U.S. EPA Proposes Electronic Reporting Requirements for RICE

On June 26, 2023, the U.S. Environmental Protection Agency (U.S. EPA) proposed revisions to the following 40 CFR Part 60 [Standards of Performance for New Stationary Sources, also referred to as New Source Performance Standards (NSPS)] and 40 CFR Part 63 [National Emission Standards for Hazardous Air Pollutants (NESHAP)] regulations applicable to Reciprocating Internal Combustion Engines (RICE):

 

 

  • 40 CFR Part 60, Subpart IIII (NSPS for Stationary Compression Ignition Internal Combustion Engines)
  • 40 CFR Part 60, Subpart JJJJ (NSPS for Stationary Spark Ignition Internal Combustion Engines)
  • 40 CFR Part 63, Subpart ZZZZ (NESHAP for Stationary Reciprocating Internal Combustion Engines)

The proposed revisions would add electronic reporting requirements to several notifications and reports that are already required to be submitted by the respective regulations. Specifically, initial notifications of compliance, performance test reports, continuous monitoring system (CMS) performance evaluations, and periodic compliance reports will be required to be submitted through U.S. EPA’s Central Data Exchange (CDX) using the Compliance and Emissions Data Reporting Interface (CEDRI).

Initial compliance notifications required by 40 CFR Part 60, Subparts IIII and JJJJ, and Notification of Compliance Status (NOCS) documents required by 40 CFR Part 63, Subpart ZZZZ will be available for portable document format (PDF) upload in CEDRI. Results of performance tests or CMS performance evaluations will either be uploaded using U.S. EPA’s Electronic Reporting Tool (ERT), if the test/evaluation method is supported by the ERT, or submitted using the attachment module of the ERT. Report templates for periodic compliance reports (i.e., semiannual and annual reports) in CEDRI will be made available and eventually required. In conjunction with the new electronic reporting requirements, U.S. EPA also proposes to revise the rules to include exemptions for CDX system outages and force majeure events that prevent timely electronic submission.

The proposed rules also contain a few clarifications and changes that facilities should note. Table 4 to 40 CFR Part 60, Subpart IIII, which outlines the emissions standards for affected stationary diesel-fired fire pump engines, is being clarified to show that the carbon monoxide (CO) emissions standards that are currently listed on the row for earlier model years for each maximum engine power range, applies to newer model years as well. In the Federal Register notice, U.S. EPA states that the table was not intended to be displayed in this manner and is a mismatch between what was submitted by the U.S. EPA and what was shown in the Code of Federal Regulations (CFR).

That said, this clarification means that facilities that may have interpreted Table 4 differently may potentially have not addressed the CO emissions standard for model year 2011 and later fire pump engines in permitting actions. Compliance with the CO emissions standard will likely be demonstrated with the same Certificate of Conformity obtained by the manufacturer, but facilities with affected diesel-fired fire pumps should confirm they meet applicable emissions standards in the revised table.

In addition to correcting a consistency error in 40 CFR Part 63, Subpart ZZZZ related to the oil analysis program and Table 2d to Subpart ZZZZ, U.S. EPA is revising Subpart ZZZZ across the board to revise the frequency of all required air cleaner inspections, hose and belt inspections, spark plug inspections, oil changes, etc. that are required to be completed after a certain number of operating hours or “annually,” whichever comes first, to be completed “every 12 months.” U.S. EPA is making this proposed revision to prevent facilities from interpreting “annually” to mean once per calendar year, which could hypothetically result in an engine’s oil being changed once every 24 months (e.g., in January 2023 and December 2024). However, the proposed requirement of “every 12 months” may result in facilities completing two oil changes in a single calendar year (e.g., in January 2024 and December 2024) to accommodate maintenance schedules and avoid missing the deadline.

U.S. EPA is also proposing to remove a change made to the RICE rules in 2013 that allowed the operation of emergency engines for up to 50 hours per year to supply power for local system reliability. The 50-hour provision is proposed for removal as a result of petitions for review the U.S. EPA received on the provision. Comments are requested on whether the 50-hour provision should be removed or revised.

The electronic reporting requirements for all three rules would take effect 180 days after the final rule is published in the Federal Register or 1 year from the date the applicable report template is made available on CEDRI, whichever is later. The other clarifications and revisions for all three rules are proposed to take effect immediately after the final rule is published.

Comments on the proposed rule revisions and the draft CEDRI templates are due August 25, 2023. ALL4 is reviewing the proposed rule and its potential impacts on the wide range of industries that utilize RICE at their facilities. Feel free to reach out to Caleb Fetner at cfetner@all4inc.com with questions on how the proposed rule would impact you or for assistance submitting comments on the proposed rule.

ALL4’s Reciprocating Internal Combustion Engines (RICE) Training

Proposed Rule to Control Emissions from Flares in Ventura County, California.

Under California Assembly Bill 617 (AB 167), Air Districts in nonattainment for one or more air pollutants were required to adopt an expedited schedule by January 2021 for the implementation of Best Available Retrofit Control Technology (BARCT)1 by December 31, 2023.

The Ventura County Air Pollution Control District (VCAPCD) has proposed to adopt Rule 74.35 in their effort reduce emissions of oxides of nitrogen (NOX) and reactive organic compounds (ROC) from flares at facilities in Ventura County, as outlined in their BARCT schedule approved in December 2018.

As proposed, Rule 74.35 will apply to owners and operators of flares with a total rated heat input greater than or equal to one million British Thermal Units per hour (MMBtu/hr).

