Unlike Wisconsin, Illinois’s and Indiana’s administrative rules limiting NOx emissions have not been approved by EPA as meeting CAA Section 182(f) NOx RACT requirements. Illinois has promulgated administrative rules limiting NOx emissions under Title 35 Part 217 of the Illinois Administrative Code. Overall, ch. NR 428, Wis. Adm. Code, establishes NOx emission limits based on emissions unit size and fuel type while the Illinois rules generally set NOx emission limits for broad categories of units (e.g., one emission limit for all solid fuel boilers above a certain maximum heat input). As a result, ch. NR 428, Wis. Adm. Code, sets many more emission limits relative to Illinois. For categories of emissions units that are directly comparable, the limits in ch. NR 428, Wis. Adm. Code, are similar to or slightly more stringent than the NOx emission limits in Illinois. Indiana has promulgated NOx emission limits under Title 326 Article 10 of the Indiana Administrative Code only for certain types of cement kilns and for a specific energy utility company. Michigan’s NOx emissions limits are incorporated under Michigan Administrative Rules 336.1801-336.1834 and are similar to the NOx rules promulgated by Illinois in that emission limits are set for broad emissions unit categories and are similar to or slightly less stringent than Wisconsin’s rules (when direct comparison is possible). Michigan, however, only became subject to CAA Section 182(f) NOx RACT requirements in November 2022, whereas Illinois, Indiana, and Wisconsin became subject to NOx RACT requirements in 2004.
Minnesota and Iowa do not have ozone nonattainment areas classified Moderate, and as such, are not required to implement Reasonable Further Progress and NOx RACT requirements under the Clean Air Act like those in ch. NR 428, Wis. Adm. Code. 9. Summary of Factual Data and Analytical Methodologies Used and How Any Related Findings Support the Regulatory Approach Chosen: The proposed rule changes address known implementation issues with ch. NR 428, Wis. Adm. Code, rule language promulgated in 2001 and 2007. With the exception of one revised emission limit which is being proposed because the existing limit is not achievable in practice, this rulemaking primarily clarifies and streamlines the rule chapter. The department is proposing to revise the NOX emission limit for gaseous fuel-fired, combined cycle combustion turbines with maximum design power output of 25 MWe or greater under s. NR 428.04(2)(g)1.d., Wis. Adm. Code, because the current limit is not achievable in practice at all times of operation by combined cycle turbines in this category (e.g., during startup and shutdown). The proposed modification would change the NOX emission limit from 3 ppmdv corrected to 15% oxygen on a 30-day rolling average basis to 9 ppmdv, corrected to 15% oxygen on a 30-day rolling average basis. This change would align the NOx emission limit under s. NR 428.04(2)(g)1.d., Wis. Adm. Code, which was promulgated in 2001, with the NOx emission limit incorporated in 2007 under s. NR 428.22(1)(h)1., Wis. Adm. Code, and approved by EPA as RACT, for the same type of unit. The technical basis for the NOx RACT limits set in subchapter IV of ch. NR 428, Wis. Adm. Code, were described in detail in Attachment A of the green sheet adoption package for Board Order AM-17-05 (https://p.widencdn.net/zplhxb/04-07-3A1). The NOx RACT limits promulgated under Board Order AM-17-05/Clearinghouse Rule 07-016 were based on the department’s review of available control technologies and their cost-effectiveness in dollars per ton of controlled NOx. The department’s evaluation followed the methods established in EPA’s Alternative Control Technology documents for NOx source categories (https://www3.epa.gov/airquality/ctg_act/). The NOx emissions limits under s. NR 428.04, Wis. Adm. Code, were promulgated in 2001. At that time, state and federal regulations set emissions limits under the assumption that emissions during periods of startup and shutdown would be excluded. After a court decision found this practice to be inconsistent with the CAA (Sierra Club v. Johnson, 551 F.3d 1019 (D.C. Cir. 2008)), regulators began specifying that emission limits apply at all times of operation. The department is proposing to change the emission limit under s. NR 428.04(2)(g)1.d., Wis. Adm. Code, from 3 ppmdv to 9 ppmdv at 15% oxygen for combined cycle combustion turbines with maximum design power output of 25 MWe or greater because it has found that the 3 ppmdv limit is not achievable in practice at all times of operation (e.g., during periods of startup and shutdown). Because the proposed emission limit is reflective of current operations, the proposed rule change is not expected to result in an increase in actual emissions. 