Meet ALL4’s Project Management Director, JP Kleinle

Effective project management is essential to ALL4’s success and is the engine of our business. As a growing organization, ALL4 currently has project management roles open in all our offices. Have you wondered what it might be like to join ALL4 and be a project manager? Whether you are someone taking on project management duties for the first time in your career, or are an experienced project manager, ALL4’s Project Management Office (PMO) offers support to both new and seasoned ALL4 staff.  JP Kleinle is our Project Management Director (PMD) and leads the PMO efforts. The PMO serves ALL4’s project manager community with the training and resources needed to continually improve our project management skills across all aspects of the business.  As part of our Operational Excellence (OE) goal, the PMO is tasked with enhancing ALL4’s framework of systems, processes, and procedures used by project managers and business leaders. JP answers three questions about how he supports project managers at ALL4 below.

Q#1 Can you give us a sense of what the PMD does, and what drew you to the role?

JP: In my role as the PMD, I serve as an advocate for team members operating in a project management role at ALL4 with the intent to bring efficiency to our processes and procedures used to manage our client’s projects. Having served as a long-time project manager, I have walked in the shoes of our project managers and have developed good habits and best management practices along the way. I am still a project manager at ALL4 today and continue to have first-hand knowledge of how to implement and optimize our processes and procedures. As a growing organization in an ever-changing world of technology, there is an ongoing need to not only onboard new team members but also to reskill and upskill our project managers. This challenge is exciting and is what drew me to the PMD role. I feel I have skillsets and knowledge to share and can make a positive impact in the careers of others at ALL4.

Q#2 There is a project manager forum. Tell us about the format of this meeting.

JP: Chad Morris, ALL4’s Chief Strategy Officer, helps me lead and moderate the project manager forum. In 2023, we held four foundational meetings and sprinkled in additional meetings throughout the year.

We also have a Microsoft Teams chat where ideas and views on issues or questions can be exchanged among project managers.  The objectives of these forums are to increase collaboration and engagement with our peers, improve communications, and support the PM cohort. During our foundational meetings, we explored topics like sales and growth, client and staff planning, best management practices, and burnout. My favorite forum so far included a role play exercise around having difficult conversations. We plan to have more role play exercises in 2024.

Q#3 For anyone contemplating making the transition into a project manager role either from industry or leveling up as a consultant, what are ways the PMO can walk alongside them to offer support?

JP: Project managers are essential to the long-term sustainable growth of ALL4, and we offer support in a variety of ways. The PMO maintains a comprehensive Project Management Guide that is a compendium of guidance on the key systems and processes that project managers utilize at ALL4. The Guide also communicates ALL4’s set of expectations for managing projects. The PMO (Neal Lebo, Project Management Consultant) administers formal Project Management Onboarding training courses that new project managers attend. The PMO has “boots on the ground,” traveling as a team to our various offices for ongoing learning and development initiatives. We call these in-person events PMO Connections. There are also the PM forums mentioned earlier. We use an idea portal to receive suggestions, concerns about obstacles, and ideas for improvement, which are all used to inform our adjustments to get the desired results both the Company and project managers are looking for. The PMO (Karen Escobar, Project Management Business Partner) recently updated our change management process to cultivate a flexible growth culture. Our change management process includes project manager participation to ensure their voices are heard. The combination of these processes keeps the engagement high, allows the PMO to explore new ideas with the project managers, and is key to a project manager’s development while charting their career path at ALL4.

If you would like to learn more about project management opportunities at ALL4, please visit our Careers Page or contact Anne Vitale at avitale@all4inc.com.

CAL OSHA Workplace Violence Prevention Program

SB 553 – Workplace Violence Prevention Programs & New Cal OSHA Requirements

In February 2023, Senate Bill No. 553 (SB 553) was placed into motion by the California State Senate to introduce the first general industry workplace violence safety requirements that would require employers to take comprehensive steps to prevent and respond to workplace violence incidents. On September 30, 2023, Governor Newsom signed SB 553 into law which will require most employers to create and implement a Workplace Violence Prevention Program by July 1, 2024. SB 553 will amend Section 6401.7 and add Section 6401.9 to the California Labor Code and Section 527.8 to the Code of Civil Procedure.

There were no prior Cal OSHA workplace violence standards, however, under the General Duty Clause (Sec 5(a)(1)), employers were required to “furnish to each of his employee’s employment and a place of employment which are free from recognized hazards that are causing or are likely to cause death or serious physical harm to his employees”.

Workplace Violence Prevention Program/Plan

Effective July 1, 2024, all covered employers will be required to establish, implement, and maintain a Workplace Violence Prevention Plan in writing as an extension to their Injury and Illness Prevention Plan (IIPP). Key updates include the following:

• Employers must maintain records of all workplace violence incidents in a violent incident log.
• Employers must provide effective training to employees on the workplace violence prevention plan and provide additional training when a new or previously unrecognized workplace violence hazard has been identified and/or when changes are made to the plan.
• Employers must maintain records of workplace violence hazard identification, evaluation, and correction.

SB 533 will provide Cal OSHA enforcement authority by issuance of a citation and a notice of civil penalty. The bill would also authorize the appeal of a citation and penalty.

Workplace Violence Types

Each workplace violence incident that occurs must be recorded on the violent incident log. SB 553 details the specific information that must be included on the log such as a classification of the offender, consequences of the incident, type of violence, and who made the log entry. Workplace violence acts are classified into four types:

• Type 1 violence – A workplace violence act by a person who has no relationship to the employee or businesses and commits a violent act against an employee in conjunction with a crime (e.g., robbery or trespassing).
• Type 2 violence – A workplace violence act between an employee and customer, visitor, or client outside of the organization.
• Type 3 violence – A workplace violence act between a present or a former employee, supervisor, or manager.
• Type 2 violence A workplace violence act by a person who does not work at the organization but has a personal relationship with the employee.