Emissions Limits:

VCAPCD has proposed the following emissions limits for flares installed, replaced, or relocated after December 31, 2023 in Table 1 of Proposed Rule 74.35:

Type of Flare Gas NOX Carbon Dioxide (CO) ROC
lb/MMBtu
Digester gas 0.025 0.06 0.038
Landfill gas 0.025 0.06 0.038
Produced gas2 0.018 0.01 0.008
Other flare gas 0.06 Not Applicable (N/A) N/A
ROC Liquid Handling
ROC liquid holding 0.25 0.37 N/A
ROC liquid transfer lb/1,000 gallons loaded
0.034 0.05 N/A

Produced Gas Throughput Limits:

Facilities who flare produced gas with estimated facility-wide annual emissions greater than or equal to five tons per year (ton/yr) of NOX or ROC or greater than or equal to 100 ton/yr of CO will be subject to the following throughput limits:

Flare Category Throughput Limit
Replaced Flares 110% of average annual throughput to that flare or flare station for the three calendar years immediately preceding the submittal of the flare application based on annual emissions reporting.
Replaced Flares where historical data is not available 45 million standard cubic feet per year (MMscf/yr)
New Flares 45 MMscf/yr

Flare Reduction Plans:

Facilities who operate a flare or flare station permitted before July 1, 2023 are required to calculate the annual percent capacity as follows3:

If the flare or flare station’s annual capacity exceeds the following thresholds, as provided in Table 2 of proposed Rule 74.35, for two consecutive years the Facility will be required to submit a Flare Reduction Plan with a Statement of Intent.

Type of Flare Gas Capacity Threshold
Digester Gas 70%
Landfill Gas 20%
Produced gas 20%
All other gas 5%

Facilities have three options when preparing a Flare Reduction Plan:

  1. Limit flare or flare station throughput:
  • Within 6 months4 of exceeding the capacity threshold for a second consecutive year, facilities must submit the following:
    • Alternative methods to reduce flare or flare station throughput below the capacity thresholds identified in Table 2; and
    • A timeline to implement the alternative method.
  • Within 13 months of exceeding the capacity threshold for a second consecutive year and annually until the annual percent capacity is reduced below the applicable threshold, facilities must submit a “Notification of Increments of Progress” including following:
    • Actions that have been implemented to reduce flaring throughput;
    • Actions that will be implemented to reduce flaring throughput; and
    • Changes to the original Notification of Intent.
  • Within 36 months of exceeding the capacity threshold for a second consecutive year, facilities must implement the Flare Reduction Plan.
  • Within 30 days of the end of the next year after the Flare Reduction Plan has been implemented, the flare capacity must be at or below the thresholds in Table 2.
  1. Replace or modify the flare to meet the emissions limits found in Table 1:
  • Within 6 months5 of exceeding the capacity threshold for a second consecutive year, facilities must submit an Authority to Construct (ATC) application for the replacement or modification of the flare.
  • Within 18 months of the issuance of the ATC, the flare installation or modification must be completed.
  1. Demonstrate that that the emissions limits found in Table 1 are met by an enclosed flare.

Notification Requirements:

Facilities who operate flares will be required to submit a “Notification of Flare Inventory and Capacity” within 30 days of the adoption of proposed Rule 74.35. The Notification of Flare Inventory and Capacity will include the following:

  • Permit number;
  • Date of installation;
  • Type of gas combusted;
  • Maximum rated capacity;
  • Description of fuel meter, if installed; and
  • Date of last source test, if applicable.

Maintenance Requirements:

Facilities must maintain flares in accordance with manufacture specifications. If manufacturing specifications are not available, facilities shall use:

  • American Petroleum Institute (API) Standard 537, Third Edition, March 2017; or
  • An alternative method approved by VCAPCD.

Labeling Requirements:

Flares installed, relocated, or modified after the date of adoption of proposed Rule 74.35 must be labeled with the model number and the rated heat input capacity.

Enclosure Requirements:

Flares installed, replaced, or relocated after December 31, 2023 must be enclosed.

Visible Emissions Restrictions:

Flares with a rated heat input capacity greater than or equal to one MMBtu/hr may not produce visible smoke on a continuous basis after December 31, 2023.

Recordkeeping Requirements:

Facilities who either exceed the annual capacity threshold for two consecutive calendar years or claim exemption from Rule 74.35 by limiting operations to no more than 200 hours per 12-month rolling period must install and operate a fuel meter for each fuel, excluding pilot gas, within 6 months of the adoption of proposed Rule 74.35. The fuel meter must be calibrated annually.

Testing Requirements:

Within 12 months of the adoption of proposed Rule 74.35, facilities must source test flares subject to the emissions standards found in Table 1 to determine NOX, ROC, and CO emissions rates. The source testing will then be conducted no less than every two years after the initial source test.

Exemptions:

VCACPD has provided the following exceptions from the requirements of proposed Rule 74.35:

  • Flares rated less than one MMBtu/hr;
  • Flares firing only propane and/or butane;
  • Flares located at landfills that collect less than 2,000 MMscf of landfill gas per year if:
    • The landfill has ceased accepting waste; or
    • The California Department of Resource Recycling and Recovery has classified the landfill as an inert waste disposal site or an asbestos contaminated waste.
  • Flares used for well testing, tank degassing, and pipeline degreasing;
  • Flares that fire regeneration gas.

Flares or flare stations that emit less than 30 pounds of NOX per month are not subject the requirements of Section B of proposed Rule 74.35 (i.e., emissions and produced gas throughput limits; flare reduction plans; notification, maintenance, labeling, and enclosure requirements; and visible emissions restrictions) if the following criteria are met:

  • The flare or flare station is subject to an enforceable emissions limit, and
  • The flare or flare station operates in compliance with the emissions limit.

