Primary Energy Sources: Gaseous, Liquid, Solid Fuels
Hydrocarbons are nonrenewable, primary energy sources or fossil fuels such as coal, natural gas, and petroleum used to generate heating, cooling, and electricity. These fuels are also used for transportation and in products such as plastics, chemicals, and similar goods. The United States alone consumes almost 98 quads2 of energy every year with 80% of that as fossil fuels, 9% as nuclear electric power, and 11% of that as renewable energy.
Up until the 1960s, hydrocarbons were readily available and relatively inexpensive. Typically, a local, regulated utility company provided electricity, the same or a separate regulated utility company supplied natural gas, and regional fuel suppliers provided coal and fuel oil. The role of the facility manager in primary fuels management consisted largely of ensuring that contracts were in place with the various fuel suppliers for the provision of energy on demand. These energy suppliers were responsible for the procurement and transportation or transmission of energy, the storage of local fuel reserves, and for ensuring that energy was available on demand.
The oil embargo of the 1970s, which restricted the world petroleum supply, caused shortages, hyperinflated prices, and provided a wakeup call about the vulnerability of national energy supplies and associated economic interests. Other hydrocarbon markets were also impacted, causing grave concerns as natural gas supplies were curtailed, local fuel-oil and coal suppliers were unable to deliver on demand, and electricity production was placed at risk. The instability of the petroleum market continued to persist into the 21st century for a variety of reasons, including continued political instability in petroleum-rich countries, natural disasters such as Hurricane Katrina, manmade disasters such as the oil spills in Alaska and the Gulf of Mexico, and spikes in supply or demand.
Most institutions reacted to the fuel crises of the 1970s by appointing a full-time energy manager whose primary responsibility was to control the cost of energy, reduce its use, and ensure its continuous availability. Under the stewardship of energy managers, many institutions reactivated coal-fired equipment, invested in central plant systems, and constructed large oil- or coal-storage facilities. In addition, most took advantage of projected energy savings, and the U.S. Department of Energy (DOE) sponsored programs to finance building energy management systems and energy conservation projects.
The 1978 Public Utility Regulatory Policy Act (PURPA), the 1978 Natural Gas Policy Act (NGPA), and subsequent amendments provided energy managers with more options for managing energy costs and availability. PURPA allowed electrical consumers to generate part or all of their electrical requirements and obligated the local electric utility to furnish standby capacity and to purchase any excess electricity produced. NGPA established the ground rules for the deregulation of the natural gas industry; by the second half of the 1980s, deregulation of the industry had become a reality. Deregulation, combined with an abundant supply of natural gas and a drop in the cost of all fossil fuels, provided energy managers with access to low-cost gas supplies from producers and brokers, in addition to gas supplied by the traditional local gas utility.
The 1990s were marked by electricity industry restructuring and the passage of the landmark Energy Policy Act (EPAct) of 1992, as well as the reinvigoration of energy-efficiency and conservation initiatives, as many institutions took advantage of rebate programs offered by local utilities. Lighting systems were converted to high-efficiency fixtures, motors were replaced with high-efficiency types, constant-volume motors were converted to variable-frequency drives, and building control systems were replaced with building automation and energy management systems. Regional heating and cooling plants were expanded, thermal energy storage systems were constructed, ground source heat pumps were installed, standby generation was implemented, and controls were placed on emergency generators to permit peak demand management.
The Energy Policy Act of 2005 addressed “energy production in the United States, including: (1) energy efficiency; (2) renewable energy; (3) oil and gas; (4) coal; (5) Tribal energy; (6) nuclear matters and security; (7) vehicles and motor fuels, including ethanol; (8) hydrogen; (9) electricity; (10) energy tax incentives; (11) hydropower and geothermal energy; and (12) climate change technology,”3 while the Energy Independence and Security Act of 2007 further worked “to increase U.S. energy security, develop renewable fuel production, and improve vehicle fuel economy.”4 These acts helped drive investments in new renewable energy technologies such as solar and wind, as well as horizontal drilling for natural gas, also known as “fracturing” or “fracking.” The latter dramatically changed the forecast for natural gas sufficiency for North America and resulted in long-term low-price and high-supply projections.
