Continuous Emission Monitoring. James A. Jahnke

to the minimum specification of <20% in Part 60 and <10% in Part 75 (Mangus 1997). Some utility managers initially installed redundant systems, concerned that CEM system downtime would incur allowance penalties. However, by instituting effective quality assurance programs and maintenance practices, availabilities of >98% became typical, negating the need for redundant systems, which were mostly removed and kept as spares. The key to these successes was in management providing the support and resources necessary to assure that the CEM data would be sufficiently accurate to back the allowance trades, where financial considerations could be substantial.

Allowance prices were relatively stable for about 10 years, hovering from approximately $150 to $200 per allowance from 1994 to 2004. Due to changes in regulatory policies (beginning with the Clean Air Interstate Rule and ending with the Cross‐State Air Pollution Rule), the closure of older coal‐fired facilities, and the increased usage of natural gas (which contains little sulfur), the market has essentially crashed, where SO₂ allowances are readily available and are priced today at less than $1. However, the acid rain program led to a decrease in SO₂ emissions in the power sector from 15.7 million tons per year in 1990 to below 1 million tons in 2019 (Figure 2‐5).

      The acid rain program succeeded in meeting and exceeding its original program objectives sooner than mandated. However, factors other than trading also contributed to the program’s success (Schmalensee and Stavins 2013, 2015). The availability of low‐sulfur coal from Montana and Wyoming, the means to transport coal across the West and Midwest, and emergence of natural gas as an alternative fuel to coal led to SO₂ reductions that were not originally anticipated. Regardless of how the reductions were achieved, the constant factor in the program was highly accurate, reliable emissions data provided by the installed CEM systems. Accurate CEM data allowed the utilities to “keep score” with confidence, to weigh their operational and control options to cost‐effectively meet their regulatory obligations (Schreifels and Napolitano 2014).

The acid rain program serves as a template for other cap‐and‐trade programs, which is well documented by Schakenbach and Forte (2006). As viewed by Schakenbach et al., it is necessary that the monitoring and reporting procedures of the program be supported by effective quality control and quality assurance requirements. These requirements were at the time unique for a CEM regulatory program, incorporating elements such as the following:

Figure 2‐5 U.S. utility sector SO₂ emission reductions 1990–2019.

      1 An implemented/effective CEM QA/QC plan

      2 Incentives for good performance

      3 Penalties for poor performance

      4 Standardized electronic reporting formats and procedures

      5 Electronic audits and data quality checking software

      6 Targeted and random field performance and system audits

      7 Flexibility for special circumstances and technical issues

      8 Vigorous enforcement

      These elements are further detailed in the Part 75 Subpart A – General Provisions (U.S. EPA 2020f). The Part 75 CEM requirements, for installation and certification, are found in Part 75 Appendix A (U.S. EPA 2020g), and quality assurance and quality control requirements are given in Appendix B (U.S. EPA 2020h). Other documents such as EPA’s Plain English Guide to the Part 75 Rule (U.S. EPA 2009), the Part 75 Emission Monitoring Technical Q and A document (U.S. EPA 2013), and the Part 75 CEMS Field Audit Manual (U.S. EPA 2003) are helpful in clarifying details of the Part 75 requirements.

      The success of the acid rain program encouraged other cap‐and‐trade programs such as the EPA NO_x Budget Program, the Regional Clean Air Incentives Market (RECLAIM) in California (discontinued), and the Houston‐Galveston HROVC (Highly Reactive Organic Compound) cap‐and‐trade program. In Canada, the province of Ontario has instituted a trading program for SO₂ and NO_x (Government of Ontario 2020b).

      Trading programs have also been established for the control of greenhouse gases. In the United States, the Western Climate Initiative (WCI) in California (with Quebec as a partner) and the Regional Greenhouse Gas Initiative (RGGI) in the northeastern states. A U.S. Federal greenhouse gas trading program had been considered at one time, but no longer appears likely due to political polarization regarding climate change issues.

       Mandatory Greenhouse Gas Reporting Program (40 CFR 98)

      Forty‐two source categories, ranging from stationary fuel combustion sources to electronics manufacturing, emitting more than 25 000 metric tons of CO_2e per year are required as per 40 CFR 98 to report greenhouse gas emissions. Monitoring methods are specified in each of the 42 subparts; however, sources subject to Part 75 where CO₂ monitors are already installed must use CEM system data for reporting. Hazardous waste incinerators with installed CO₂ monitors must similarly report emissions using CEM system data. However, for most source categories, the reporting rule does not require the installation of continuous emission monitors, but allows the use of production data and emission factors instead.

Subpart C of Part 98 applies to stationary sources that combust fossil fuels. Here, a tier approach is taken, where each successive tier requires more measurements and the application of fewer emission factors, with the assumption that the higher the number of the tier, the higher the accuracy of the reported data. As an example of the use of emission factors, in Tiers 1 and 2, CO₂ emissions are calculated from the following equation:

(2‐3)

      where

       CO2 = annual CO2 mass emissions (metric tons) for a particular type of fuel

       Fuel = quantity of fuel combusted during the year (tons, scf, gal)

       HHVd = default (Tier 1) or measured (Tier 2) high heating value of fuel (mmBtu per quantity of fuel)

       EF = fuel‐specific default CO2 emission factor (kg CO2/mmBtu)

Tier 3 applies to sources larger than 250 mmBtu that have not been required to install a CEM system. In this tier, sources are required to monitor fuel use and the carbon content of the fuel instead of the fuel’s high heating value. CEM systems are used for Tier 4 reporting, where annual emissions are calculated as a pollutant mass rate times operating time. Methane and nitrous oxide emissions are reported using default emission factors for CH₄ and N₂O in Equation 2‐3. The CH₄ and N₂O calculate emissions data are combined with the CO₂ data to report greenhouse gas emissions as CO_2e, carbon dioxide equivalents.

      Greenhouse gas issues and reporting procedures are discussed in greater detail in Chapter 14.

       Office of Solid Waste CEM Requirements (40 CFR 266)

      Through the authority of the Resource Conservation and Recovery Act (RCRA), the EPA Office of Solid Waste requires CEM systems to be installed for incinerators designed to burn hazardous waste and for boilers and industrial