energy centre and will be able to provide operator initiated automatic start-up and shutdown of the system. Steam will be used for heating, reheating and sterilization. Electricity from the cogeneration unit will be fed into the VA’s power system. Controls and relay protection will be put into place to immediately shed enough load so the cogeneration unit will be capable of continued operation. Load shedding will include automatic operation of existing automatic transfer switches forcing existing emergency generators to pick up specified portions of the electric load for the facility. Emissions of NOx will not exceed 0.18 kg/MWh.