The regulatory environment continued to evolve with the passage of the Clean Air Act in 1970 and its amendments in 1977 and 1990, and the passage of similar regulatory acts that included stricter air emission monitoring and control requirements, stormwater and groundwater protection, and the advent of greenhouse gas reporting in 2009. In February 2013, the U.S. Environmental Protection Agency (EPA) issued its final rule for the National Emissions Standards for Hazardous Air Pollutants for Area Sources (NESHAP): Industrial, Commercial, and Institutional Boilers and Process Heaters, also known as the Boiler MACT (Maximum Achievable Control Technologies), which required the installation of expensive controls on boilers. The promulgation of the final Boiler MACT rule coincident with projected long-term lower costs of natural gas has driven and is expected to continue to drive utilities and institutions to convert to natural gas.
Issues to be considered when evaluating fuel costs include the seasonal impact on market prices for the various fuels, cost comparisons of the various fuels on an equivalent performance basis, short-term and long-term market projections for the fuels, and accounting for any cost penalties associated with environmental compliance requirements. The geographic location of facilities, particularly their proximity to fuel supplies, affects the availability of a particular fuel to an area, especially for natural gas distribution pipelines and coal rail service. The availability of fuels to serve critical facilities such as hospitals, animal care, and research facilities, as well as the possibility of disruptions caused by strikes, pipeline failures, manmade or natural disasters, or political instability that may affect the world supply, are extremely important issues to consider when making a decision to commit to a specific fuel.
Cost, fuel availability, safety, and aesthetic considerations all factor into determining storage needs. Large storage capacity results in a lower risk of inadequate fuel supplies to serve facilities, especially critical areas, and provides greater flexibility in purchasing fuels during off-peak periods when the fuels typically cost less. However, large storage facilities cost more to construct, can tie up money in inventory, and often raise significant aesthetic, safety, or regulatory issues.
Most colleges and universities have carbon reduction and similar sustainability goals, and are increasingly leveraging their physical assets as “living laboratories” for their students to learn and explore sustainability initiatives. Faculty, staff, and students are increasingly vocal concerning the alignment of their institution’s strategic goals with the economic, environmental, and social equity goals of sustainability, including the use and types of energy on their campuses; investments in renewable energy certificates or credits and green energy technologies; divestment of institutional endowments in gas, oil, and coal companies; providing a living wage for employees; and similar initiatives.
This chapter provides an overview of the many challenges facing energy managers in handling the complex issues associated with primary fuels.
Natural gas is a mixture of methane (55 to 98 percent), higher hydrocarbons (primarily ethane), and noncombustible gases. The composition of natural gas varies, depending in large part on the surrounding underground conditions and the proximity of the gas deposit to oil deposits. Wet or saturated natural gas is found near oil deposits and, as such, has absorbed heavy hydrocarbons. Dry natural gas has no contact with oil deposits, and thus contains no heavy hydrocarbons. The nitrogen content in natural gas can range from 0 to 87.69 percent by volume. The composition of sulfur in natural gas in the form of hydrogen sulfide ranges from 0 to 7 percent by volume.
The heating value content of natural gas, which is defined as the thermal units contained in one unit of a fuel and released as heat when the fuel undergoes combustion, can vary from as low as 982 British thermal units (Btu) per standard cubic foot (CF) to as high as 1,089 Btu/CF.5 The variation in heating value content can have a significant impact on operations, as a low heating value can reduce boiler or generator output and cause increased emissions, since more product is needed to produce the same total output of energy. Many institutions currently use or are converting to the use of natural gas from coal or other fossil fuel sources as their primary energy source.
The end of the first decade of the 21st century saw an exponential increase in the use of “fracturing” or “fracking” technology in the natural gas industry, which has transformed the natural gas market in North America. Previously, forecasts for the North American natural gas market predicted that liquefied natural gas (LNG) would play a large role in meeting the growing energy demand of the United States. LNG is produced when natural gas is cooled to about –260°F at normal pressure and condensed into a liquid form. LNG is much easier to transport as it takes up about one six-hundredth of the volume in liquid form that it does in gaseous form. LNG is almost pure methane, since oxygen, carbon dioxide, sulfur, and water are removed during the liquefaction process. The United States, Canada, and Mexico have several import LNG terminals that re-expand the imported product to its gaseous form prior to supplying it to the interstate pipeline system or local distribution companies, or to storage facilities.6 The majority of the imported LNG comes from Trinidad and Tobago, Qatar, and Algeria.
All forecasts now point to domestic shale gas plays using fracturing technology as the long-term source of cheap, abundant energy for the United States. In fact, the United States now has several LNG export terminals that are proposed or in construction, and effective in February 2016, will have one fully operational export terminal in Louisiana. With the growth of the U.S. shale gas plays, LNG imports are expected to continue a downward trend while LNG exports are expected to rise.
