What is the Texas Environmental, Health, and Safety Audit Privilege Act?

Enacted by the Texas Legislature and administered by the Texas Commission on Environmental Quality (TCEQ), the Texas Environmental, Health, and Safety Audit Privilege Act—the Audit Act for short—has been in effect since 1997, with the purpose to encourage voluntary compliance with environmental, health, and safety (EHS) laws. This act contains two main points:

• Providing immunity to the person (defined as an individual, corporation, partnership, or legal entity) from administrative or civil penalties for voluntarily disclosed EHS violations, and;
• Granting privilege to audit reports, protecting them from being used as evidence in civil or administrative proceedings.

These two privileges work together to encourage companies to be proactive with their compliance with environmental and occupational health and safety laws. The audits themselves can be rigorous and time consuming, as they assess a facility’s systems, processes, policies, and their compliance with regulatory standards. Ultimately, acting in accordance with the Audit Act allows companies to disclose and correct EHS violations in good faith on a more forgiving—yet reasonable—timeline and without fear of fines.

How do I take part in the Audit Act?

There are two required portions to participate in the Audit Act: the Notice of Audit (NOA) and the Disclosure of Violation (DOV), both of which are not privileged documents and are available to the public. The NOA is the letter that a person must submit to TCEQ before beginning an environmental audit to make use of the immunity granted by the Audit Act. Although audit reports hold the privilege provided by the Audit Act, documents, reports, and data required to be collected, developed, maintained, or reported under State or Federal law are still available to government bodies for review, and can be requested by the public. Additionally, the privilege provided by the Act does not apply to criminal proceedings. Once the audit commences, the person has six months to complete the audit and send a DOV to TCEQ, unless they have received a Request for Extension (RFE) approved by TCEQ. Ideally, the audit investigation would be as thorough as possible; any violations discovered by TCEQ that were not self-disclosed are not eligible for any privileges or immunities.

The DOV is the disclosure that promptly follows the completion of an environmental audit, detailing the dates, descriptions, and durations of any violations discovered, as well as the status and schedule for corrective actions. The privileges and immunities provided by the Audit Act are only granted if, among other things, the person does not conduct the audit in bad faith, the person making the disclosure makes appropriate efforts to achieve compliance, the person pursues those efforts with due diligence, and corrects the noncompliance within a reasonable time.

A person may submit an RFE—a letter requesting to extend the six-month period allowed for the completion of the audit—before the audit is completed and must include adequate details for TCEQ to determine whether a request is reasonable.

What if I just acquired a facility that is in the middle of an audit?

If an audit has started before the acquisition closing date, a NOA is not required; instead, a letter notifying TCEQ that the audit is continuing must be sent. If an audit is completed before an acquisition, then a DOV must be sent within 45 days of the acquisition closing date. If an RFE is submitted before the acquisition, it must also include a description of the relationship between the buyer and the seller.

How might the privileges be waived?

Audit privilege under the Audit Act does not apply to disclosures made to federal agencies, such as the United States Environmental Protection Agency, and such disclosure may waive the privilege. Additionally, audit reports submitted to TCEQ cannot be claimed as confidential.

How can ALL4 help?

ALL4 can provide EHS audits and assist in complying with the Audit Act, allowing you to look deeper to see if there are any EHS issues that need to be disclosed to TCEQ and subsequently corrected. If you would like to learn more, please contact Patrick Salvanera at psalvanera@all4inc.com for more information.

Understanding New York’s Shift from Dialogue to Enforcement of CLCPA Conformity in Air Permitting

Updates to the Enforcement of CLCPA Conformity

New York State’s Department of Environmental Conservation (NYSDEC) and its Division of Air Resources (DAR) are strengthening their enforcement of greenhouse gas (GHG) emissions targets in the Empire State with recent updates to the air permitting guidelines under the Climate Leadership and Community Protection Act (CLCPA). For background, ALL4 has previously discussed the CLCPA here.