Restraining Orders

Under the current law, employers have the authority to seek a restraining order on behalf of any employee who is a victim of a workplace incident. SB 533 will authorize a collective bargaining representative of an employee to seek a restraining order on behalf of the employee. The Bill will also provide employees the opportunity to not be named in the restraining orders and will not prohibit an employer or collective bargaining representative from seeking restraining orders on behalf of other employees at the workplace.

What’s Next?

Employers are required to create and implement a Workplace Violence Prevention Program by July 1st, 2024. ALL4 staff are experienced in planning for and implementing updated environmental, health and safety regulatory requirements, including workplace safety procedures and training. If you have any questions on this requirement or would like help preparing for these new requirements, please contact Ivan Torres at itorres@all4inc.com.

U.S. EPA Finalizes Elimination of TRI PFAS de-minimis

elimination of de-minimis rule for pfas

Effective November 30, 2023, the United States Environmental Protection Agency (U.S. EPA) finalized Changes to Reporting Requirements for Per- and Polyfluoroalkyl Substances and to Supplier Notifications for Chemicals of Special Concern rule which designates per-and polyfluoroalkyl substances (PFAS) as “chemicals of special concern” and with that comes other requirements to the Toxics Release Inventory (TRI) program under the Emergency Planning and Community Right-to-Know Act (EPCRA) Section 313.  This designation eliminates the de-minimis exemption for TRI reporting and supplier notifications, as well as eliminates the option to submit a Form A report instead of a Form R.

PFAS were initially added to the TRI chemical list for the 2021 reporting year when the National Defense Authorization Act (NDAA) was signed on December 20, 2019. The NDAA immediately added 172 PFAS chemicals with a 100-pound reporting threshold for each of the listed PFAS that are manufactured, processed, or otherwise used at the facility. Additionally, the NDAA stipulated that additional PFAS would be added annually thereafter. As of 2023, the list has increased to include an additional 17 PFAS chemicals, totaling 189 TRI-listed PFAS. The previous de-minimis concentration threshold for perfluorooctanoic acid (PFOA) was set at 0.1%, and all other TRI-listed PFAS at 1%.

The decision to eliminate the de-minimis exemption is due to PFAS being typically incorporated into materials at very low concentrations, causing facilities to disregard them during the TRI reporting process and for supplier notifications. With the designation of PFAS as “chemicals of special concern,” EPA’s goal is to develop a more accurate and complete dataset of where PFAS are being released to the environment and potential impacts on human health because they believe more facilities will be required to submit TRI reports for PFAS than have historically done so.

What’s Next?

Suppliers and facilities are now required to disclose TRI-listed PFAS, no matter the concentration. Previously, suppliers and facilities were able to claim the de-minimis exemption and not disclose the chemical composition due to lower concentrations.

• Request from your suppliers and be on the lookout for updated SDS or supplier notifications sent with the first shipments of the year in 2024.
• Review used materials that were historically listed as containing PFAS and were designated as meeting the PFAS de-minimis
• Track PFAS chemicals that will be reported for the 2024 Reporting Year in July 2025.

If you have questions about the changes to TRI reporting requirements for PFAS, how to review and track PFAS containing materials, or how PFAS may impact your facility, please contact Colleen Nagel at cnagel@all4inc.com or (616)251-1097 or Kayla Turney at kturney@all4inc.com or (610)422-1143.

U.S. EPA Issues Final Decision Related to Burning Paper Recycling Residuals and Treated Wood

The Non-Hazardous Secondary Materials (NHSM) Rule at 40 CFR Part 241 is used by facilities to determine whether non-traditional fuels they burn in their combustion units are solid waste. The U.S. Environmental Protection Agency (EPA) received a petition in 2018 requesting revisions to the NHSM Rule related to how to assess materials as non-wastes and also to refine how  paper recycling residuals (PRR) and creosote treated railroad ties (CTRT) are evaluated as non-wastes.  Specifically, the petition requested the following:

• Change the third legitimacy criterion at 40 CFR Part 241.3(d)(1) to allow for an optional instead of mandatory comparison of contaminants in the NHSM against the contaminants in a traditional fuel;
• Remove the designed to burn and other associated limitations on burning CTRT; and
• Revise the definition of PRR.

U.S. EPA published its final response to that petition on October 18, 2023. The requests in the petition were denied, but the definition of PRR was revised.

What changed and did not change in the NSHM Rule?

Petitioners were hoping to align the legitimacy determination process for NHSM to match the process for hazardous secondary materials.  This alignment would have made optional the required mandatory contaminant comparison in the NHSM regulations.  The ability to make the contaminant comparison optional would have increased the flexibility for qualifying a secondary material as a non-waste.  Ultimately, U.S. EPA kept the contaminant comparison mandatory because the non-hazardous and hazardous programs are distinct programs and regulatory criteria for one program do not translate to the other.