Other sources of gaseous fuels include biogas, landfill gas produced when methane is generated as a natural by-product of anaerobic digestion of organics, and technology-made digesters that accelerate the anaerobic process. Syngas is produced from fossil fuels or from woody material under high heat and no/low oxygen conditions, leaving a char that can also be burned or converted into other uses. When the fuel is derived from organics such as manure, plants, food, agricultural waste, and sewage, the gas is considered renewable energy.
Liquefied petroleum gases (LPGs), a by-product of oil refinery operations or natural gas stripping, are commercially available as butane, propane, or a mixture of the two. Although some institutions use LPGs as a backup fuel, most rely on natural gas, which is more readily available and less expensive.
United States Regulatory Development
Most of the original natural gas pipelines were constructed by holding-company offshoots of major petroleum producers. These pipelines crossed state boundaries and therefore were not regulated by states. This resulted in a considerable monopoly of power being exercised by the petroleum companies. In an attempt to regulate the gas industry, Congress enacted the Natural Gas Act (NGA) in 1938. The NGA actually protected pipelines from competition and resulted in self-dealing among affiliated gas producers. However, it was the NGA that later gave the Federal Energy Regulatory Commission (FERC) the authority to regulate the construction of pipeline facilities and the transportation of natural gas in interstate commerce. In 1955 the U.S. Supreme Court decided that purchases from all producers should be regulated by FERC. This action led to administrative difficulties, price distortions, and eventually an acute gas shortage in the 1970s.
In 1978 Congress enacted the Natural Gas Policy Act (NGPA), which attempted staged regulatory reform and resulted in some components of the industry being deregulated while others were still subject to price controls. This further resulted in a supply “bubble” of natural gas and “take-or-pay” contracts in which pipelines were contractually liable for paying for billions of dollars of gas that they were then unable to sell at a commensurate price.
FERC Orders 436 (1985), 500 (1988), and 636 (1992) provided several regulatory changes that addressed the take-or-pay crises, articulated an “open access” policy that enabled utilities and industrial customers to purchase gas directly from pipelines or upstream suppliers and resulted in pipelines becoming common carriers, with the gas supply business being separated from the pipeline subsidiaries.
The energy manager has essentially two mechanisms for purchasing natural gas. The first option is to procure natural gas through the local distribution company (LDC), which has established rate structures for firm or interruptible service. Various levels of interruptible service can be negotiated, depending on how much risk the purchaser is willing to share with the LDC. Risks include shortages in local availability of fuel, severe weather, and volatile market prices. The second natural gas procurement option is the direct purchase of natural gas. The following is a discussion of application issues and the advantages and disadvantages of these two options.
Procurement Using an LDC
Most small users of natural gas contract directly with the LDC for the provision of natural gas. The LDC can be a municipality or a local regulated utility company that accepts natural gas at the “city gate,” that is, the point at which the transportation pipelines end and the LDC pipelines begin, and distributes natural gas to customers to meet their energy needs. If the facility has a backup source of fuel, the energy manager can opt to purchase natural gas from the LDC on an interruptible basis. If the facility has no backup fuel, the energy manager is required in most states to purchase natural gas at a firm rate. Most LDCs require a minimum annual consumption of natural gas to qualify for interruptible service.
Depending on the contract, an interruptible customer without standby fuels can be asked to shut down completely if conditions warrant, so entering into interruptible contracts should be carefully considered.
The rates and other terms of service are based on the LDC’s cost of service and are usually approved or set by the public utility commission. When the LDC is a municipality, the rates may include a component for local social programs such as police and fire protection, low-income energy assistance, energy conservation, and similar programs entitled “payment-in-lieu-of taxes.” Typically, both the firm and interruptible natural gas rates are charged in incremental steps in which the rate decreases with increasing quantities of natural gas consumed. Some LDCs set fixed rates for a given year for firm and interruptible service, although most allow their rates to rise and fall depending on their purchased cost or seasonal market conditions. Many LDCs include a rate adjustment that accounts for the heating value of the fuel, especially if they sell the natural gas in units of standard cubic feet, which is a volumetric unit, not an energy unit. Both firm and interruptible customers are charged a minimum monthly fee for natural gas service; this fee is usually higher for the interruptible rate.