10. Analysis and Supporting Documents Used to Determine the Effect on Small Business or in Preparation of an Economic Impact Report: The only proposed change which may economically impact businesses is the incorporation of s. NR 428.08(2)(g), Wis. Adm. Code. The proposed language clarifies monitoring requirements for kilns, furnaces, asphalt plants, process heating units, engines, and other units. Currently there are no monitoring requirements explicitly defined for these types of units under s. NR 428.08(2), Wis. Adm. Code, leading some to potentially conclude that either no compliance methods are required for these units or that continuous emissions monitoring systems (CEMS) are the only approvable compliance method for these units. This is an oversight from previous rulemakings. The proposed changes will improve clarity for businesses by ensuring that applicable monitoring requirements are clearly defined. Additionally, the proposed changes may reduce emissions of NOx to the environment by ensuring the department is able to enforce NOx emission limits by way of requiring emissions monitoring at all applicable units. The proposed remedy under s. NR 428.08(2)(g), Wis. Adm. Code, offers facilities the flexibility to either operate a CEMS or meet specific operational and performance testing requirements. The department estimates that the potential annual cost of the rulemaking is $109,200 based on assumptions made as part of its analysis. The department’s analysis is described below. The department estimates that 21 units may be subject to s. NR 428.08(2)(g), Wis. Adm. Code. The number of potentially affected units was determined by conducting a search of facilities with kilns, furnaces, asphalt plants, process heating units, or engine units and whose permits reference the sections of ch. NR 428, Wis. Adm. Code, that could make them subject to s. NR 428.08(2)(g), Wis. Adm. Code (i.e., ss. NR 428.04, 428.05, and 428.20, Wis. Adm. Code). Based on cost estimates gathered from CEMS manufacturers, initial costs for the purchase of a NOx CEMS, installation, and training are $53,500 to $150,000, depending on the system and facility, or $101,750 on average. Annualized costs to maintain a NOx CEMS are approximately $7,500 to $15,000 ($11,250 on average). The total annualized cost for the 21 potentially affected emissions units to comply with s. NR 428.08(2)(g), Wis. Adm. Code, over a 10-year period by operating a CEMS is $449,925. Because CEMS are relatively expensive to operate and maintain, the department’s proposed rule language also provides a more economical alternative to operating a CEMS in order to meet the requirements of s. NR 428.08(2)(g), Wis. Adm. Code. Instead of operating a CEMS to comply with s. NR 428.08(2)(g), Wis. Adm. Code, facilities are given the flexibility to alternatively meet specific operational and performance testing requirements. The latter would require sources to meet a testing requirement every two years. The department estimates that the annualized cost of the biennial performance tests is $3,500 to $5,700, or $4,600 on average, for each affected emissions unit based on cost information gathered from companies that offer stack testing services. A small percentage of the identified 21 emissions units may have an initial one-time cost if the unit needs to be modified to allow for tests to be conducted. The cost of modification is expected to vary widely depending on unit material type (e.g., if the unit is designed to withstand extreme temperatures), unit location (e.g., if scaffolding or a lift is required), and mechanical modification (e.g., installation of sampling ports). The department estimates this potential one-time modification expense could be $2,000 to $10,000 ($6,000 average), and notes that outliers could exist. To be conservative, the department assumed all 21 units would have a $6,000 one-time modification cost to accommodate stack testing. The department expects that in reality, only a few emissions units may incur an initial modification cost. The total annualized cost, including the potential initial modification costs and biennial performance test costs, over a 10-year period to comply with the operational and performance testing option in s. NR 428.08(2)(g), Wis. Adm. Code, is $109,200. In estimating the cost associated with this revision, the