Flares or flare stations that operate no more than 200 hours per year, excluding emergency flares are not subject the requirements of Section B of proposed Rule 74.35 if the following criteria are met:

  • The flare or flare station is subject to an operating hours or throughput limit, and
  • The flare or flare station operates in compliance with the operating hours or throughput limit.

What is Next?

Based on information presented by VCAPCD during recent working group meetings related to proposed Rule 74.35, it is expected that VCACPD will propose the Rule for final adoption during the July 11, 2023 Hearing Board Meeting.

ALL4 has extensive experience helping industrial facilities comply with regulations in the VCAPCD. With the expected adoption date of the Rule approaching, it is never too early to evaluate your compliance obligations and strategy. If you are interested in learning how this rule or other VCAPCD rules may affect your facility, please feel to reach out to me at 610.442.1131 or mmchale@all4inc.com.


1Under Section 40406 of the California Health and Safety Code BARCT is defined as “an emission limitation that is based on the maximum degree of reduction achievable, taking into account environmental, energy, and economic impacts by each class or category of source.”
2Under Subsection G.2 of proposed Rule 74.35, produced gas is defined as “organic compounds that are both gaseous at standard temperature and pressure and are associated with the production, gathering, separation or processing of crude oil.”
3“Capacity” as used in the equations above based on manufacturing design, if known, or the maximum permitted hourly capacity. For flare stations, it reflects the combined total capacity of all the flares in the flare station.
4Within 12 months for Publicly Owned Facilities.
5Ibid.

Data Quality Part 3: The Quantitative Components: Precision, Accuracy, and Completeness

 

We started this journey with the following thought: Defining data quality and implementing a data quality program furthers the goal that the data collected serve the intended purpose, i.e., informed decision making. Last time we discussed that precision is a measure of repeatability and that accuracy is a measure of correctness (agreement with the true value). The attached graphic shows precision and accuracy using targets and arrows (or darts, if you wish). Of course, when we make a measurement, we don’t know the true value. And, based on our discussions in the first article in this series, different data uses have different needs for precision and accuracy.

Let’s try a different analogy for this: weighing myself using the bathroom scale. I don’t know the “true” value (although maybe there is an “expected” value 😊). I can get precision by getting on and off the scale multiple times. But accuracy is harder. I could put a known weight on the scale, or I could climb on the scale, and then pick up the known weight. But I have to accept that accuracy for those two proxies (a known that’s not me or an addition to the unknown that is me), are reflective of the accuracy in the measurement of me.

So, how do we put numbers around precision and accuracy? It’s interesting, we tend to measure and put limits around inaccuracy and imprecision. Precision is generally reported as a deviation from a mean (standard deviation, percent difference, etc.), and the limits are maxima (e.g., relative standard deviation below 15%). Highly reproducible values will have very small deviations. Accuracy can be reported as the error, or deviation, from the expected or true value. Accuracy can also be measured as “recovery” (which messes with my observation above, about measuring inaccuracy). Very accurate results will have very small errors and recoveries very near 100%.

And how do we measure accuracy, especially if we don’t know the true value? Because when you measure an unknown you don’t know the true value. Ever. All measurements are an estimate of true value. As described above in my adventure with the bathroom scale, we must develop some proxy indicator of accuracy, some indicator of measurement performance. It must be the measurement of some known (or knowable) value. To make the logical jump from the proxy indicator to the actual measurement, there must be robust procedure and activity performance control. That’s just a fancy way to say, “we know how we do things and we do them that way each and every time”. We must know that our proxy was handled as closely as possible to how our unknown is handled.

Ok, so how do we measure precision? Simply put, we do repeated measurements. On and off the bathroom scale. (Maybe if I do that enough times, I’ll lose a couple pounds?)

Let’s switch from my bathroom scale analogy to analyzing an environmental sample. We still don’t know the “true” or “expected” value, but (big surprise!) we have a few tools that can be used to assess accuracy and/or precision. In the discussion below, “matrix” is the physical or chemical form of the sample and “analyte” is the target we’re looking for.

  • To determine accuracy in the sample analysis, some possible tools include:
    • Measurement of a known matrix that is as similar as possible to our unknown matrix. This might be a reference standard or an audit sample.
    • Measurement of a spike. That is, a known amount of analyte is added to a split of an unknown. The “true” or “expected” level is the measured unknown plus the known addition. This is the lab equivalent to me picking up a weight on the bathroom scale. Spikes can be prepared at any of the sample processing steps (sample collection, sample recovery, extraction, digestion, dilution, clean‑up, and analysis).
    • A spike can be prepared on a clean matrix, in which case there is only the spike.
    • Addition and measurement of a known amount of a similar analyte (surrogate) that is not present in the actual unknown sample. (This might be an isotopically-labeled compound.)
    • Measurement of calibration standard(s). This can be done once, or multiple times over an analytical sequence. It can be the actual calibration standard or a “second-source” standard used for confirmation.
  • To determine precision in the sample analysis, there are many tools to choose from:
    • Two (or more) samples collected simultaneously (field duplicate/replicate).
    • Two (or more) analyses of the sample itself (lab duplicate/replicate).
    • Splits at any of the processing steps (sample collection, sample recovery, extraction, digestion, dilution, clean‑up, and analysis).
    • Any of the spikes prepared in duplicate (and they frequently are).
    • If we do surrogate spikes, we can also pool the surrogate results/recoveries across multiple samples.

The last quantitative data quality objective is completeness. It’s also the easiest: How many samples did you plan to get, and how many did you actually get? For a very small program (e.g., our stack test), we target as few as 3 measurements (for each analyte), and our completeness objective is 100%.

