January 18, 2021

Volume XI, Number 18


January 15, 2021

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EPA Issues Revised Emission Factors for Flares and Other Refinery Process Units

On April 20, 2015, EPA issued new and revised emission factors for flares and certain other refinery process units. The final action addressed: (1) VOC and CO emission factors for flares; (2) emission factors for NOX, total hydrocarbons (THC) and CO for sulfur recovery units; (3) a THC emission factor for catalytic reforming units; (4) a NOX emission factor for hydrogen plants; and (5) a hydrogen cyanide emission factor for fluid catalytic cracking units. Although EPA had proposed a revised NOX emission factor for flares, the agency declined to adopt the revised factor due to concerns about the quality of the supporting data. EPA updated Sections 5.1, 8.13, and 13.5 of AP-42, which is EPA’s primary compilation of emission factors. The agency also updated the Refinery Emissions Estimation Protocol that was used for the 2011 Refinery Information Collection Request.

EPA was acting in part to meet deadlines set by the consent decree in Air Alliance Houston, et al. v. McCarthy, No. 1:13-cv-00621-KBJ (D.D.C.). The lawsuit was filed in 2013 by Air Alliance Houston, Community In-Power and Development Association, Inc., Louisiana Bucket Brigade and Texas Environmental Justice Advocacy Services. The plaintiffs asserted that EPA had failed to perform nondiscretionary duties under Section 130 of the Clean Air Act. Section 130 of the Act requires the Administrator to review, and if necessary revise, emission factors used to estimate emissions of CO, VOC and NOX from sources of those pollutants and to establish emission factors for sources for which factors have not been established. Initial action under Section 130 was required within nine months after enactment of the 1990 amendments to the Clean Air Act and then every three years thereafter. The plaintiffs asked the court to set a date certain by which EPA had to complete a review of VOC emission factors for flares, liquid storage tanks and wastewater collection, treatment and storage systems at petroleum refineries and petrochemical plants and either revise the factors or make a final determination that revisions were not needed. EPA entered into a consent decree that established a schedule to complete the review and take final action.

A number of comments were received on the proposal. In response to criticism of the emission factors for flares, EPA pointed out that it relied on data from four flares at test facilities burning propylene, propane and natural gas. The data set included eight flares from refineries and one flare from a chemical plant, all burning typical flare vent gas. EPA believes the data set adequately captured the emission profile of both the refinery and chemical plant flares. EPA also pointed out that the original emissions factors were based on testing of only two flares, one steam-assisted and one air-assisted burning a single fuel (crude propylene).

Although EPA recognized that use of source-specific data is preferred when it is available, if a source needs to use an emission factor, the agency concluded that these emissions factors are representative of flares that fall into assigned source classification code categories of Industrial Processes, Petroleum Industry, Flares, and Process Gas. For industries with flares that do not fall into these categories, the user must determine whether the emission factor is representative of its flare or whether a more appropriate data source, such as data from a manufacturer, is available. For example, the oil and gas production sector may use the flare factors at their own discretion although EPA noted that many of the flares in the oil and gas sector vary from the types of flares from which data was collected to develop the factors. Oil and gas sector flares may not have to achieve the same level of control as the refining and chemical manufacturing sectors, so the emission profiles would not be equivalent.

EPA specifically noted that use of AP-42 emission factors (or the Refinery Protocol) is not required. However, AP-42 emission factors in particular are routinely used by sources in all sectors to estimate emissions. Although EPA stated that it does not recommend using emission factors for site-specific permit limits, permit applicants and permitting agencies often use AP-42 emission factors in the permitting process where unit-specific emission data is unavailable. Thus, adjustments to emission factors can indirectly affect source permitting, particularly future renewals or revisions.

© 2020 Dinsmore & Shohl LLP. All rights reserved.National Law Review, Volume V, Number 184



About this Author

Carolyn M. Brown, Dinsmore, environmental litigation Lawyer, Compliance Issues

Carolyn M. Brown’s understanding of environmental law makes her an invaluable resource to her clients. Her practice focuses on all areas of environmental law and includes counseling on regulatory requirements, permitting and transactional issues as well as environmental litigation. She spends a significant amount of time dealing with air permitting and compliance issues, water discharge permitting and compliance issues, as well as waste management and site remediation matters. 

(859) 425-1092