Although U.S. EPA denied the petition to make the contaminant comparison optional for all secondary material and to remove the “designed to burn” test for CTRT, it did revise the definition of PRR (although not as the petition requested). In January 2022, U.S. EPA had proposed to revise the PRR definition to specify a 2% limit on non-fiber materials. However, based on comments from industry, that definition was not finalized. The final PRR definition is:

Paper recycling residuals means the secondary material generated from the recycling of paper, paperboard and corrugated containers composed primarily of fibers that are too small or weak to be used to make new paper and paperboard products. Secondary material from paper recycling processes with a heating value below 6,300 Btu/lb on a dry basis due to excessive non- fiber material content (including polystyrene foam, polyethylene film, other plastics, waxes, adhesives, dyes and inks, clays, starches and other coating and filler material) are not paper recycling residuals for the purposes of this definition.

U.S. EPA finalized this definition, which includes a minimum heating value that PRR must meet in order to be considered a non-waste fuel, to address concerns that facilities were burning PRR with low heating value (e.g., from non-fiber materials) to discard the PRR, not to recover energy.

Does this decision affect me?

If you are burning or would like to burn PRR, you will need to review the revised definition and determine if the PRR you are burning or will burn meet the definition. For example, you will need to determine the heating value of the PRR. Note that a condition to evaluate the characteristics of your PRR could be added to your permit as a result of this definitional change. If you burn PRR that do not meet this definition, you could be burning solid waste.

What about design to burn criteria and CTRT?

With respect to CTRT, a categorical non-waste exemption exists for boilers meeting certain characteristics.  Petitioners had hoped to expand the capability of facilities to combust CTRT for energy recovery by relaxing how “designed to burn” was incorporated in the non-waste determination.  If you are burning CTRT under the categorical exemption or would like to burn CTRT under a self-implementing non-waste determination, the design to burn criterion must be met.  In the non-waste determination, designed to burn, as it applies to a traditional fuel, means a boiler  could/can burn the traditional fuel, regardless of whether it has burned, or is permitted to burn, the fuel. For example, if your boiler is physically capable of burning both biomass and fuel oil (i.e., the fuel handling equipment was or is currently installed), you can compare the contaminants in CTRT to both of those fuels, regardless of whether your permit includes both fuels.  Petitioners had hoped to make the design to burn assessment a hypothetical assessment rather than the deterministic approach used by U.S. EPA.

Not sure what to do?

If you need help evaluating what materials you are burning or would like to burn are NHSM fuels versus solid waste, reach out to me or your ALL4 project manager for help. We will continue to monitor for further changes to this and other combustion-related regulations.

48C Tax Credit – Round 2

The Inflation Reduction Act (IRA) has revived the Qualifying Advanced Energy Project Credit under 26 U.S. Code Section 48C, also known as the 48C investment tax credit, to accelerate domestic clean energy manufacturing and the transition to clean energy technologies. The IRA allocated $10 billion to be distributed through Section 48C with up to a 30% tax credit for qualified energy projects. These incentives are available for projects in three categories: clean energy manufacturing and recycling; industrial decarbonization; and critical materials processing, refining, and recycling.

The Section 48C tax credit is based on an application and award process that allocates tax credits to successful applicants for their qualifying projects. Eligibility is a highly competitive process and entities must apply for approval. $4 billion in tax credit allocations was made available for Round 1, which closed in August 2023. According to the Department of Energy (DOE), applicants submitted concept papers for projects totaling almost $42 billion for Round 1. The application process for Round 2 is expected to open in 2024, and will allocate up to the remaining $6 billion of tax credits.

What is a qualifying project, defined in 26 USC §48C(c)(1)?

As stated above, the qualified projects fall into three categories, which are described below. A more detailed discussion of these, including qualifying, and non-qualifying, project examples can be found in this table.

1. Projects that re-equip, expand, or establish an industrial facility for the processing, refining or recycling of critical minerals. Critical minerals are defined as any mineral, element, substance, or material designated by the Secretary of the Interior, through the Director of the U.S. Geological Survey, and include minerals such as antimony, chromium, cobalt, gallium, graphite, lithium, manganese, nickel, platinum, titanium, and zirconium. The full list of fifty critical minerals is available from DOE.
2. Projects that re-equip an industrial or manufacturing facility with equipment designed to reduce greenhouse gas emissions by at least 20% through the installation of:
   • Low-or-zero-carbon process heat systems
   • Carbon capture, transport, utilization and storage systems
   • Energy efficiency and reduction in waste from industrial processes
   • Other industrial technology designed to reduce greenhouse gas emissions, as determined by the Department of Treasury
3. Projects to re-equip, expand or establish an industrial or manufacturing facility for the production or recycling of:
   • Property designed to produce energy from the sun, water, wind, geothermal deposits or other renewable resources
   • Fuel cells, microturbines or energy storage systems and components
   • Grid modernization equipment or components
   • Property designed to capture, remove, use or sequester carbon dioxide emissions
   • Equipment designed to refine, electrolyze or blend any fuel, chemical or product that is renewable or low-carbon and low-emissions.
   • Fuel cell or electric vehicles, and their components, materials and charging infrastructure
   • Hybrid vehicles weighing less than 14,000 pounds and their components and materials
   • Property designed to produce energy conservation technologies
   • Other property designed to reduce greenhouse gas emissions, as determined by Department of Treasury

The second category is the most widely accessible covering significant energy efficiency, electrification, or renewable energy projects, but category three is broad so there may be opportunity for creative interpretation. Companies should consider forming a cross-functional team comprised of tax professionals, accounting, finance, legal, and environmental staff to explore project opportunities and eligibility. If a potentially qualified project has already been implemented at a facility it will not qualify but if will be replicated at a second facility the new project could qualify.

What is the application process?