It’s not really as hard as it sounds. Most (if not all) of the activities described above are in place in the methods and are implemented (and controlled and reported) by the analytical laboratory. As an end-user, or a definer of the data quality objective (DQO), you need to select the subset of quality activities which become the project-specific data quality objectives. And that is based on the end use of the resulting data (the underlying question).

Next Time: Comparability and Representativeness

Until then, feel free to contact either of us:

Links to other blogs from our Data Quality Series:

Colorado Air Quality Control Commission Adopts Environmental Justice Protections

On May 18, 2023, Colorado’s Department of Public Health and Environment (CDPHE) had its Air Quality Control Commission (Commission) adopt enhanced protections to implement the Colorado Environmental Justice Act (Act). The Act, signed into law by Colorado governor Jared Polis on July 2, 2021, is designed to reduce environmental health disparities in Disproportionately Impacted Communities (DIC) in the state. The new rules adopted by the Commission will become effective July 15, 2023.

 

The Act defines DIC as:

  • Census Block Groups with one of three demographic factors:
    • More than 40% of households are low-income (the median household income is less than or equal to 200% of the federal poverty guideline);
    • More than 40% of households identify as minority; or
    • More than 40% of households are housing cost-burdened (the household spends more than 30% of its income on housing).
  • Communities that a state agency has identified as having a history of environmental racism perpetuated through exclusionary laws, including redlining, anti-Hispanic, anti-Black, anti-indigenous, and anti-immigrant laws; and
  • Communities that a state agency has identified as having multiple factors (socioeconomic stressors, disproportionate environmental burdens, lack of public participation) that cumulatively contribute to persistent public health and environmental disparities. The Commission has defined a community that meets the criteria in this bullet point as a “Cumulatively Impacted Community”.

The Colorado Enviroscreen tool will be used to determine if a facility is in or adjacent to a DIC.

The new rules include enhanced monitoring and modeling requirements for new or modified air pollution sources of certain pollutants when emissions from the source will affect a DIC. These affected pollutants include volatile organic compounds, oxides of nitrogen, particulate matter that is 2.5 microns or smaller, and hazardous air pollutants (HAP) as identified by the Commission. The HAP that have been identified are:

  • Benzene
  • Toluene
  • Ethylbenzene
  • Xylene

The Act requires the Commission to revisit its determinations of affected pollutants at least once every three years. The enhanced modeling requirement for HAP will be the first time in Colorado that air pollution sources must evaluate HAP in modeling. The Act also allows the Division of Administration at CDPHE to reopen an air permit to add monitoring requirements for sources that affect a DIC.

The new rules also include measures beyond what is required by the Act. These additional measures include:

  • Environmental justice (EJ) summaries must be submitted with any construction or operating permit application for each census block group in which a source is located.
  • Reasonably Available Control Technology to further reduce air pollution emissions for any new source of affected pollutants in Cumulatively Impacted Communities.
  • Community air monitoring programs for new or modified sources of affected pollutants located in a DIC that go beyond the monitoring that the state and air pollution sources would otherwise conduct.
  • Enhanced monitoring requirements for air pollution sources located in Cumulatively Impacted Communities that includes source-specific monitoring plans approved by the Air Pollution Control Division.
  • Providing air pollution education in DIC.

The Commission will begin collecting permit processing fees under the new rules that will apply to permits for sources of pollutants that cause or contribute to significant health or environmental impacts in a DIC. The Commission will also begin collecting an annual air pollutant emission notice (APEN) fee for greenhouse gas (GHG) emissions.

APEN submissions will also begin including GHG emissions in the list of reported air pollutants in an effort to better track and ultimately reduce GHG emissions. The Act calls out recommended and required GHG emissions reductions from specific sectors for the Commission to implement into its rules. These sectors are:

  • Electric utilities (recommended),
  • Oil and gas exploration, production, processing, transmission, and storage operations (required),
  • Industrial and manufacturing facilities (required).

These new rules make Colorado the second U.S. state to make its air permitting process more protective for DIC. In 2020, New Jersey became the first US state to require mandatory permit denials if an EJ analysis determined a new facility would have a disproportionately negative impact on an overburdened community.

These new rules are published under the following regulatory sections:

  • 5 CCR 1001-5: REGULATION NUMBER 3 STATIONARY SOURCE PERMITTING AND AIR POLLUTANT EMISSION NOTICE REQUIREMENTS
  • 5 CCR 1001-8: REGULATION NUMBER 6 STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
  • 5 CCR 1001-10: REGULATION NUMBER 8 CONTROL OF HAZARDOUS AIR POLLUTANTS

The current versions of the Commission’s regulations are published as part of the Code of Colorado Regulations and can be accessed at the Colorado Secretary of State’s office. The upcoming versions of the Commissions regulations are provided as unofficial versions on the CDPHE’s website.If you have questions, need assistance planning for compliance with the Commission’s EJ Rules, or if you’d like to know what your state is doing around EJ, please contact Rich Hamel at rhamel@all4inc.com or (617) 721-5796. ALL4 also has additional resources available online, including coverage of EJ rules in other states.

OSHA Severe Violator Enforcement Program (SVEP)

The Occupational Safety and Health Administration (OSHA) established the Severe Violator Enforcement Program (SVEP) on June 18, 2010. The SVEP summarized enforcement policies and procedures for inspecting employers that demonstrated what OSHA defines as “indifference to their Occupational Safety Health (OSH) Act obligations” by either meeting the criteria of willful, repeated, or failure-to-abate violations.

On September 15, 2022, OSHA released Directive Number CPL 02-00-169 to update enforcement policies and procedures for the SVEP. Key takeaways include the following:

  • Expanded criteria for placement on the SVEP.
  • Established a timeframe for conducting a follow-up inspection.
  • Extended requirements and timeframes for removal from the SVEP.