The advantage of contracting for interruptible service is lower rates and costs. Obviously, the disadvantage of interruptible service is the likelihood of service interruptions that force the use of an alternative fuel such as oil, coal, or electricity. This may result in higher operating and maintenance costs or place the institution at risk of not having an alternative energy source during the period of natural gas interruption. The latter is a major concern for those institutions with critical areas that cannot sustain even a short interruption in service.
Procurement Using Direct Purchasing
Large users of natural gas can still opt to purchase firm or interruptible gas from the LDC. However, most large users have been able to achieve savings of up to 25 percent or more (compared to the cost of natural gas furnished by the LDC) by directly purchasing their natural gas. Small users of natural gas may be able to partner with other small or large users to aggregate their consumption and direct purchase. In addition, very large users of natural gas may find it economical to own, build, and operate their own natural gas pipeline and bypass the LDC altogether, especially if their facility is close to the interstate natural gas pipeline system.
To purchase natural gas directly, the energy manager enters into a transportation agreement with the LDC. This assumes the institution does not own the distribution pipe to their facility. Most LDCs charge a monthly transportation fee and offer transportation rates for firm to various levels of interruptible service. In addition to the transportation fee and rates, the LDC is generally allowed under regulatory procedures to charge a purchased gas adjustment (PGA) for changes in supply costs as an automatic pass-through to ratepayers. PGAs show up as a varying cost on each monthly gas bill. LDCs are also allowed to deduct for shrinkage, which assumes that some of the natural gas purchased by the customer is lost in transportation. Shrinkage essentially reduces the quantity of natural gas purchased by the customer by 1 to 3 percent of the total quantity of natural gas nominated, for example, the amount of natural gas they agree to procure.
The direct-purchase natural gas contract, which can be negotiated using the request-for-proposal (RFP) process or contracted using the invitation-for-bid (IFB) process, should include the following minimum provisions:
- Price. The cost of the natural gas purchase can be established as a fixed price: a spot market-priced, open-ended contract that reflects market prices at the time of purchase; or a negotiated base price that is adjusted based on specified criteria such as the indexed cost of oil or natural gas futures strips. The cost of natural gas may be slightly higher if the contract requires a guaranteed supply of natural gas to ensure certainty of supply. The latter arrangement also benefits natural gas producers and suppliers, who are guaranteed a market for their natural gas. In this case, the purchaser should include a price reopener clause in the contract, exercisable at specified periods in the contract, to enable flexibility in renegotiating the purchase price of the contract to reflect prevailing market conditions.
- Purchasing options. The purchaser can negotiate (1) natural gas production costs, (2) transportation rates, (3) transportation line losses, (4) penalties for over-and under-nominations, and penalties or credits for take-or-pay, (5) storage, and (6) contract management costs as separate contracts or as one overall contract. Contracting separately provides greater opportunities for cost savings but can result in substantial losses if the purchaser is not thoroughly familiar with each of these issues or is unable to devote adequate time to managing the contracts.
- Time of contract. Although the term of the agreement can be as short as 30 days, most contracts are established on a one-year basis with an option for annual renewal of up to three years. Some also have provisions for additional one- or two-year renewal options. Shorter term contracts can be the most advantageous, as they provide the purchaser the most flexibility in negotiating prices. However, they are the most vulnerable to seasonal fluctuations in price and provide no protection against long-term price increases. Most purchasers opt for longer-term agreements that contain a base-price agreement with provisions for market-based adjustments included. All contracts must contain a term of agreement and should have provisions for contract cancellation.
- Quantity. Most contracts specify maximum annual natural gas consumption and indicate daily, weekly, or monthly use. The purchaser is responsible for correctly nominating natural gas quantities for a specific pipeline pressure at the point of consumption. The latter is extremely important, as pipeline pressure directly affects the amount of natural gas that must be nominated.
Many energy managers choose to use a full-service natural gas supply broker for managing their natural gas purchasing needs. The broker secures natural gas supplies, arranges for transportation to the “city gate,” the interstate connection point, or to the “burner tip,” the meter at the plant, and assumes all responsibility for reconciling the quantity of natural gas purchased with the quantity of natural gas delivered. Full-service brokers usually require the institution to report meter readings daily or weekly and at the first of the month, which are used to nominate natural gas quantities. The responsibility for payment of any penalties for over-nominations that result in storage costs by the LDC should be negotiated as part of the contract with the broker. Undernomination of natural gas usually results in the institution obtaining natural gas from the LDC at the nontransportation rate, which is usually at the high end of the rate scale because of the small quantity of natural gas involved.