The Internal Revenue Service (IRS) provided guidance through IRS Notice 2023-18 and Notice 2023-44 on the application process. Entities interested in the 48C tax credit are required to first submit a “concept paper” through a portal created by the DOE. The DOE then reviews submitted concept papers and will issue a letter to the interested party either encouraging or discouraging the party to submit a full application.

To be considered for a Round 1 allocation, concept papers were to be submitted within 30 days of the application portal opening, however this deadline was extended to August 3, 2023. Following submission, the Department of Energy (DOE) issued a letter encouraging or discouraging the submission of a formal application. The full applications can be submitted as early as 7 days but no later than 45 days after the letter of encouragement or discouragement is issued. The deadline for Round 1 full applications is December 18, 2023. Final Round 1 allocation decisions are expected to be made by March 31, 2024.

Entities should not be misled by the short application timeframes. Complex project calculations and significant supporting documentation are required for both the concept letter and the full application. The application process is extensive and requires significant data development. The process to apply for Round 2 allocations is anticipated to be similar to the Round 1 application process.

What is the allowed construction period?

Any project awarded a Section 48C tax credit for advanced energy projects will have a two-year window to complete construction of the facility and provide evidence (for example, permits) that the requirements have been met. The Treasury Department will then provide certification for the tax credit. Failure to meet this two-year construction deadline will result in a forfeiture of the tax credit allocation under Section 48C.

If you are interested in the 48C tax credit but missed the Round 1 deadline to submit a concept paper, the IRS anticipates opening at least one more allocation round. While the IRS has not released definitive guidance as to when Round 2 will open for concept paper submissions, it is likely it won’t be until late Spring or early Summer of 2024, after the Round 1 allocations have been made.

How can ALL4 help?

ALL4 is currently working with clients to prepare full applications for Round 1 and to strategize and identify potential qualifying projects. ALL4 can provide technical analysis and documentation, project management support and assistance with timely application development. It is important for interested parties to begin to assess project eligibility soon in order to prepare for the opening of Round 2 and subsequent submittal deadlines. If you have any questions or need help determining if a project you are contemplating could qualify, feel free to contact Jenny Brown or Daryl Whitt.

Colorado Adopts GHG Intensity Verification Rule

Introduction

As a part of the Colorado Public Health and Environment’s (CDPHE) Pollution Reduction Roadmap, published in January 2021, the state has been taking action to reduce greenhouse gas (GHG) emissions. Recently on July 20^th 2023, the Colorado Air Quality Control Commission unanimously approved a new greenhouse gas intensity verification rule which sets standards on how oil and gas facilities must monitor, track and calculate GHG emissions. This verification plan is a part of a Colorado GHG intensity target, which sets numerical limits of carbon dioxide equivalent (CO2e) emissions per barrel of oil produced. The state’s overarching roadmap plans to reduce GHG emissions by 50% in 2030 compared to 2005 levels. The verification rule is codified in Regulation 7, Part B, Section VIII.F and will take effect at the start of 2025 when the first greenhouse gas intensity target comes into effect.

Does This Apply to Me?

The greenhouse gas intensity verification rule applies to “intensity operators”, meaning a person or entity that operates upstream segment activities or equipment, where upstream segments include the following processes in the oil and gas industry:

• Exploration – geological and physical surveys
• Extraction – drilling (boreholes and wells)
• Production – primary, secondary, and tertiary recovery

What Does This Mean?

It is clear that CDPHE is taking action as planned in their 2021 Roadmap. Starting in 2025, when the intensity standards are set, facilities must develop an emissions inventory that demonstrates compliance with the new intensity standards. For facilities subject to these new intensity standards, it is imperative that they maintain an accurate and up to date emissions tracking tool to demonstrate compliance with the intensity standards.

CDPHE will also develop and release protocols (including approved measurement strategies and default intensity verification factors). Keeping a close eye on these protocol updates will help ensure your compliance tool is as efficient and accurate as possible. Any revisions to the protocols will be published by June 30^th of the calendar year preceding the verification year. Record keeping requirements require the following documentation be kept on hand for a minimum of 5 years and available upon CDPHE request:

• Records created by the measurement strategy. The CDPHE Air Pollution Control Division has defined a measurement strategy as one that is informed by direct measurements of GHG emissions from a regional, local, stationary source, or an air pollution source monitoring of methane emissions, and optionally through parametric monitoring (monitoring of regional, local, stationary source, or air pollution source monitoring of pressure, temperature, flow rate, control efficiency, or other operational characteristics)
• Records of calibration and maintenance of equipment
• Records of inventory submissions to certified third party auditors
• Reports created by certified third party auditors
• Actions taken by certified third party auditors

ALL4 can help create standard operating procedures for emissions tracking and recordkeeping to ensure that your facility’s compliance with this new rule is a smooth process.

What Can I Do?

CDPHE will continue to update verification protocols as they come out. Following their website as well as ALL4 published articles on this topic will keep you up to date on any new guidance or standards that CDPHE releases. If you need assistance setting up the tools to comply with this new rule, or if you have any questions regarding the new rule, please contact Evan Mia at emia@all4inc.com or 610-422-1162.

Air and Waste Management Association Holds its First Annual Environmental Justice Conference

A&WMA held its first annual conference on EJ in Arlington, VA on October 23^rd and 24^th. The conference had a different vibe than most of the environmental conferences industry attends and had two distinct sets of attendees:

• Industry representatives and the consultants that work with them. Their primary interest was the permitting implications of undertaking projects in and around EJ communities and getting clarity on the expectations for those projects.
• Social and EJ advocates who are pushing for even more activity out of the government and had stories to share from being “on the ground” in EJ communities.