The 2022 update strengthens the department’s enforcement capabilities and expands the program’s scope, which may impact industries not previously affected. This reflects the Biden-Harris administration’s desire to ensure employers maintain safe and healthy workplaces and be held accountable when they fail to do so.

SVEP Placement Criteria

For an employer to be placed in the SVEP, an inspection must result in an issue of failure-to-abate notice(s) for any of the following categories or in a willful, repeated violation(s) for the first two categories:

  1. Fatality/Catastrophe Criterion – incidents resulting in at least one fatality or three hospitalizations.
  2. Non-Fatality/Catastrophe Criterion – two or more incidents that involve high gravity serious violations.
  3. Egregious Criterion – all egregious enforcement actions.

Previously, the Non-Fatality/Catastrophe Criterion only included two or more willful or repeated violations or issued failure-to-abate notices for incidents related to employee exposure to specific high-emphasis hazards or three or more violations related to the potential release of highly hazardous chemicals. This has been expanded to include all OSHA standards and hazards.

Follow-Up Inspections

After inspection results in a notice or violation, the Review Commission must consider the case under Section 11(b) of the OSH Act. If the citation is affirmed, a final order will require the employer to be placed under the SVEP and address the violation. Within one to two years, a follow-up inspection must be conducted to assess if the violation(s) have been mitigated and whether there are similar or related hazard violations. Previously, there was no required inspection timeframe.

Removal from SVEP

After being placed in the SVEP, an employer becomes eligible for removal at least three years after they receive an acceptable abatement verification. This expands the time the employer must remain on the public list, as employers were previously eligible for SVEP removal three years after a final order affirmed a citation.

However, employers can now enter into an enhanced settlement agreement to reduce their time in the program to two years. This agreement would require establishing a safety and health management system that, at a minimum, meets the seven basic elements outlined in OSHA’s Recommended Practices for Safety and Health Programs.

How is this impacting facilities?

By introducing additional placement criteria, a stricter timeframe for follow-up inspections, and a longer process to be removed from the SVEP, employers are encouraged to take a more proactive approach to establishing and maintaining healthy and safe workplaces.

If you have questions about how this may affect your facility, please get in touch with your ALL4 Project Manager or email info@all4inc.com.

The United States of Stormwater

The United States Environmental Protection Agency (U.S. EPA) first published the Multi-Sector General Permit (MSGP) for Industrial Stormwater in 1995, with the most recent update becoming effective in September 2021. Authority has been granted by U.S. EPA to 47 of the 50 states to implement their own stormwater permitting programs, in lieu of strict adoption of the MSGP. Only Massachusetts, New Hampshire, New Mexico, and U.S. territories are covered by the MSGP.

Because we have 48 (47 states plus the MSGP) versions of a stormwater permitting program across the country, it’s a monumental task to keep up with the nuances of each one. This can be especially onerous for corporations that operate similar facilities across multiple states. Even for two identical sites that sit across state lines, the stormwater management requirements can vary quite a bit. Below are five common differences across these permits; do you know how your state stacks up?

1. Is my permit multi-sector or multiple sectors?

No, this isn’t a trick question. Many states follow U.S. EPA’s MSGP formatting and maintain one general industrial stormwater permit. These multi-sector permits contain all the state-wide, cross-industry requirements in the main sections of the permit and list the sector-specific requirements in appendices. Mississippi, New York, Pennsylvania, South Carolina, and Virginia all have permits with this layout.

Other states – including Alabama, New Jersey and North Carolina – maintain several general industrial stormwater permits. These permits will be applicable to a certain industry group, and all requirements in the permit are applicable to all sites claiming coverage under the industry-specific permit.

2. Do I have to post signage?

This may sound simplistic, but in the 2021 update of the U.S. EPA’s MSGP, a requirement was added to post notice of permit coverage at a publicly accessible location at or near your facility. Since this addition to the MSGP, states are slowly starting to incorporate the requirement into their permits, but not without some turmoil. Georgia proposed a signage requirement initially in a draft of their latest permit but removed it prior to the final issuance due to industry pushback. Texas is one of the few individual states to incorporate this requirement into their general permit so far.

3. Monitoring – wait, it’s not consistent?

Not even close! Not only do water quality standards vary from state to state, requirements for benchmark and indicator monitoring also vary greatly. Indicator monitoring, which is reported with no enforceable limits, for total suspended solids (TSS), chemical oxygen demand (COD), and pH were added for all sectors to the MSGP in 2021 – states are slowly starting to incorporate that requirement as well. Even sector-specific benchmark limits are not always consistent state to state. For example, the TSS benchmark monitoring concentration for the asphalt paving and roofing materials sector is 100 milligrams per liter (mg/L) in Georgia but is 150 mg/L just to the north in Tennessee.

4. Is there an annual reporting requirement?

Several states require permittees to submit an annual report that details exceedances, notes potential issues, and includes certification statements. States requiring these reports include, but are not limited to, California, Georgia, Minnesota, and Washington. Often, these reports will be submitted electronically via the state’s environmental reporting platform; it’s important to note that these reports are not the same as a discharge monitoring report (DMR).

5. Speaking of DMRs, am I required to submit them electronically?

More and more states are moving to using the U.S. EPA’s online DMR submittal platform, NetDMR. NetDMR is a program under the Central Data Exchange (CDX) and requires a CDX account to upload, review, and certify data. Again, this is in alignment with the 2021 MSGP. As general permits are renewed, most states are adding an electronic DMR requirement – Georgia, North Carolina, and Texas have recently implemented this newly issued permits. If a site does not already have NetDMR access from wastewater reporting, it will be a partnership between the site and the state agency to get accounts set up and the site’s requirements imported into the system.