department assumes a facility would opt for the less expensive performance testing approach to meet the proposed s. NR 428.08(2)(g), Wis. Adm. Code, requirements because the testing approach is approximately a quarter of the cost of operating a CEMS. The department also notes that the $109,200 is likely overestimated due to four factors. First, the number of affected emissions units is likely overestimated because some of the 21 identified emissions units may not be subject to the compliance requirements, based on the rule’s emissions unit capacity thresholds. Second, the department expects that some sources would only be required to conduct tests every four years, instead of the standard two-year testing schedule, because some emissions units will meet the exception under s. NR 428.08(3)(a)1.b., Wis. Adm. Code. The department is not able to estimate how many units may be eligible for this exception as it is dependent on future emissions tests. Third, the department’s analysis assumes none of the 21 emissions units are currently operating a CEMS, which could also be used to comply with s. NR 428.08(2)(g), Wis. Adm. Code. Fourth, some facilities may request and receive approval to use an alternative monitoring approach. The department does not expect any other changes proposed as part of this rulemaking to have an economic impact on businesses. While the creation of additional exemption criteria in s. NR 428.21(3)(d), Wis. Adm. Code, is necessary to ensure NOx RACT requirements are appropriately applied, the department is not aware of any facility currently exempt, that would no longer be exempt after finalization of this proposed change. Additionally, the proposed NOx emission limit revision under s. NR 428.04(2)(g)1.d., Wis. Adm. Code, will not result in an economic impact because the revised limit is equivalent to the NOx RACT emission limit under s. NR 428.22(1)(h)1., Wis. Adm. Code, for the same type of unit. 11. Effect on Small Business (initial regulatory flexibility analysis): Chapter NR 428, Wis. Adm. Code, primarily applies to facilities with high NOx emissions, and those facilities in Wisconsin have tended to not meet the definition of small business. The proposed revisions are intended to clarify existing requirements and to ensure clear and consistent implementation of ch. NR 428, Wis. Adm. Code. The proposed changes to ch. NR 428, Wis. Adm. Code, will not result in any existing facility, small business or otherwise, becoming newly subject to NOx emissions regulations upon promulgation of this rule. 12. Agency Contact Person: Olivia Salmon, Department of Natural Resources, P.O. Box 7921, Madison, WI 53707-7921; Olivia.Salmon@wisconsin.gov; (608) 630-5264 13. Place where comments are to be submitted and deadline for submission:
A public comment period occurred from May 1 through June 7, 2023, and a public hearing was held on May 31, 2023.
RULE TEXT
Section 1 NR 400.03 (4) (mf) is created to read:
NR 400.03 (4) (mf) “SIP” – state implementation plan
Section 2 NR 428.02 (7i), (7p), (7u) and (7w) are created to read:
NR 428.02 (7i) "Primary fuel" means the fuel types that provide the greatest amount of heat input, in terms of mmBtu, to a combustion unit. A combustion unit may have more than one primary fuel.
(7p) “Secondary fuel” means any fuel that is not a primary fuel.
(7u) “Simple cycle stationary combustion turbine” means any stationary combustion turbine that does not recover heat from the stationary combustion turbine exhaust gases.
(7w) (a) “Supply interruption” or “curtailment” means a period of time during which the supply of primary fuel to an emissions unit is reduced for reasons beyond the control of the facility.
(b) “Supply interruption” or “curtailment” may not result from an increase in the cost or unit price of the primary fuel.
Section 3 NR 428.04 (2) (g) 1. d. is amended to read:
NR 428.04 (2) (g) 1. d. 3 9 parts per million dry volume (ppmdv), corrected to 15% 15 percent oxygen, on a 30-day rolling average basis for a combined cycle combustion turbine with a maximum design power output of 25 MWe or greater.
Section 4 NR 428.04 (2) (i) and (4) (c) are created to read:
NR 428.04 (2) (i) Emissions units using secondary fuel. An emissions unit that is capable of firing secondary fuel is not subject to the requirements under this subsection when utilizing only a secondary fuel if any of the following apply:
1. The emissions unit heat input capacity or maximum design power output while utilizing the secondary fuel is less than the applicability thresholds under this subsection.