The conference had two main tracks of presentations:

The first focused on community engagement and included talks on specific EJ actions that are underway, approaches to engaging the community around your facility, and other similar more social topics. This track also included one or two presentations by non-governmental organizations (NGOs) that advocated action against, or even the shutdown of, specific facilities located in EJ communities that they accused of being bad neighbors. The track also included presentations on ethics and other similar kinds of issues.

The second track was more technical and focused on cumulative impact assessments (CIA), the tools, and methods for addressing EJ. This track was of great interest to the industrial community, in particular how the social stressors side of the CIA was addressed in the case studies presented. The short answer is that it wasn’t. The studies included a number of innovative air dispersion modeling approaches and other statistical analyses but did not attempt to quantify the social side at all, instead leaving that analysis to a qualitative approach that didn’t really directly address the issues or potential mitigation strategies. A notable highlight was the example of following Massachusetts’ CIA Guidance that was recently adopted for permitting actions near EJ communities. The analysis included air dispersion modeling for criteria pollutants and toxics, but nothing else to address the social side, and seemed to be no different than the modeling requirements in states that require modeling for minor source permits already (for example, Texas).

This highlights the continuing problem with CIA’s that the United States Environmental Protection Agency (U.S. EPA) has thus far not been able to answer: How do you factor in the social stressors in some sort of quantitative way, so that they can be compared or added to the impacts of the chemical stressors which we do know how to quantify, to truly identify the potential cumulative impacts? The conference unfortunately had no answers to that question.

Beyond the discussions around CIA’s several different new tools addressing various types of EJ analyses were demonstrated. Most notable was a tool that would trace air emissions backwards from a potential EJ community to the upwind coal-fired power plant, sometimes hundreds of miles away, that the emissions may have come from using the HYSPLIT model to trace the origin of the emissions.

Finally, the most enlightening part of the conference may have been the Tuesday morning plenary presentation given by Matt Tejada, Deputy Assistant Administrator for Environmental Justice at U.S. EPA, Kelly Crawford, Senior Advisor for Energy and Environmental Justice at the U.S. Department of Energy (DOE), and Ana Mascarenas, Senior Advisor for Environmental Justice in the Office of the Assistant Secretary for Health at the U.S. Department of Health and Human Services.  Aside from an update on what the various agencies recent EJ-related activities were, several notable points came out of this session, mostly from Mr. Tejada:

• “We know what to do” to address cumulative impacts and EJ issues was a driving theme. He also suggested that addressing EJ should not add to the cost or timing of permitting projects.
• The pending CIA guidance, when it finally arrives, will not have the specificity that industry and consultants are looking for in terms of a solid list of requirements or steps for including a CIA as part of the process. U.S. EPA clearly is either waiting for someone to perform a CIA of their own volition to point to as an example, or prefers to have each project do a CIA on a case-by-case basis. Despite Mr. Tejada’s claims, this would seem to inevitably add time, cost, and uncertainty to projects requiring a CIA with no specifics as to how to execute one.
• Tejada was adamant, as a corollary to not providing any direct guidance on incorporating EJ into a permitting project, that industry should be taking steps to address EJ “because it’s the right thing to do,” not because it is a requirement, and suggested that industry undertake outreach programs, add additional controls, and run its own community monitoring programs as part of their projects near EJ communities regardless of what is required.
• When pressed on the permitting guidance timing, the panel retreated and didn’t have much in the way of answers except for several vague statements about things an applicant might do that clearly would increase the cost and timing of a project, contradicting what was said during the presentation at the beginning of the session.
• Finally, and perhaps most notably, when asked when industry was going to be invited to the table to participate in U.S. EPA’s policy making discussions, Mr. Tejada said in so many words “when I can trust you” and further suggested that he would not bring anyone into the conversation that he didn’t know he could trust, and “we’re not there yet.” This exchange drew a lot of concerned glances from the industry representatives in the room.

To summarize, the conference was interesting and informative, especially as it shed light on the administrations’ stance on EJ issues and the lack of progress or guidance in terms of how and when to conduct a CIA.

If you’d like to discuss the any issues around environmental justice concerns near your facilities and how to address them, feel free to contact your ALL4 Project Manager or Rich Hamel. We’ll continue to monitor EJ guidance from the administration and states and the tools available to evaluate EJ concerns as they develop. We can also help you evaluate permitting risks, from EJ concerns to regulatory issues, and assist in developing a strategy to make the permitting of your project as efficient as possible.

Proposed Amendments to Integrated Iron and Steel Manufacturing MACT Standards

On July 31, 2023, the U.S. Environmental Protection Agency (EPA) proposed amendments to 40 CFR Part 63, Subpart FFFFF, National Emission Standards for Hazardous Air Pollutants (NESHAP) from Integrated Iron and Steel Manufacturing Facilities (Subpart FFFFF). Subpart FFFFF applies to facilities under the NAICS code 331110, or any facility engaged in producing steel from refined iron ore. There are currently eight operating facilities and one idle facility in this source category. U.S. EPA is updating the technology review promulgated in July 2020.

What is changing?

U.S. EPA has proposed new and revised emissions limits based on maximum achievable control technology (MACT) for point and fugitive sources located at integrated iron and steel manufacturing facilities. The changes are substantial and include:

• Regulation of hazardous air pollutant (HAP) emissions from unmeasured fugitive and intermittent particulate matter sources (UFIP)
• Regulation of five unregulated HAPs from sinter plants
• Regulation of three unregulated HAP from blast furnace stoves (BF) and basic oxygen process furnaces (BOPF)
• Regulation of two unregulated HAP from BF
• Revision of the dioxin/furan (D/F) and polycyclic hydrocarbon (PAH) standards for sinter plants.
• A new requirement for fenceline chromium (Cr) monitoring at each Facility to ensure that the proposed work practice standards and emissions limits are achieving anticipated results.

