Emissions

It’s time to become EPA’s good neighbor

It’s time to become EPA’s good neighbor
(Source: Flickr.)

By Robynn Andracsek, PE, Providence Engineering and Environmental Group LLC contributing editor, and Tim Girard, Affiliated Engineers, Inc.

The Environmental Protection Agency (EPA) has spoken: the Good Neighbor Plan was finalized on March 15, 2023. This rule continues EPA’s Cross-State Air Pollution Rule (CSAPR) for the 2015 ozone National Ambient Air Quality Standards (NAAQS) and requires initial reductions from Electric Generation Units (EGUs) beginning in the 2023 ozone season (May 1-September 30). The rule pulls in other industries, such as steel, glass, and paper production, which we won’t discuss here. Requirements vary in the 23 states affected – see Figure 1.

Figure 1. States Covered Under the Power Plants and Other Industries Portions of the Final Good Neighbor Plan

The rule reduces the number of ozone season allowances, which in turn reduces emissions, using a phased-in approach. The operator of each emission unit subject to the rule must hold sufficient allowances to cover their ozone season nitrogen oxide (NOx) emissions.

2023

  • EPA assumes that any EGU with an existing, post-combustion control (selective catalytic reduction [SCR] or selective non-catalytic reduction [SNCR]) will operate that device fully. Therefore, allowances are reduced by the amount of extra control achieved through optimization of existing post-combustion controls.
  • Assurance level exceedance provisions: When total emissions from all covered state sources exceed a state’s ozone season emissions budget by more than 21 percent (%) (this threshold can vary), all units with post-combustion controls operating at least 10 percent of the ozone season hours will be subject to a unit-specific secondary emissions limit. When this exceedance occurs, NOx emissions are prohibited when they exceed by more than 50 tons (per ozone season), an emission rate of 0.10 pound per million British thermal units (lb/MMBtu), or 125 % of the unit’s lowest average emission rate from any previous control period. The unit will be subject to potential administrative or judicial action and subject to penalties under the Clean Air Act’s enforcement authorities. In other words, in certain circumstances the 51st ton emitted during the summer is subject to a 0.10 lb NOx/MMBtu limit, regardless of existing permits.

2024

  • EPA reduces allowances by an amount that assumes implementation of state-of-the-art combustion controls [low-NOx burners (LNB), over-fire air (OFA), etc. specific to each boiler] on all EGUs.
  • Every coal-fired steam EGU greater than 100 megawatts with an existing SCR in a covered state is limited to 0.14 lb NOx/MMBtu (backstop daily emission rate). Exceeding this daily limit, by more than 50 tons, can result in surrendering 3 allowances for every extra ton emitted.

2026 – EPA reduces allowances by an amount that assumes:

  • Implementation of new SNCR on all EGUs and SCR on half of the EGUs currently without SCR/SNCR, and
  • Implementation of new controls on all non-EGUs(2-year extension available as outlined in the regulation).
  • During the second ozone season after an SCR is installed (i.e. starting 2026 if SCR was installed in 2024), a unit-specific 0.14 lb NOx/MMBtu backstop emission rate applies for coal-fired EGUs. Exceeding this daily limit by more than 50 tons can result in surrendering 3 allowances for every extra ton emitted.

2027 and beyond

  • EPA reduces allowances by an amount that assumes reductions based upon the fleetwide implementation of SCR (allowing for addition of alternative control methodologies or the purchase of allowances to meet the statewide mandate).
  • In 2030, a unit-specific 0.14 lb NOx/MMBtu backstop emission rate applies for all coal-fired EGUs, except for circulating fluidized bed (CFB) units. Exceeding this daily limit by more than 50 tons can result in surrendering 3 allowances for every extra ton emitted.

Beware of the Prevention of Significant Deterioration (PSD) permitting implications. EPA states “The actual compliance requirement that the EGUs must meet is simply to hold sufficient allowances to cover emissions during a given control period, not to undertake any specific compliance strategy…Those costs could, in turn, result in a reduction in electricity generation from higher-emitting sources and an increase in electricity generation from lower-emitting or zero-emitting generators, but that kind of generation shifting (not mandated but occurring as an economic choice by the regulated sources) is consistent, and in no way interferes with, the existing security-constrained economic dispatch protocols of the modern electrical grid.” Many previous PSD lookback enforcement cases originated from maintenance projects that occurred prior to an increase in capacity factor. Defending causality becomes the responsibility of the EGU.

What should you do?

  1. Conduct a PSD netting analysis before the capacity factor increases to provide insurance against possible lookbacks.
  2. If you currently have SCR or SNCR, review the system design basis or operating assumptions to determine if you are achieving the lowest emissions possible. Reagent delivery system balancing, injection operating parameter adjustment or catalyst management programs may require updating to reflect the latest unit operating scenario or industry practice.
  3. If you do not have NOx control (LNB, OFA, SCR, SNCR), determine if this rule requires you to install it and get cost estimates now.
  4. Talk to your compliance specialist or consultant about your unit’s prior emissions reporting and historical heat input in comparison with the unit specific allocations as identified by the EPA. In some cases, states may opt to modify the allocations as allowed by the rule.
  5. Work with your engineering staff, qualified air quality control system engineer and/or equipment supplier to determine the options available to meet the future allocation reductions by adjusting existing operations, adding/modifying control equipment, and/or reviewing generation shifting or unit retirement.

About the Authors:

Robynn Andracsek, PE, is a Senior Air Quality Engineer at Providence Engineering and Environmental Group LLC with 26 years of experience in air permitting for utilities and district energy facilities.  Providence is an employee-owned, multidisciplinary engineering and environmental consulting firm. Our work has taken us across the United States and beyond in support of our governmental and industrial clients’ goals and challenges all the while holding an unwavering dedication to our founding principles – to take care of our clients, make a little money, and have fun while doing it. Her email address is [email protected].

Tim Girard is a Project Manager at Affiliated Engineers, Inc. with 24 years of experience in air quality equipment assessment, engineering and construction projects for industrial and electrical generation facilities.  Affiliated is a multidisciplinary engineering and consulting firm with 19 offices in the United States.  Our mission drives us to find unique solutions to solve our clients’ challenges and our dedicated team of engineering professionals use industry knowledge, innovative technology and practical solutions to complete complex projects. His email address is [email protected].

Tags