2. The emissions unit burns the secondary fuel only during any of the following periods:
a. Supply interruption or curtailment of primary fuel. The secondary fuel usage under this paragraph may not exceed 500 hours within a 12 consecutive month time period unless the owner or operator obtains a fuel variance under s. NR 436.06. b. Periodic testing, maintenance, or operator training of the secondary fuel when the periodic testing, maintenance, or operator training does not exceed a combined total of 48 hours during any calendar year.
3. The secondary fuel constitutes less than 1 percent on an energy equivalent basis of the emissions unit’s fuel consumption within the most recent 12 consecutive month time period.
(4) (c) The owner or operator claiming exemption from the requirements under sub. (2) pursuant to sub. (2) (i) shall keep a record of all of the following:
1. Each occurrence when a secondary fuel was burned in accordance with the provisions under sub. (2) (i).
2. The reason for each occurrence when a secondary fuel was burned in accordance with the provisions under sub. (2) (i).
3. The monthly and yearly total hours for each occurrence when a secondary fuel was burned in accordance with the provisions under sub. (2) (i).
4. Other relevant information as required by the department.
Section 5 NR 428.05 (2) (b) is amended to read:
NR 428.05 (2) (b) Except as provided in under par. (a)or, (c), or (f) the following categories of NOx emissions units listed in under this subsection shall complete a combustion optimization to minimize NOx emissions in accordance with s. NR 439.096 by December 31, 2002.: Section 6 NR 428.05 (2) (f), (3) (f) and (5) (c) are created to read:
NR 428.05 (2) (f) An emissions unit that is capable of firing secondary fuel is not subject to the requirements under this subsection when utilizing only a secondary fuel if any of the following apply:
1. The emissions unit heat input capacity or maximum design power output while utilizing the secondary fuel is less than the applicability thresholds under this subsection.
2. The emissions unit burns the secondary fuel only during any of the following periods:
a. Supply interruption or curtailment of primary fuel. The secondary fuel usage under this paragraph may not exceed 500 hours within a 12 consecutive month time period unless the owner or operator obtains a fuel variance under s. NR 436.06. b. Periodic testing, maintenance, or operator training of the secondary fuel when the periodic testing, maintenance, or operator training does not exceed a combined total of 48 hours during any calendar year.
3. The secondary fuel constitutes less than 1 percent on an energy equivalent basis of the emissions unit’s fuel consumption within the most recent 12 consecutive month time period.
(3) (f) Emissions units using secondary fuel. An emissions unit that is capable of firing secondary fuel is not subject to the requirements under this subsection when utilizing only a secondary fuel if any of the following apply:
1. The emissions unit heat input capacity or maximum design power output while utilizing the secondary fuel is less than the applicability thresholds under this subsection.
2. The emissions unit burns the secondary fuel only during any of the following periods:
a. Supply interruption or curtailment of primary fuel. The secondary fuel usage under this paragraph may not exceed 500 hours within a 12 consecutive month time period unless the owner or operator obtains a fuel variance under s. NR 436.06. b. Periodic testing, maintenance, or operator training of the secondary fuel when the periodic testing, maintenance, or operator training does not exceed a combined total of 48 hours during any calendar year.
3. The secondary fuel constitutes less than 1 percent on an energy equivalent basis of the emissions unit’s fuel consumption within the most recent 12 consecutive month time period.
(5) (c) The owner or operator claiming exemption to the requirements under subs. (2) and (3) pursuant to subs. (2) (f) and (3) (f) shall keep a record of all of the following:
1. Each occurrence when the fuel denoted under subs. (2) (f) and (3) (f) was burned.
2. The reason for each occurrence when fuel denoted under subs. (2) (f) and (3) (f) was burned.
3. The monthly and yearly total hours of operation for each fuel used as specified under subs. (2) (f) and (3) (f).
4. Other relevant information as required by the department.
Section 7 NR 428.055 is created to read:
NR 428.055 Alternatives.