In the past, NYSDEC allowed flexibility in CLCPA compliance demonstrations, often accepting a discussion of potential project design considerations or emissions mitigation strategies in lieu of enforceable mitigation measures. With the approaching 2030 and 2040 target dates for emissions reductions approaching, NYSDEC is transitioning from dialogue to active enforcement of CLCPA conformity for air permitting. The proposed measures which were treated as non-binding in the past are now expected to be implemented so that the State can reach its emissions reduction goals. Failure to demonstrate concrete, enforceable reductions in GHG or co-pollutant emissions, particularly in or near Disadvantaged Communities (DACs), can result in a notice of incomplete application (NOIA) or a rejection of a permit application. ALL4 anticipates that this active enforcement obligation will become a mechanism to ensure compliance with CLCPA objectives as well as a tool to incentivize renewable energy adoption and to dis-incentivize fossil fuel infrastructure development. In short, NYSDEC is no longer treating GHG mitigation strategies as an aspiration, but rather as a mandatory requirement for Air State Facility and Title V major stationary source permits.

An example of this recent shift in NYSDEC’s overall enforcement strategy can be observed in the 2024 updates to the CLCPA conformity criteria established in NYSDEC Guidance Documents DAR-21 and DEP 24-1. These changes reflect a broader regulatory shift away from aspirational, ad hoc evaluations toward enforceable standards that more closely align with the state’s aggressive decarbonization goals. DAR-21 addresses air permitting conformity with Section 7(2) of the CLCPA while DEP 24-1 addresses environmental justice (EJ) conformity with Section 7(3). Changes to the DAR-21 guidance are analogous to the methods used to determine applicability under Federal New Source Review (NSR) regulations and include mandating the quantification of both direct and upstream GHG emissions using projected actual and potential to emit (PTE) calculations, along with comparisons to existing baseline emissions. With the promulgation of DEP 24-1, NYSDEC has formalized the process for conducting a qualitative and quantitative disproportionate burden analysis for projects impacting DACs. Applicants with facilities adjacent to or within DAC census blocks must now assess how project emissions may contribute to existing environmental and health burdens using NYSDEC-defined indicators. After assessing these impacts, the NYSDEC may require design changes and mitigation approaches to lessen these burdens and reduce GHG emissions prior to authorizing the construction of a project or a renewal of an existing permit.

Project Scoping for Affected Facilities

To address the requirements of the CLCPA, it is essential to have a strategic approach to minimize the risk of regulatory non-compliance and to increase the chance for permit approval. ALL4’s approach to project scoping under the CLCPA begins with having a clear understanding of applicability across different facility types and permit actions. All applicants should first determine if they are subject to the regulations of Section 7(2) or 7(3) of the CLCPA. This defines the specific compliance obligations and emissions mitigation requirements of a project. Early in project scoping, applicants should ask critical questions to evaluate CLCPA conformity, such as is the project consistent with statewide emissions reduction targets, are there project emissions increases near a DAC, and what feasible alternatives to the project could be implemented? If the project cannot demonstrate consistency with the CLCPA, applicants must evaluate justifications for the approval of the project such as essential public need (e.g., providing grid support) or lack of technologically or economically feasible renewable technologies. ALL4 can identify these obligations early on in the project scoping process to ensure all parties involved can properly allocate the necessary resources and strategy for the project.

How can ALL4 help?

NYSDEC’s decision to approve or reject an air permit application is contingent on the project’s demonstration of conformity with the CLCPA. A recent shift in the agency’s guidance for air permitting and EJ policies means that NYSDEC is no longer treating GHG mitigation strategies as an aspiration, but rather as a mandatory requirement for Air State Facility and Title V major stationary source permits. ALL4 is equipped with the resources and expertise to ensure that our clients remain compliant with the updated CLCPA guidelines throughout all permitting processes.

ALL4 can support decision-making on project feasibility and can help deliver strong pre-project strategies to enable applicants to reach permit approval as smoothly as possible. From early planning and scoping to full implementation of design considerations and mitigation strategies, ALL4 can guide our clients through the permit approval process with an emphasis on quality work products that align with project and State objectives. Ultimately, successful scoping requires a proactive approach that integrates CLCPA compliance from the onset. Assessing regulatory applicability, evaluating community impacts, and defining plans for emissions mitigation will be necessary to advance projects in the State of New York as NYSDEC strengthens its enforcement of the CLCPA. For inquiries about how the proposed New York legislation may impact your facility or organization, contact Daniel Brese at dbrese@all4inc.com or your ALL4 project manager.

2025 Fire Code and Hazardous Material Reporting

As industrial and commercial facilities continue to handle a wide range of hazardous materials, understanding and complying with fire code requirements is more critical than ever. This article highlights key takeaways from a recent presentation — featuring ALL4 consultants Eli Waddell and Meredith Pedraza — on fire code standards, permitting obligations, and hazardous material reporting.