Summaries of the revisions are provided below.

Proposed New UFIP Requirements

Summaries of the proposed changes to the five UFIP sources are provided below.

BF Unplanned Bleeder Valve Openings

BF unplanned bleeder valve openings are unexpected openings of the bleeder valves due to pressure surges that can occur when raw materials build up at the top of the BF and fall (slip). U.S. EPA has proposed new operational limits listed below:

• Existing Sources: Five unplanned openings per furnace, per year
• New Sources: Zero unplanned openings per furnace, per year (new sources)

U.S. EPA determined that five unplanned openings per furnace per, year was the MACT floor level of performance for the existing units. The best performing BF reported zero unplanned openings, which resulted in the proposed new source operational limit.

U.S. EPA also proposed the following work practice standards to prevent large raw material slips from occurring:

• Install and operate devices to continuously measure/monitor material levels in the furnace at a minimum of three locations and using alarms to inform operators of static conditions that indicate a slip may occur.
• Install and operate instruments such as a thermocouple and transducer on the furnace to monitor temperature and pressure to help determine when a slip may occur.
• Install a screen to remove fine particles from raw materials.
• Develop and submit a plan to the U.S. EPA for approval that explains how the facility will implement these requirements.

U.S. EPA has also proposed a new requirement  for facilities to submit a semi-annual unplanned bleeder valve report to include the date, time, duration, and any corrective actions taken in response to unplanned openings.

BF Planned Bleeder Valve Openings

BF planned bleeder valve openings are bleeder valve openings initiated by an operator as part of a furnace startup, shutdown, or temporary idling for maintenance.   Planned openings occur after the BF is turned down, which results in less emissions than during unplanned openings.  U.S. EPA has proposed the following new opacity limits for such openings:

• 8% opacity for any 6-minute averaging period of the BF planned bleeder valve openings for existing sources.
• 0% opacity for any 6-minute averaging period of the BF planned bleeder valve opening for new sources.

U.S. EPA suggests that preemptive actions prior to planned openings such as tapping as much liquid out of the furnace as possible, removing fuel or and/or stopping fuel injection, and lowering the bottom pressure  can help to minimize visible emissions, but did not propose any work practice standards for planned openings to allow facilities flexibility in determining how they will comply with the opacity standards.

BF and BOPF Slag Processing, Handling, and Storage

Slag is skimmed from the surface of molten iron or steel and transported to pits for cooling. Fugitive emissions can occur during slag dumping, storage, removal or recovery, and handling.

U.S. EPA has proposed a new opacity limit for visible emissions from slag pits during slag handling, storage, and processing:

• Existing Sources: 5% opacity based on a 6-minute average.
• New sources: 2.5% opacity based on a 6-minute average.

The existing source opacity limit reflects a beyond the floor standard because there are work practices available that are not requirements but can assist in minimizing emissions, such as applying a water spray or droplets, installing wind screens, dust suppression misters, maintain  high moisture content of slag during handling, storage, and processing operations.

BF Bell Leaks

Blast furnace charge systems typically include a system of large and small “bells” that serve as a lock system to prevents blast furnace gases from escaping during furnace charging. The metal seals of the bells  mechanically wear down over time from use.  . As the seals wear, they lose their effectiveness and allow BF gases to escape into the atmosphere.

U.S. EPA has proposed a new operating requirement to observe the top of the BF monthly for visible emissions using EPA Method 22. If there is a visible plume present via EPA Method 22, an EPA Method 9 test to determine opacity would be required. If visible emissions determined by EPA Method 9 test are greater than a 10% opacity “action level” based on a 3-minute average, then the large bell seals would need to be repaired or replaced within the next 4 months.

The newly proposed requirement for small bells seals is to replace or repair seals prior to a facility-specific metal throughput limit that has been proven and documented to produce no opacity from the small bells.

Beaching of Iron BFs

“Beaching” occurs when hot iron from a BF is dumped onto the ground because the BOPF cannot accept the iron, which results in fume generation.  EPA has proposed a new work practice standard that will require facilities to have full or partial enclosures for the beaching process or to use CO₂ to suppress the associated fumes and minimize the height, slope, and speed of beaching.

BOPF Shop Standards

BOPF shop fugitive emissions are associated with various operations (e.g., hot metal and scrap charging, tapping steel, hot metal transfer, metallurgical processes, etc.) and escape through building openings (e.g., roof vents, doors, and other openings).  The EPA has proposed to reduce the existing BOPF shop 20% opacity limit to 5% (3-minute average) and to add the following work practice standards:

• Keep all openings, except roof monitors (vents) and other openings that are part of the designed ventilation of the facility, closed during tapping and material transfer.
• Conduct regular inspections of BOPF shop structure for unintended openings and leaks.
• Optimize positioning of hot metal ladles with respect to hood face and furnace mouth.
• Monitor opacity twice per month from all openings, or from the one opening known to have the highest opacity for a full steel cycle (which must include the tapping event).
• Develop and operate according to an “Operating Plan” to minimize fugitives and detect openings and leaks.