The natural gas purchase contract can be awarded to one or more brokers. In the latter case, shares of the contract are split between the brokers and set up to reward the best performing broker with the majority of the contract. In addition to directly purchasing all natural gas for the institution, it is possible for the institution to use the full-service natural gas broker to furnish natural gas only to a central heating plant or a cogeneration facility and to continue to contract with the LDC to furnish natural gas to individually metered buildings that utilize small quantities of natural gas. This reduces recordkeeping and frequency of meter readings, which require more staff time with little or no added benefit in savings.
The energy manager can further reduce costs by serving as his or her own natural gas broker. He or she can procure gas directly from a producer, contract with a transportation company for national or regional delivery of the purchased gas to the LDC, and contract with the LDC for local transportation to the burner tip. As the brokering agent, the energy manager is responsible for timely and accurate nomination of natural gas and for reconciling nominated quantities with the quantities delivered and consumed. The reconciliation of natural gas quantities nominated with the quantities delivered and consumed is often a daily task and must be accomplished for each of the natural gas production, transportation, and delivery contracts. As with the full-service broker, if the nominated quantities differ from the delivered amounts, the institution may be required to purchase natural gas from the LDC at a premium price as in the case of under-nomination or pay for storage as in the case of overnomination. To avoid these situations, the energy manager must establish procedures for ensuring that accurate forecasting is used in the nomination process. The financial risks are high with this method, which makes it attractive only to large consumers, who can anticipate at least a 10 percent savings using this method over the use of a full-service broker. It is recommended that even large consumers of natural gas initially contract for natural gas management from a full-service broker and simulate the same process with in-house staff to identify areas of risk or vulnerability. This arrangement provides in-house staff training, which needs to be accomplished regardless of the final management process.
Fuel oil is available in several grades, including No. 1 (light distillate), No. 2 (distillate), No. 4 (light residual or heavy distillate), No. 5L (light residual, heavier than No. 4), No. 5H (heavy residual), and No. 6 (heavy residual, also known as “Bunker C”). Each of these fuel oils has a distinct fuel composition, ignition temperature, flash point, pour point, viscosity, specific gravity, and heating value. Preheating of No. 5L may be necessary for burning and handling in colder climates. Preheating of No. 5H is usually necessary for burning and handling. Preheating of No. 6 oil in the storage tank is required to enable pumping, and additional preheating at the burner is typically required to enable atomizing. Figure 1 lists the ranges of heating values; weights; sulfur levels; and pour, pump, and atomizing points of some fuel oils.
Figure 1. Heating Values; Weights; Sulfur Levels; and Pour, Pump, and Atomizing Points of Fuel Oils (lbm = pound-mass)
Low-sulfur and ultralow-sulfur residual oils are available in many areas to permit users to meet sulfur dioxide emission regulations. Low-sulfur fuel oils are produced (1) by refinery processes that remove sulfur from the oil, (2) by blending high-sulfur residual oils with low sulfur distillate oils, or (3) by a combination of these two methods.
Diesel oil is available as No. 1, No. 2, and No. 4 grades, and has the same property specifications as fuel oil except that it can be specified by a cetane number, which is the measure of the ignition quality of the fuel. The cetane number requirements depend on engine design, size, speed, and load variations. Use of a diesel oil with a cetane number higher than that indicated for the specific engine is not recommended, as it does not greatly enhance engine performance and is typically more costly and difficult to obtain.
United States Regulatory Development
The Interstate Commerce Act and the EPAct are the two pieces of legislation used to regulate the rates and practices of oil pipeline companies engaged in interstate transportation. The 1970 Clean Air Act and its 1977 and 1990 amendments placed emissions restrictions limiting the sulfur content of the fuel oil used in most plants and prohibited the use of fuel oil in many urban areas except as a backup fuel or for testing.
Title V of the Clean Air Act, the New Source Performance Standards, and the New Source Review established state implementation plans for air permits and emission limits and performance standards for new sources (boilers or combustion units), which placed further restrictions on the installation of new boilers. In addition, in February 2013, the U.S. EPA issued its final rule for the NESHAP: Industrial, Commercial, and Institutional Boilers, also known as the Boiler MACT. The NESHAP emission limits and work practice requirements for new and existing small boilers rated at less than 10 million Btu (MMBtu)/hour that burn oil, biomass, and coal require them to be tuned up every other year or every five years. Existing large oil-fired boilers (≥10 MMBtu/hr) are required to get a tune-up every other year, and the facility must receive a one-time energy assessment. New large oil-fired boilers are required to have an emission limit for particulate matter (PM) and a tune-up every other year or every five years. Limited-use oil-fired boilers have no emission limits.7
The selection of a fuel-oil grade for a specific application is usually based on fuel availability and economic factors, such as fuel cost, clean air requirements, preheating and handling costs, and equipment costs.