International Fire Code (IFC) and Local Application

The International Fire Code (IFC) sets minimum safety standards for fire prevention, protection, life safety, and the handling of hazardous materials. Developed by the International Code Council (ICC), the IFC is updated every three years and is supported by related I-Codes including building, mechanical, plumbing, and electrical. Unlike the National Fire Protection Association (NFPA), which provide several standards that are focused on specific operations, hazards, or fire protection methods and equipment, the IFC provides broader regulations pertaining to a building’s construction and occupancy, especially concerning hazardous material storage and use.

The IFC has been adopted by 41 states and many municipalities, often with localized modifications. However, jurisdictions may claim adoption of the IFC without having effective permitting systems in place, making local enforcement and compliance complex. California, for example, has adopted its own code nearly identical to the IFC.

Understanding Group H Occupancies and Thresholds

Facilities must track the types and quantities of their hazardous materials to ensure they stay below the limit for each hazard category, known as a Maximum Allowable Quantities (MAQs). If MAQs are exceeded within a given control area, the area may be reclassified as a Group H Occupancy (H-1 through H-5), each with increasing hazard levels and corresponding code requirements, such as:

• Mechanical ventilation
• Spill control and secondary containment
• Automatic fire suppression systems
• Standby power
• Fire rated walls and separations

Depending on the type of operation, there may be additional requirements that apply and the change in occupancy could have additional impacts on the buildings design and allowable area. Even outdoor areas and low-quantity storage must comply with specific guidelines if thresholds are approached.

Permitting Requirements

The IFC relies on local adoption and enforcement through two main types of permits:

• Construction Permits: Needed for installing or modifying fire systems or specific types of equipment, or for processes and areas where hazardous materials exceed permitting thresholds.
• Operational Permits: Required for ongoing activities involving hazardous materials or other regulated operations (totaling 57 distinct types under the IFC).

Permit applications often require submission of a Hazardous Materials Inventory Statement (HMIS) and, in some cases, a Hazardous Materials Management Plan (HMMP). Where quantities of hazardous materials exceed a corresponding MAQ, it is common for the City or Authority Having Jurisdiction (AHJ) to request a more detailed application, often including a Fire Code Technical Report, or even complete a conditional use permit application as part of the preliminary process.

HMIS and HMMP: Key Reporting Tools

The HMIS provides critical information for first responders and authorities by documenting:

• Product names and chemical composition
• Hazard classifications and storage/use quantities
• Locations and control area details

The HMMP, where required, includes business details, facility layouts, storage maps, and emergency contact information. Requirements vary by jurisdiction—some cities like Phoenix, AZ request HMMPs only upon inspection, while others like Scottsdale, AZ provide standardized forms.

California’s HMBP: A State-Specific Mandate

In California, facilities handling significant quantities of hazardous materials (equal to or greater than 55 gallons of liquids, 500 pounds of solids, or 200 cubic feet of gases) must submit a Hazardous Material Business Plan (HMBP) through the California Environmental Reporting System (CERS). The HMBP includes business info, hazardous inventory, emergency response plans, and site maps, and must be updated within 30 days of any significant operational change.

Final Thoughts and Compliance Tips

Accurate reporting is essential. Over-reporting may lead to unnecessary expenses and misclassification, while under-reporting can result in non-compliance, unsafe conditions, and legal liabilities. Understanding your local code, identifying applicable permit types, and accurately classifying materials are vital for operational safety and regulatory compliance.

How ALL4 Can Help

ALL4 provides full support for fire code and hazardous materials compliance, including:

• Preparing HMIS, HMMPs, and HMBPs
• Chemical classification and code evaluation
• Permitting coordination and fire code technical reports

For questions or support, contact: Eli Waddell – ewaddell@all4inc.com | 858.525.3656

U.S. EPA Proposes to Repeal Certain Provisions of the Mercury and Air Toxics Standards for Power Plants

On June 11, 2025, the United States Environmental Protection Agency (U.S. EPA) proposed to repeal certain provisions of the 2024 amendments to the National Emission Standards for Hazardous Air Pollutants (NESHAP) for Coal- and Oil-Fired Electric Utility Steam Generating Units (EGUs), also known as the Mercury and Air Toxics Standards (MATS). MATS includes standards to limit emissions of mercury, acid gas hazardous air pollutants (HAPs), non-mercury HAP metals, and organic HAPs from coal- and oil-fired EGUs. In the rule, an EGU is a fossil fuel-fired combustion unit of more than 25 megawatts (MW) that serves a generator that produces electricity for sale. A unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 MW electric output to any utility power distribution system for sale is also considered an EGU.  