BF Casthouse Fugitive Emissions

Blast Furnace Casthouse fugitive emissions are similar to the BOPF Shop emissions and exit through roof vents, open doors, and other openings. The current NESHAP limit for fugitive emissions is 20% opacity for existing sources and 15% opacity for new sources, based on a 6-minute average. EPA has proposed a revised opacity limit of 5% based on a 6-minute average for both new and existing sources. Opacity measurement would take place during tapping  at least two times per month. Under 40 CFR 63.7823(c)(2), tapping begins when the furnace is opened, usually creating a hole at the bottom of the furnace, and ends when the hole is plugged. The EPA has not proposed specific work practices but has proposed a new requirement to keep all openings, except roof monitors, closed during tapping and material transfer events.

New Limits on Previously Unregulated HAPs

U.S. EPA has proposed new point source emissions limits for new regulated pollutants from Sinter Plants, BF Stoves and BOPFs, and BFs. These limits are proposed to fulfil the requirement that all HAPs from affected sources are regulated.  The proposed limits are summarized in the table below.

Revised D/F and PAH Standards for Sinter Plants

U.S. EPA has proposed revised point source emissions limits for D/F and PAH from Sinter Plants.  U.S. EPA determined that activated carbon injection (ACI) was not cost effective and proposed limits of 3.5E-08 lbs/ton of sinter for D/F and 5.9E-03 lbs/ton of sinter for PAHs for existing sinter plant windboxes.  For new sinter plant windboxes, U.S. EPA proposed limits of 3.1E-09 lbs/ton of sinter for D/F (TEQ) and 1.5E-03 lbs/ton of sinter.

Fenceline Monitoring

U.S. EPA has proposed that facilities place four ambient air monitors at or near their fenceline at appropriate locations around the facility perimeter facility based on an approved site-specific plan. The ambient monitors will collect  samples every 6^th day for chromium analysis. Chromium was chosen as the pollutant to be measured because it was deemed a good surrogate for other HAP metals, including arsenic.   The proposed action level for chromium is 0.1 μg/m³ based on a 12-month rolling average “delta c” concentration. The delta c concentration is determined as the highest sample value for a given sample period, minus the lowest sample value measured during that period. If the delta c concentration 12-month rolling average is greater than the proposed action level, then the facility must conduct a root cause analysis and take corrective action to prevent additional exceedances.  The data from the fenceline monitoring will be reported through EPA’s CEDRI portal on a quarterly basis and will be available to the public via WebFIRE.

There is also a proposed sunset provision for fenceline monitoring. If the facility’s 12-month average value remains less than or equal to 50% of the proposed action level (0.1 μg/m³) for a 24-month period, the facility could discontinue fenceline monitoring as long as they continue to comply with all other requirements of the NESHAP.

Compliance Deadlines for the Proposed Additional Requirements

EPA’s proposed compliance dates for the new requirements are summarized below.

What’s Next?

There are multiple proposed compliance dates ranging from 6 months to 2 years after the promulgation date.  The compliance dates are dependent upon whether the proposed change will require installation of monitors, equipment, or new procedures. The comment period ended on September 14, and the final rule is expected to be signed in March 2024.

ALL4 staff are experienced in planning for and implementing updated air regulatory requirements, including fenceline monitoring. If you have any questions on this rule or would like help preparing for these new requirements, please contact Roy Rakiewicz at rrakeiwicz@all4inc.com or Michael Harris at mharris@all4inc.com.

Colorado’s GEMM Phase 2 Rule

The Colorado Department of Public Health and Environment (CDPHE) Air Pollution Control Division (Division) submitted a proposal for Phase 2 of the Greenhouse Gas Emissions and Energy Management for Manufacturing (GEMM) rulemaking (GEMM 2) to the Air Quality Control Commission during the September 21-22, 2023 meeting. The GEMM 2 rule was adopted on September 22, 2023. The new rule extends greenhouse gas (GHG) emissions reduction requirements to several facilities in Colorado’s industrial manufacturing sector.

What is GEMM?

GEMM is a regulation that was passed by the Colorado Air Quality Control Commission in October 2021 to help Colorado meet its GHG emissions reduction goals. Phase 1 of GEMM (GEMM 1) became effective on December 15, 2021 and applies to certain industrial facilities in Colorado with reported direct GHG emissions equal to or greater than 50,000 metric tons of carbon dioxide equivalent (CO₂e) per year. A list of the facilities subject to GEMM 1 can be found here.

GEMM 1 requires affected facilities to conduct an energy and GHG audit every 5 years, beginning in 2022, through 2037. The audit must demonstrate that the facility is using Best Available Control Technologies (BACT) for control of GHG emissions and Energy Best Management Practices (energy BMPs) to achieve an additional 5% reduction in GHG emissions.

What facilities are subject to GEMM 2?

GEMM 2 applies to manufacturing stationary sources in Colorado that generate 25,000 metric tons or more of CO₂e emissions per year. A list of the facilities subject to GEMM 2 can be found here.

The rule states that facilities subject to GEMM 2 will remain subject to the rule even if the facility reports less than 25,000 metric tons of CO₂e emissions for any year thereafter the facility became subject to GEMM 2. Once a facility becomes subject to GEMM 2, the facility will always be subject to GEMM 2.

What are the requirements of GEMM 2?

Beginning in 2024, GEMM 2 requires affected facilities to reduce their GHG emissions to a certain percentage below the GEMM 2 Facility GHG Baseline Emissions (Baseline Emissions). A facility’s Baseline Emissions are the higher reported direct GHG emissions from either the 2021 or 2022 calendar year. The required yearly GHG reduction percentages, as established in 5 CCR 1000-27, Part B, Tables 1-5, are based on a comparison of the facility’s reported 2015 GHG emissions to the Baseline Emissions.