Still not sure exactly where your site(s) stand with respect to industrial stormwater coverage? Do all these differences in a program that seems so simple at first glance have you seeing red or feeling blue? ALL4 tracks all of these requirements and is experienced in industrial stormwater permitting across the country. We are well suited to assist with stormwater program management for either a single facility or corporate-wide. If you have questions or want to discuss your site’s compliance please reach out to Anna Richardson at arichardson@all4inc.com or Matt Dabrowski mdabrowski@all4inc.com.

U.S. EPA’s “Good Neighbor Plan” Finds Its Way to the Federal Register. Let the Litigation Begin.

On June 5, 2023, U.S. EPA published the “Good Neighbor Plan” (GNP), also known as the Ozone Transport Federal Implementation Plan (FIP), in the Federal Register at 88 FR 36654.  U.S. EPA originally signed the GNP on March 15, 2023.  With the rule’s publication in the Federal Register, the GNP becomes effective on August 4, 2023, except in states (i.e., Arkansas, Kentucky, Louisiana, Mississippi, Missouri, and Texas) that were awarded a stay of U.S. EPA’s disapproval of their State Implementation Plans (SIPs) pending judicial review.

On February 13, 2023 (88 FR 9336), U.S. EPA fully or partially disapproved SIPs for 21 states that were submitted to fulfill their “good neighbor” obligations under the Clean Air Act (CAA) to address the 2015 National Ambient Air Quality Standards (NAAQS) for ozone.  U.S. EPA’s disapproval of these states’ SIPs resulted in the Federal GNP.  Several states, challenged U.S. EPA’s disapproval of their SIPs. Arkansas, Kentucky, Louisiana, Mississippi, Missouri, and Texas were awarded an administrative stay of their SIP disapprovals pending judicial review.  This ultimately means that the FIP is not effective in these states, pending legal review.  On June 1, 2023, U.S. EPA issued the “Goffman Memo” in response to the legal actions, noting that U.S. EPA will take action to ensure that the requirements of the GNP will not take effect in Arkansas, Kentucky, Louisiana, Missouri, and Texas while U.S. EPA’s disapprovals of the SIPs are being reviewed.  Note that Mississippi was not directly included in the Goffman Memo; however, it is expected that the same action by U.S. EPA would be applicable for Mississippi.

On June 8, 2023 a group of 17 Senators introduced a joint resolution of disapproval of the GNP under the Congressional Review Act (CRA) (S.J.Res.31).  This action has been referred to the Committee on Environment and Public Works.  In addition, several cement companies have requested that the GNP be vacated and remanded “because it is arbitrary, capricious, and not otherwise in accordance with law”.

This may be just the start of litigation on the GNP and associated SIP disapprovals, but it does not mean you can bury your head in the sand and wait for the GNP to disappear.  There is a lot to do, in a short amount of time.  For electric generating units (EGUs), now is the time to review allocations calculated by U.S. EPA for your facility and look at predictive measures to determine the impacts moving forward, as cost of compliance increases.  For non-electric generating units (Non-EGUs), there is a whole host of actions that need to be taken, such as determining applicability to your units, data collection, control device evaluation, permitting, monitoring challenges, etc. At a minimum, you should be evaluating compliance options and determining the time it will take to implement solutions while you wait to see if the rule will stand in your state for your facility. If the rule ultimately stands, it may be difficult to justify a compliance extension if you were waiting for the legal system instead of taking any action.

ALL4 has been actively looking at the GNP for a wide range of EGUs and Non-EGU sectors and we are actively working to get implementation questions answered. Need more information? you can review ALL4’s previous GNP blogs and webinars by looking here.  If you haven’t already started looking at what you need to do, the time to start is now.  If you have questions or need help planning for compliance with the GNP, please reach out to Eric Swisher, Amy Marshall or Roy Rakiewicz.

National Forklift Safety Day 2023

National Forklift Safety Day (NFSD) is observed on the second Tuesday of June each year, which is June 13 this year. This year is the 10th anniversary of NFSD which was started as an initiative by the Industrial Truck Association (ITA) and NFSD is observed to highlight the importance of safety for manufacturers, operators and those who work around forklifts.

Background

In 1923, the first electric truck with raising forks was produced. During WWII materials were moved on wooden pallets and new longer lasting forklift models were introduced. In the 1960’s forklifts as we know them are invented. Modern forklifts come in all shapes and sizes and are more powerful and capable than ever before. Depending on the model, some units can carry loads up to 35,000 pounds!

Warehouses, manufacturing facilities, retail stores, to name a few examples can have massive loads of materials, which require moving by using vehicles with immense lifting and holding capacities. Even if a material is lightweight, it can be nearly impossible for a person to transfer it without any additional help. With the use of forklifts, workers can effortlessly move materials on site without any hassle.

The National Institute for Occupational Safety and Health (NIOSH) notes that each year nearly 100 workers are killed and another 20,000 are seriously injured in forklift-related incidents. Forklift overturns are the leading cause of fatalities and represent about 25 percent of all forklift-related deaths, while foot injuries are the most prevalent of nonfatal incidents.

If you work on or around forklifts here are some safety tips to help protect you and your surroundings.

  • If in doubt, don’t lift it. If the load isn’t steady or secure, wait until it can be arranged properly.
  • Know what’s around you. Be aware of your surrounds, keep an eye out for pedestrians or other equipment.
  • Inspect before use. Does everything look to be in good working order? If not, report it and don’t use it.
  • Are you trained? If you don’t have training on the equipment, why are you using it?

What can you do for NFSD?

