Robynn Andracsek, P.E., Burns & McDonnell and Contributing Editor
Every month seems to bring a new, yet familiar, headline: “EPA levies huge fine against utility for Clean Air Act violations.” The most prevalent charge is modifying coal-fired boilers without receiving a New Source Review (NSR) permit and applying best available control technology (BACT). This is the so-called “routine maintenance” reinterpretation of the Clean Air Act.1
EPA’s power plant enforcement effort has systematically targeted electric utilities with the goal of “bringing the power plant industry into full compliance with the NSR” and Prevention of Significant Deterioration (PSD) requirements contained within the Clean Air Act.
No grandfathered coal-fired boiler can survive a PSD look-back. Twenty years ago, how did a plant manager justify a capital expenditure? By saying that “this modification will decrease downtime, regain lost capacity and extend the life of the boiler.” What words today are red flags to EPA that an actionthought at the time to be routine maintenanceis no longer considered “routine”? Decrease downtime, regain lost capacity and extend the life of the boiler; the very same words historically used to justify a capital expenditure.
The enforcement initiative against utilities began in 1999. Let’s check the score after almost a full decade of action. (See Table 1.)
All of these decrees, except for Alcoa2, also require the surrender of SO2 and/or NOX allowances. EPA is a big advocate of cap and trade regulations to reduce emissions. These programs, such as Acid Rain and Clean Air Interstate Rule (CAIR), assign a monetary value to each ton of emissions. By capping the amount of tons allowed, EPA can control the total amount of emissions of each pollutant. EPA then lowers the total amount over time to reduce national emissions. Each facility subject to cap-and-trade legislation must hold or purchase allowances to account for each ton of their actual emissions. Facilities that reduce their emissions can sell their excess emissions to other companies that are short on allowances. With allowances priced around $700 a ton, the surrender of allowances can add millions of dollars to the true cost of each settlement.
A separate enforcement action against East Kentucky Power Cooperative specifically addressed only Acid Rain compliance, at a cost of more than $11.4 million in penalties, plus the cost of surrendered allowances.
The requirement to retrofit control devices comes with an emission rate to be met.
For NOX, installation of selective catalytic reduction (SCR) to a level of 0.01 lb/mmBtu is the most common requirement (imposed in the actions involving Mirant, AEP, Alabama Power and Ohio Edison, among others). System-wide requirements can also be mandated (for example, 0.15 lb/mmBtu across Santee Cooper and Mirant). Some retrofits require low NOX burners (Nevada Power, Mirant) or over-fire air (Minnkota Power).
For SO2, installation of flue gas desulfurization (FGD) to a level of 95 percent and/or 0.1 lb/mmBtu is the most common requirement. In some cases, wet FGD is specified (Minnkota Power). In others, the choice of FGD is left open (as at East Kentucky Power Cooperative, which has yet to make its decision). However, given a requirement to meet a 95 percent reduction, the choice of FGD is largely determined to be wet instead of dry. System-wide requirements are also given in some cases (again, Santee Cooper).
Requirements to control particulate (PM10) are usually installation of a new electrostatic precipitator (ESP) or baghouses with a front-half (filterable) particulate rate of 0.03 lb/mmBtu and the installation of a PM continuous emissions monitor system (CEMS), as is the case for AEP and SIGECO. This requirement matches the New Source Performance Standard. The limitation might range down to 0.015 lb/mmBtu if testing shows that a lower rate is achievable (as was required for Alabama Power) or if a dry FGD is required for SO2 in lieu of a wet FGD (Minnkota Power). The agreements do not address back-half (condensable) particulate since it is not controllable.
From reviewing the penalties in Table 1 (see page 8) and other cases, a trend in the severity of the penalties appears and is shown in Table 2. Facilities considered “major” for federal programs such as Title V or PSD are liable for larger penalties. Likewise, facilities that have actual emissions over their limits are subject to larger fines as opposed to facilities whose compliance issues deal more with paperwork and records. However, Table 1 shows that the true price tag for these consent decrees is not in the civil penalty but in the cost of emission control device retrofits.
The uncontrolled, grandfathered coal-fired boiler is going the way of the dinosaur. Few units have not been hit by recent legislative efforts, such as best available retrofit technology (BART) for protection of visibility or CAIR for protection of the PM2.5 National Ambient Air Quality Standard and have escaped this NSR enforcement initiative. Any such unit can be considered an EPA target at risk for a future enforcement or regulatory action.
- See October 2007 column.
- Alcoa does not sell electricity to the distribution grid and is therefore not subject to Acid Rain or CAIR.
- All consent decrees referenced can be found at http://cfpub.epa.gov/compliance/cases/.
- The costs shown for controls are EPA estimates as described in the fact sheets and press releases for each consent decree.
- Nevada Power’s consent decree is the only one discussed here that covers natural gas-fired turbines instead of coal-fired boilers.
- $4.9 million in purchased and retired SO2 allowances.