The fuel-oil contract usually specifies a minimum annual use for each type of fuel. Terms and conditions of the contract typically include indemnification clauses, transportation responsibilities, auditing procedures, and provisions for cancellation of the contract. The contract must include provisions to enable compliance with air pollution control requirements such as limitations on sulfur content, heating value content of the fuel, which is typically required on every fuel-oil invoice, as well as quantity purchased. Recordkeeping of the fuel type, quantity, heat value, sulfur content, and related parameters for each boiler, diesel generator, and/or facility for demonstrating Title V compliance is typically necessary, and submission of this information as part of the contract is mandatory in some cases. Lower sulfur content in the oil provides a secondary benefit of reducing overall corrosiveness in the flue gas. Finally, it may be desirable to minimize ash (noncombustible material) in the oil, which causes high wear on the burner pumps.
Federal and state/province/region laws regulate the construction, installation, and use of aboveground storage tanks (AST) and underground storage tanks (UST) used for the storage of petroleum products. The goal of these regulations is to prevent the potential contamination of drinking water supplies, soil, and other resources from the release or threatened release of petroleum products. The United States Code of Federal Regulations requires any tank greater than 1,320 gallons to have a spill prevention, control, and countermeasure (SPCC) plan. The SPCC Rule has specific requirements depending on the size and type (AST or UST) of storage. Federal regulations also require the following minimum standards:
- New tanks must be constructed of fiberglass-reinforced plastic, steel that has been cathodically protected by a suitable dielectric material or a field-installed cathodic protection system, a steel-fiberglass-reinforced plastic composite, or an equivalent approved construction system.
- Piping must be constructed of steel and cathodically protected.
- Spill and overfill prevention equipment must be installed.
- Leak detection must be provided on piping and tanks, or leak testing accomplished on a periodic basis.
Although seldom a problem, oxidation or microbial growth in large No. 2 fuel-oil storage facilities is occasionally encountered. Either of these might occur when fuel oil is stored for five or more years with little or no turnover in product. Oxidation and microbial growth over a long period of time can degrade the fuel oil and make it unsuitable for combustion, thereby requiring its removal and remediation. To prevent this, any fuel oil that is stored for extended periods of time with no movement of product should be tested at least annually and antioxidants or antimicrobial agents added as needed.
Solid fuels include coal, coke, waste products, wood, plant materials, and similar sources. Similar to gaseous fuels, the use of organic-sourced solids is typically considered a source of renewable energy. If these are co-fired with a fossil fuel such as coal, the percentage of the total energy input (Btu) derived from the organic-sourced material is the same percentage that counts as renewable. Waste products from industrial, agricultural, and municipal operations in the form of raw material or as refuse-derived fuel (RDF) are used in waste-to-energy facilities (WTE) primarily for the generation of electricity or for the cogeneration of electricity and steam.
RDF is obtained when the combustible material in municipal solid waste is separated from the noncombustible portion and packaged into a form that can be fired in a boiler. High-quality RDF that is free of grit, glass, metals, and other noncombustibles is sometimes used as a supplemental fuel in existing coal-fired boilers.
Source reduction and recycling efforts in some communities are adversely affecting the availability of high-quality mass burn solid waste or RDF. The uncertainty of long-term availability of combustible materials from the solid waste stream, combined with the inconsistency of quality, makes it difficult to assess the long-term impact of relying on solid waste or RDF as a primary fuel.
The demand for wood in the building construction and furniture fabrication industries, the value of wood as an environmental and aesthetic resource, and the comparatively high cost of wood compared with other fuels can make it a less financially attractive option for most energy generators as a primary fuel source. However, geographic location and local market conditions for wood can make it a less expensive fuel source than other types of fuels. Several energy generators have been able to negotiate with local paper mills, wood construction industries, municipalities, industrial or commercial facilities, and other generators of waste wood products to obtain wood chips at no cost other than transportation to their wood-burning facilities. In addition, fuels derived from biomass, including waste wood products, sustainably harvested wood, oat hulls, bagasse, switchgrass, and similar products, are classified as renewable energy sources, making them very attractive to institutions in their efforts to reduce greenhouse gas emissions and achieve sustainability goals.