  • Organize a workshop or demonstration – Host a safety workshop for your operators or provide other forms of training.
  • Review Safety Protocols – Use NFSD as a chance to review your training and safety procedures. Make sure guidelines are up to date and share any updates with your employees.
  • Sign up for a Webinar or event – ITA hosts an event every year with an impressive panel of speakers who discuss several aspects of forklift safety. An in-person event is taking place in Washington D.C. this year on June 12-13 and is free to attend!

ALL4 assists clients with forklift safety training programs and inspections for a wide range of industries. We can develop forklift safety programs, training, and provide OSHA compliance evaluations, including recommendations and corrective actions for any compliance gaps. If you have questions on forklift safety and its effect on your facility, please reach out to Victoria Sparks at vsparks@all4inc.com.

Sustainable Aviation Fuels

With growing interest in carbon neutrality from industry, government, and consumers, the aviation industry is under increasing pressure to reduce its carbon footprint. Sustainable aviation fuels (SAFs) offer a potential solution by reducing greenhouse gas (GHG) emissions, decreasing dependence on fossil fuels, and potentially being produced locally.

What Are Sustainable Aviation Fuels?

Air travel is a significant contributor to carbon emissions, responsible for approximately 2.5% of global GHG emissions1. The aviation sector is beholden to fluctuating oil prices and limited geographic availability due to its dependence on fossil fuels2. One solution to this problem is the use of SAFs.

SAFs are a potential alternative to traditional jet fuels and can be produced from renewable sources such as those listed below3:

  • Corn grain
  • Oil seeds
  • Algae
  • Other fats, oils, and greases
  • Agricultural and forestry residues
  • Wood mill waste
  • Municipal solid waste streams
  • Manures and other compost gases
  • Wastewater treatment sludge
  • Dedicated energy crops

The largest benefit of transitioning to SAFs is the significant decrease in carbon emissions. The combustion of jet fuel produces about 94 kilograms (kg) of carbon dioxide equivalents (CO2e) per million British Thermal Units (MMBtu). SAFs emissions factors vary depending on their composition but are estimated to be around 50 kg/MMBtu CO2e4. SAFs can be used in existing aircraft engines without the need for significant modifications or infrastructure changes5. Additionally, the many types of feedstocks available to SAFs can be grown in all locations, reducing transportation emissions, and decreasing dependence on fossil fuels2.

How Are SAF Being Implemented?

Globally, the combustion of jet fuel accounts for about 98% of the airline industry’s carbon emissions. Delta Airlines has reported that it intends to transition to at least 95% SAFs by 2050 to meet their climate goal of net zero GHG emissions. Delta has made a deal with Shell for 10 million gallons of SAFs to be supplied to the Los Angeles International Airport (LAX). Because there is not currently enough SAFs to fully fuel airlines, Delta Airlines hopes to utilize deals such as this one to create higher demand and incentivize the production of SAFs6.

United Airlines has also announced that it will use SAFs on its flights departing from the San Francisco International Airport (SFO) which will result in about 10 million gallons of SAFs used in 20237. Several other airlines worldwide are making commitments to operate using SAFs in the next five years, including American Airlines, Alaska Airlines, Japan Airlines, British Airways, Qatar Airways, and Finnair. In September 2021, 60 companies agreed to work together toward using 10% SAFs by 2030 at an event for the World Economic Forum’s Clean Skies for Tomorrow Coalition8.

In addition, the Inflation Reduction Act (IRA) of 2022 aims to increase domestic energy production and reduce carbon emissions by investing $369 billion in Climate Change and Energy Security Programs9. The IRA allocates $297 million to the advancement of SAFs and other low emissions aviation technologies10 and provides a $1.25 credit per gallon of SAF used by businesses11.

Closing

As stakeholders and government organizations are showing increasing interest in sustainability, many companies are quantifying their GHG emissions or carbon footprints. One way for businesses to improve their carbon footprint is to utilize airlines that are transitioning to SAFs. If a company does not transport products via plane, corporate sustainability can be improved by taking flights fueled by SAFs to meetings and conferences.

ALL4 offers climate and environmental, social, and governance (ESG) consultation services and can help companies evaluate their carbon footprints and meet their sustainability goals. For more information, contact Susan Iott at siott@all4inc.com.


References:

1Our World in Data – Climate Change and Flying: what share of global CO2 emissions come from aviation?
2International Air Transport Association – What is SAF?
3Office of Energy Efficiency & Renewable Energy – Bioenergy Technologies Office – Sustainable Aviation Fuels
4Advanced Biofuels USA – Quick Summary of Sustainable Aviation Fuels (SAF) Provisions in Inflation Reduction Act
5British Petroleum – What is sustainable aviation fuel (SAF)?
6ESG Today – Delta Outlines Decarbonization Plans, with Focus on Sustainable Aviation Fuel
7CSR Wire – United to Triple SAF Use in 2023, Adds SAF on Flights at San Francisco Airport
8i6 Group – Which Airlines Are Embracing SAF?
9Senate Democrats – Inflation Reduction Act One Page Summary
10U.S. Department of Transportation – Meeting to discuss the new Inflation Reduction Act (IRA) Section 40007 Grant Program Fueling Aviation’s Sustainable Transition through Sustainable Aviation Fuels (FAST-SAF) and Low-Emission Aviation Technology (FAST-Tech)
11Internal Revenue Service – Treasury, IRS issue guidance on new Sustainable Aviation Fuel Credit

U.S. EPA Issues Memorandum on How Hazardous Waste Regulations Apply to Lithium-Ion Batteries

After many years of anticipating the United States Environmental Protection Agency (U.S. EPA) guidance on the management of end-of-life lithium-ion batteries, the wait is finally over for the battery industry. On May 24, 2023, the U.S. EPA released a guidance memorandum that clarifies the agency’s position that most lithium-ion batteries are likely hazardous waste under the Resource Conservation and Recovery Act (RCRA) regulations at end-of-life and that they can be managed under the streamlined hazardous waste management standards for universal waste until they reach a destination facility for recycling or discard1.