For example, a facility’s 2015 GHG emissions were 40,000 metric tons of CO₂e, and their Baseline Emissions are 34,000 metric tons of CO₂e (i.e., a 15% reduction as compared to the 2015 GHG emissions). Pursuant to 5 CCR 1000-27, Part B, Table 2, for the years of 2024-2029, the facility must comply with a GHG emissions requirement of 1.25% less than the Baseline Emissions (i.e., 33,575 metric tons of CO₂e per year). In 2030 and beyond, the facility must meet a GHG emissions requirement of 7% less than the Baseline Emissions (i.e., 31,620 metric tons of CO₂e per year).

There are multiple ways that each facility could achieve the required GHG reduction. The first method is direct GHG reductions from the GEMM 2 facility. The facility must implement all technologically feasible and cost-effective reduction measures. If these measures do not achieve the required reduction, the facility may use additional offsite compliance options, such as purchasing GHG credits or achieving reductions at other industrial facilities located in Colorado that are owned and operated by the same company or one of its affiliates.

GEMM 2 also requires affected facilities to develop and submit a GHG Reduction Plan to the Division, along with an independent third-party evaluation and findings of the plan, no later than September 30, 2025 (except for glass container manufacturing facilities, which have a later compliance date). The independent third party is an engineering or consulting firm contracted by the State of Colorado that will review the GHG Reduction Plan for the accuracy and completeness of the plan, including but not limited to cost projections, assumptions and data sources, emissions impacts, and compliance with the GEMM 2 requirements. The GHG Reduction Plan must then be certified by the independent third party as adhering to the requirements of GEMM 2. The GHG Reduction Plan is also subject to a public comment period and at least three public meetings. The Division must issue an approval or request for modification of the GHG Reduction Plan by December 31, 2025.

If you have questions or need assistance determining GHG reduction strategies or planning for compliance with GEMM 2, please contact Sarah Raver at sraver@all4inc.com or (610) 422-1161.

Utah Division of Water Quality to Renew the Utah General Multi-Sector Industrial Storm Water Permit

Background:

The Utah General Multi-Sector Industrial Storm Water Permit (MSGP or Permit) under the Utah Pollutant Discharge Elimination system (UPDES) is required to be obtained by industrial facilities. The facilities include manufacturing facilities, mining operations, landfills, steam electric plants, automotive recyclers, waste and metal recycling, larger wastewater treatment plants, and transportation plants. This Permit covers all new and existing point source discharges of storm water to waters of the State in accordance with the eligibility and Notice of Intent (NOI) requirements, discharges point(s), effluent limitations, inspection and monitoring requirements, and other conditions set forth in the UPDES Permit.

This Permit covers the State of Utah except for Indian Lands. On Indian lands, the storm water Permit must then be acquired through the Environmental Protection Agency (EPA) Regions VIII and IX. This Permit became effective on January 1, 2019, and renews every five years based on groups made of sectors. Appendix I of the Multi-Sector General Permit for Storm Water Discharges Associated with Industrial Activities can be checked to determine your sector designation and the Permit coverage.

Changes:

There will be reorganizational changes made to the Permit, with some more significant changes in the renewal timeline. The groups mentioned are being discontinued, with all groups being merged and being required to report every five years following January 1 when this Permit becomes effective. All sectors and groups will need to renew after the 2028 expiration of this new Permit, whereas those with expiring Permits will need to renew after January 1, 2024.

What your facility needs to do?

When the Permit expires, the NOI must be recertified, or a new NOI submitted for continued permit coverage. Facilities affected will be required to renew their Permit to ensure authorized continued operation of discharging water. To be authorized to discharge water under this Permit, dischargers must submit a complete NOI using the NOI form that can be found on the Utah Department of Environmental Quality (DEQ) This includes paying the appropriate permit fee.

The Permit can be paid online using the NeT MSGP website now for the next year until 60 days after the Permit’s renewal on January 1, 2024. This is also the allotted time to renew the Permit.

Until a new Permit is issued, the expired general Permit will continue in force and effect if a timely reapplication is made for the new Permit (UAC R317-8-3.1(1)(d)). This process includes submitting a new or recertified NOI. Failure to submit the NOI within 30 days of the Permit’s expiration date will result in termination of coverage leading to a loss of authorization to discharge water in the State of Utah.

In the event that this Permit is not renewed by the Division of Water Quality, Permittees will be notified by the Director of the Division of Water Quality and provided instructions on how to stay in compliance with the Utah Water Quality Act and the Utah Wastewater Rules (UAC R317-8) with the discharge covered by this Permit.

New facilities that do not discharge any water will need to formally opt for exclusion from obtaining this Permit by submitting a No Discharge form and providing supporting documentation to the District of Water Quality. To terminate coverage under this Permit, a Notice of Termination (NOT) must be submitted to the District of Water Quality. Permittees who are no longer required to have permit coverage due to having a No Exposure Certification (NEC) or No Discharge Certification (NDC) under UAC R317-8-3.9 must submit a NOT. The NOT, NEC, and NDC can all be found on the State DEQ website.

New Facilities that do discharge water will need to apply online for permit coverage in N . The new facilities must prepare a Storm Water Pollution Prevention Plan (SWPP) prior to submitting the NOI, or before starting facility operations.

Next Steps for your Facility:

There will be a stakeholder review with more information hosted in November 2023, where more information can be found. In the meantime, updating or developing your SWPP should be started.

If you have any questions about stormwater permitting, SWPP planning, and how ALL4 can help, please contact your All4 project manager or call us at 610.933.5246 for more information on Storm Water Compliance.