Coke is the ash- and sulfur-containing carbon residue produced by heating coal in the absence of oxygen. It is smokeless when burned and is used primarily in blast furnaces.
Coal is generally classified into four major categories: anthracite, bituminous, subbituminous, and lignite. Anthracite is a clean, dense, hard coal that creates little dust in handling and burns freely once ignited. Bituminous coal encompasses many types of coal that generally ignite easily, burn freely, and are strong enough to permit screening to remove fines. When improperly fired, bituminous coal produces large quantities of soot and smoke, especially at low burning rates. Subbituminous coal ignites easily and is susceptible to spontaneous ignition when piled or stored. It burns freely, breaks up easily into small pieces, and generates little smoke and soot. Lignite has a low heating value, is most susceptible to spontaneous ignition, and tends to break up in the fuel bed, which results in burning pieces falling into the ash bed. It generates little smoke and soot when burned.
Assessments indicate that the original quantity of coal worldwide was 6.9 trillion short tons, of which only 2.5 percent has been exploited. It is projected that coal will last from a few hundred to more than 1,000 years, depending on technological advances and the rate of use. Sixty percent of the world’s coal deposits are in the United States, Russia, and China.
The heating values of coal are reported on an as-received, dry, dry and mineral matter-free, or moist and mineral matter-free basis, with the higher heating values for the various coals typically being used. Figure 2 lists the heating values and the nitrogen, sulfur, and ash content of the four major classes of coal on an as-received basis.
Figure 2. Heating Values and Nitrogen, Sulfur, and Ash Content of Coals
United States Regulatory Development
The passage of the Clean Water Act, the Clean Air Act of 1970, and its amendments in 1977 and 1990 resulted in emissions restrictions being placed on all boiler plants, most notably coal-fired facilities. These acts required most coal-fired plants to limit sulfur, nitrogen, and ash content in coal; to monitor particulate, sulfur dioxide, and/or nitric oxide emissions; and to limit emissions of these chemicals as well as volatile organic compounds and carbon monoxide from the plant. These limitations are typically based on boiler or facility size, types of fuels used, age of equipment, and location of the facility, and are set to not exceed a certain number of pounds per hour, tons per year, parts per million, or pounds per British thermal units per hour (Btu/hr) of input fuel. Some facilities were required to install enclosed coal handling systems, coal storage silos, and ash handling systems to protect against fugitive dust emissions and groundwater contamination. In some cases, especially in nonattainment areas, restrictions on emissions became so rigorous that some facilities had to be converted to fire natural gas as a primary fuel. The
Title V of the Clean Air Act, the New Source Performance Standards, and the New Source Review established state implementation plans for air permits and emission limits and performance standards for new sources (boilers or combustion units), which placed further restrictions on the installation of new boilers. In addition, in February 2013, the U.S. EPA issued its final rule for the NESHAP: Industrial, Commercial, and Institutional Boilers, also known as the Boiler MACT. The NESHAP emission limits and work practice requirements for new and existing small boilers rated at less than 10 MMBtu/hour that burn coal require them to be tuned up every other year or every five years. Existing large coal-fired boilers (≥10 MMBtu/hr) are required to meet emission limits for mercury (Hg) and carbon monoxide (CO); however, existing limited-use coal-fired boilers ≥10 MMBtu/hr have no emission limits, but are required to get a tune-up every five years. New large coal-fired boilers are required to meet emission limits for Hg, CO, and particulate matter (PM) with limited use boilers needing to get a tune-up every five years.8
The Boiler MACT will require significant investment for many coal-fired assets if they are to attain compliance with it. In addition, the Energy Information Administration as well as many other energy experts are forecasting that the cost of natural gas will remain low for the foreseeable future and even through 2040, as the natural gas shale plays continue to grow in meeting energy demand. As a result, many institutions, investor-owned utilities, and commercial and industrial facilities are retiring their coal-fired assets and converting to natural gas.
The selection of a coal type for a specific application is usually based on fuel availability and economic factors such as fuel cost, transportation cost, clean air requirements, storage needs, handling costs, and equipment costs. Coal management issues include ensuring an adequate supply of fuel, minimizing fuel procurement and transportation costs, and meeting or exceeding air pollution control limitations.