U.S. EPA states in the memorandum that most lithium-ion batteries on the market today are likely to be a hazardous waste2 when they are disposed of due to their ignitability (D001) and reactivity (D003) characteristics and explains that “fires at the end-of-life are common and mismanagement and damage to batteries make them more likely.” The guidance states that most lithium-ion batteries can be managed as a universal waste until they reach their destination facility, at which point they must be managed as a fully regulated hazardous waste. US EPA emphasizes that lithium-ion batteries at end-of-life should only be sent to facilities that are either hazardous waste recyclers with no storage before recycling or RCRA-permitted treatment, storage, and disposal facilities.

How does this memo affect Lithium-Ion Battery Waste Generators?

Once a generator concludes that a lithium-ion battery is a universal waste, the generator will need to appropriately manage it as universal waste. The requirements for managing universal waste are found in 40 C.F.R. Part 273 and include employee training, labeling of containers, limits on how long such waste may be accumulated at a site before being shipped for disposal or recycling, and requirements relating to shipping (including Pipeline and Hazardous Materials Safety Administration shipping requirements). Entities that accumulate more than 5,000 kilograms of universal waste at any time are subject to more stringent requirements.

U.S. EPA also notes that the determination that a battery is a waste, rather than a product that might be reused, can be made off site, so long as there is a “a reasonable expectation of reuse.”  For example, intact and functional batteries provided to an electronic waste reverse logistics provider, who would then evaluate whether the batteries can be reused or instead must be recycled, could potentially not qualify as a waste until the logistics provider makes that determination, so long as there was a reasonable expectation that the battery might be reused when provided to the logistics provider.

The memorandum goes on to explain that “international shipments of lithium batteries managed as universal waste must also comply with RCRA requirements for export and import of universal waste.” Those requirements, located at 40 CFR Part 272 Subpart H, generally require prior notification and consent by the relevant countries before wastes can be imported or exported, as well as other requirements. Accordingly, entities shipping used lithium-ion batteries internationally should pay careful attention to these requirements.

How does this memo affect Recyclers of Lithium-Ion Batteries?

“Recycling” under the definition of the solid waste transfer-based recycling exclusion (40 CFR 261.4(a)(24)&(25)) requires that (1) both the state of generation and state of recycling have adopted the federal exclusion in state law, (2) all conditions for the exclusion are met, including financial assurance or RCRA storage permit for the recycler and reasonable efforts to audit the recycler by the generator, and (3) transportation through states that have not adopted the exclusion comply with such states’ hazardous waste regulations. U.S. EPA clarifies that battery recycling facilities generally do not need to obtain RCRA permits in order to conduct recycling operations. However, U.S. EPA cautions that recyclers may not “store” batteries prior to recycling them without obtaining a RCRA permit. U.S. EPA declines to specify a permissible “holding time,” which would not be deemed storage, prior to recycling commencing and instead leaves that determination to the regions or the states. U.S. EPA also explains that certain RCRA air emission requirements may apply to such operations, and that such operations must comply with the general recycling requirements at 40 CFR Part 261.6.

U.S. EPA recommends that in addition to following the prescribed standards for storage and transportation for lithium-ion batteries, managers of end-of-life batteries should take the following precautions to protect against the chance of thermal runaway and fire:

  • Conduct safety training for all employees handling batteries;
  • Isolate the terminals of the batteries with non-conductive tape, plastic bags, or other separation techniques, keeping the label legible;
  • Prevent damage to batteries;
  • Store batteries in climate-controlled spaces with good ventilation;
  • Store batteries in a separate building away from flammable materials and occupied spaces when possible;
  • Store batteries that have been identified as damaged, defective, or recalled (DDR) separately from non-DDR batteries in appropriate containers;
  • Conduct frequent visual and thermal inspections of the batteries;
  • Have ongoing communications with local fire marshals and first responders about materials and processes happening onsite; and
  • Maintain a plan for how to respond and evacuate in case of emergency.

The memorandum explains that most states have delegated authority to implement their own RCRA programs and can impose more stringent requirements. Generators, recyclers, and others who manage lithium-ion batteries at the end of their lives should carefully evaluate potential state requirements and take proactive steps to ensure their employees and operating procedures are trained and updated appropriately to ensure they remain in compliance.

If you have questions about any part of this memorandum and how it may affect compliance at your facility, or if you would like to inquire about training or setting up a battery management program at your facility, please reach out to me at mliebert@all4inc.com. ALL4 is monitoring all regulatory updates in this ever-evolving industry, and we are here to answer your questions and assist your facility with the safe and compliant handling and transport of lithium-ion batteries.


1 The universal waste standards in 40 CFR Part 273 are for certain hazardous wastes that are generated by a wide variety of establishments and are meant to streamline the collection of these hazardous wastes for proper management at a hazardous waste recycler or a permitted treatment, storage, or disposal facility. Both rechargeable lithium-ion and single use lithium primary batteries can be managed as universal waste. Universal waste regulations do not require a hazardous waste shipment manifest but require that the waste be sent to a permitted hazardous waste disposal facility or a hazardous waste recycler.

2 Waste generators have an obligation to evaluate whether their waste is hazardous under RCRA. Per this guidance, generators should expect to conclude that any lithium-ion batteries they discard will qualify as universal waste. If a generator decides not to handle a discarded lithium-ion battery as a universal waste, it should have a sound technical basis for concluding that the battery does not meet the ignitability or reactivity criteria.

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