and process monitors. If a CEM system is already installed for compliance monitoring through a permit, NSPS, or other requirement, additional monitoring is not required.
Acid Rain Program (40 CFR 75)
The EPA acid rain program was the most significant program for CEM system implementation and development since the promulgation of the NSPS requirements in the 1970s. The program was responsible for the installation of over 2000 CEM systems in the electrical utilities in a relatively short period of three years. As a result of the program, dilution extractive systems were popularized in the United States, flow monitors were applied widely, and CEM system data acquisition systems improved markedly. Also, CEM systems achieved respectability. Being necessary to support the structure of the acid rain program, CEM system operation and performance came under supervision by engineers who report to upper management levels.
The acid rain program was established through Title IV of the 1990 Clean Air Act and is codified in Parts 72‐75 of Title 40 of the Code of Federal Regulations (U.S. EPA 2020f). Parts 72–74 deal with the programmatic issues of allowance trading, whereas Part 75 addresses the continuous emission monitoring requirements that support the program. The acid rain program is a “trading program” where the trading commodity is the “allowance.” An allowance is a trading permit, corresponding to the right to emit one ton of pollutant such as SO2, NOx, or CO2 in any year. In the program, an affected facility must be in possession of the exact number of allowances corresponding to its annual emission of SO2 in tons per year. If a coal‐fired power plant emits 30 000 tons per year of SO2, it must have 30 000 allowances. If it has only 20 000 allowances, it must either reduce emissions by 10 000 tons during the year or it must purchase allowances to make up the difference. Allowances may be purchased, sold, banked, auctioned, or otherwise treated as negotiable securities.
The acid rain program differed from previous federal programs by applying to both existing and new electrical utilities greater than 25 MW capacity. In a trading program, a set number of allowances are initially issued to facilities affected by the program. To reduce emissions by 50%, only one‐half of the allowances necessary to cover annual emissions were provided by EPA. From SO2 emissions level of 17.5 million tons annual emissions, in 1980 for the electric utilities, only 8.9 million allowances were distributed. When fully implemented by 2010, SO2 emissions were expected to be approximately halved.
In contrast to “command and control” programs where certain control equipment or operating conditions are mandated, in trading programs a facility can choose how to comply with the rule. For example, a facility could add an SO2 scrubber to reduce emissions; it could shut down intermittently; it could burn lower sulfur fuels, switch fuels, or buy allowances at auction, or could buy allowances from a company that had “overcontrolled” its emissions and had allowances to sell. This is illustrated in the example of Figure 2‐4. In the example, each plant emits 100 tons per year, but each plant is allocated only 50 allowances. To meet their allowance requirements, the plants adopt different strategies. Plant A decides to burn low‐sulfur coal and succeeds in reducing its emissions to 50 tons per year to meet the 50 allowances it was allocated. Plant B decides to install a wet scrubbing system and reduces its annual emissions by 70 tons down to 30 tons. It has overcontrolled its emissions, but now has 20 allowances available to sell. Plant C is an older plant and finds it too expensive to reduce its emissions by 50%. It decides to reduce them by only 30% down to 70 tons per year. To meet its allowance obligation at the end of the year, it then buys the 20 allowances available from Plant B.
The advantages of a trading program are that a source has choices instead of mandates and can change control strategies without notifying the agency. A trading program also changes the character of environmental management from spending money for compliance to possibly profiting by controlling its emissions more than it is required. Additionally, the similarity of an “allowance” to a “security” is understandable to corporate management and helps management to participate in a game with which it may be more familiar. Here, a strategy’s success or failure can be measured; and that measurement is made by CEM systems.
Figure 2‐4 Trading allowances.
Trading allowances requires a high degree of confidence in the negotiable instrument, the allowance. To calculate SO2 mass emission rates, the flue gas volumetric flow rate must also be known. This is shown in Equation 2‐1.
where
pmrs = pollutant mass rate (kilograms per hour, tons per year)
cs = pollutant concentration (milligrams per cubic meter, pounds per cubic foot)
Qs = volumetric flow rate (cubic meters per hour, cubic feet per hour)
s = subscript denoting “stack”
For coal‐fired plants, flow monitors are specified for monitoring the flue gas volumetric flow. For gas‐ and oil‐fired plants, the fuel flow in conjunction with an O2 or CO2 “diluent” monitor can be used instead, to calculate the flue (stack) gas volumetric flow (see Appendix A).
Under the acid rain program, NOx emissions were not traded, but instead regulated under lb/mmBtu emission limits. Emissions are calculated using F‐factor methods, where the emissions in lb/mmBtu are determined from Equation 2‐2:
where
E = emissions in units of lb/mmBtu (or ng/J)
cs = NOx concentration
Fc = carbon dioxide F factor
Here, a NOx monitor and diluent monitor measuring either CO2 or O2 are necessary to perform the calculation. F factors can be found in Table A‐2.
Since CEM systems are used to determine mass emission rates and, therefore, available allowances, it is essential that the CEM systems installed for this purpose meet high levels of accuracy and precision. Consequently, EPA established a new set of rules and performance specifications for CEM systems in 40 CFR 75, increasing the stringency of monitoring requirements from those originally promulgated in the New Source Performance Standards of 40 CFR 60 (U.S. EPA 2020g). As a result, CEM systems essentially became the “gold standard” by which the program operated. Because of the importance of the program and its potential costs, utility managers purchased new CEM systems, assigned engineers to oversee the monitoring programs, and provided financial and staff resources for their operation and maintenance. This led to a new generation of CEM systems and a new generation of CEM professionals. Close cooperation between utility professionals, regulators from the EPA Clean Air Markets Division (CAMD), and CEM system vendors contributed greatly to the overall success of the program (Schakenbach and Forte 2006).
Because of the more stringent monitoring requirements and incentives, Part 75 CEM systems