The energy manager can opt to purchase coal and transportation as one complete package or as separate contracts. The benefit of a single contract is that it establishes a single point of responsibility for both the fuel purchase quantity and delivery. However, this approach typically results in higher unit costs for the fuel and less flexible delivery schedules. Flexibility in delivery schedules is important for ensuring that fuel deliveries and quantities meet the daily fuel-burn requirements while maintaining an adequate inventory.
The use of separate contracts for fuel purchase and transportation results in a lower unit cost for the fuel and provides local control over delivery times and quantities. The separate transportation agreement also provides the energy manager with the flexibility to contract with a second coal supplier in the event of a contract default by the primary coal supplier. A default in a coal supplier contract can occur for a variety of reasons, including not providing specified quantities; not complying with limits on ash, sulfur, and nitrogen content; and providing coal that has excessive fines or low heating values or that is contaminated with debris. The transportation agreement is usually with a national railroad company and rarely goes into default. The disadvantage of separate contracts is that the energy manager becomes responsible for coordination of the two contracts and risks supply disruptions or monetary penalties known as “demurrage charges,” which are caused by not being able to process coal sitting in rail cars or trucks. Similar to the fuel-oil contract, the coal contract typically specifies minimum annual coal use and provides for indemnification, transportation responsibilities, auditing and cancellation procedures, and air pollution compliance requirements.
The award of the coal contract should be based on the energy content of the coal rather than on the cost per ton, as the heating value of coal can vary widely. The bidder typically supplies a cost per ton of coal, a cost per ton for freeze protection, and a heating value content for the coal, from which a total unit cost per MMBtu is calculated. The coal contract typically contains a penalty clause that specifies monetary penalties for supplying coal with a lower heating value or with higher ash or sulfur content than was bid for. In addition to the monetary penalties, the penalty clause must indicate that the purchaser reserves the right to reject any shipments that do not meet the specifications, at the coal vendor’s cost. This is especially important when the ash and sulfur content of the coal shipments exceeds the limitations imposed by air pollution control requirements.
The contract should assign to the coal supplier the responsibility for testing the coal for heating value content, ash and sulfur content, and percentage of fines, and should require the supplier to send the results to the purchaser prior to shipment. This should eliminate shipment of unsuitable coal to the plant, which is extremely important during periods of critical need. The purchaser may opt to contract with an independent testing agency for testing of coal samples as an added quality-control check. The coal supplier is federally liable for the accurate reporting of ash and sulfur content of the coal. In addition, the coal vendor typically pulls samples from a continuous flow process, which is more representative of average coal quality than samples analyzed by an outside testing agency, which are usually obtained from the top or bottom of the rail car.
The rail transportation agreement, whether included in the purchase contract or established as a separate contract, should contain terms and conditions that are similar to those in the coal purchase contract and should identify major rail lines and local switching requirements. The energy manager may want to arrange for backup transportation of coal by truck in the event that rail service is unavailable. A separate contract should be used for truck transportation. Truck transportation is often included as a unit bid item in the coal contract, and is typically priced at two or three times the cost that could be obtained through a separate contract.
On an equivalent heating value basis, delivered coal typically costs less than other thermal fuels. However, the capital investment in coal handling and storage equipment, pollution control equipment, and ash handling and storage equipment, as well as the operating and maintenance costs associated with coal-fired plants, are higher than for gas- and oil-fired plants. If adequate storage capacity is not provided for at the coal-fired plant, the institution is at risk of supply shortages and may be forced to use a more costly backup fuel for generating heat or electricity. Use of a more costly fuel can quickly undermine the capital and ongoing maintenance investments in the coal-fired facility.
To protect capital and maintenance investments and to ensure availability of fuel for critical facilities, the storage facilities should provide for at least a 30-day inventory of coal at the peak burn rate. A larger inventory is highly recommended. Several factors can quickly erode the coal inventory, including a contract default by the coal vendor, mine and transportation strikes, severe weather, low coal supplies at the mine, frozen coal that cannot be quickly unloaded, receipt of several shipments of unsuitable coal, and a variety of other factors. With the exception of strikes, most institutions have experienced some or all of these problems in the last few years.
To avoid coal fires, storage facilities must be carefully designed for the type and quantity of coal being stored. This is especially true for subbituminous or lignite coals, which are highly susceptible to spontaneous combustion. Some states require or recommend that a fire suppression system be installed in coal storage facilities.