What’s New? 

Broadly, the new Administration has announced a number of deregulation activities in response to several Presidential Executive Orders and U.S. EPA Administrator Lee Zeldin’s “Powering the Great American Comeback” initiative. Reconsideration of the 2024 MATS rulemaking was among the list of deregulation activities affecting fossil fuel-fired power plants.  

The recently proposed amendments to the MATS rule were published in the Federal Register on June 17, 2025. The rule proposes to repeal certain provisions of the 2024 MATS amendments. The 2024 MATS amendments were promulgated as part of U.S. EPA’s technology review for the source category and revised certain requirements promulgated in the original 2012 MATS rule. Technology reviews are conducted by U.S. EPA every eight years to assess whether there are developments in practices, process, and control technologies since the promulgation of the original standard. When deciding whether to revise the existing standards, U.S. EPA considers a number of factors including cost. The 2024 MATS amendments lowered the filterable particulate matter (fPM) emissions standard from 0.030 to 0.010 pounds per million British thermal units (lb/MMBtu) for existing coal-fired EGU, required the use of continuous emissions monitoring systems (CEMS) for demonstrating compliance with the fPM standard for coal- and oil-fired EFU, lowered the mercury emissions limit from 4.0 to 1.2 pounds per trillion British thermal units (lb/TBtu) for existing lignite-fired EGUs, and revised startup requirements. 

Specifically for fPM, which serves as a surrogate for non-mercury HAP, U.S. EPA proposes to revert to the 0.03 lb/MMBtu standard for existing coal-fired EGUs. This proposed revision also includes reverting the total and individual non-mercury HAP emissions standards to the levels in the 2012 rule because these standards had been proportionally lowered in the 2024 rule. U.S. EPA proposes these revisions citing both high total cost and high cost per mass emissions reduced (i.e., cost effectiveness). U.S. EPA noted that the cost effectiveness accepted in the 2024 MATS rule was higher than cost effectiveness values rejected in other technology reviews (e.g., Taconite Ore Processing, Petroleum Refinery Sector, Integrated Iron and Steel Manufacturing). 

The proposed rule would also reinstate the options for demonstrating compliance included in the original 2012 rule. The compliance options will once again include quarterly stack testing, and PM continuous parameter monitoring systems (CPMS) in addition to PM CEMS. U.S. EPA explained that in the 2024 rule, it was estimated that the compliance costs for stack testing at the lower limit would increase to the extent that it would be comparable to the cost of a CEMS when combined with the reduced costs of CEMS as compared to 2012. The 2024 rulemaking also noted that data transparency and public access to such data was an advantage of requiring CEMS. In its repeal, U.S. EPA noted that because the standard is proposed to be reverted to its original value, the cost of stack testing is not expected to increase and that stack testing data is publicly accessible on WebFIRE. As part of reinstating the various compliance demonstration options, U.S. EPA also proposes to reinstate the low emitting EGU (LEE) program for fPM and non-Hg HAP metals that provides a pathway for facilities electing to conduct stack testing to reduce their testing frequency.  

Finally, U.S. EPA proposes to revert to the 4.0 pounds mercury per trillion British thermal units (lb/TBtu) for existing lignite-fired EGUs, citing insufficient data to inform a lower standard and technical feasibility concerns regarding boiler, fuel, and control technology variability. 

Now what? 

This is just one of many rules that is expected to be reconsidered that will affect fossil fuel-fired power plants, and ALL4 is tracking them all. U.S. EPA will conduct a public hearing for the proposed MATS rule on July 10, 2025 and has opened a public comment period which will end on August 11, 2025. ALL4 can assist you with preparing comments on the proposed revisions, with stakeholder engagement meetings, and with evaluating the impact of the proposed rule on your facility. If you have questions about how the proposed MATS revisions could affect your facility’s program, or what your next steps should be, please reach out to your ALL4 project manager or to me at lpearce@all4inc.com. ALL4 is monitoring all updates published by U.S. EPA on this topic, and we are here to answer your questions and assist your facility with any aspects of MATS compliance. 

U.S. EPA Proposes to Repeal GHG Standards for Fossil Fuel-Fired Power Plants

On June 11, 2025, in response to President Trump’s energy-related Executive Orders, the United States Environmental Protection Agency (U.S. EPA) signed a proposal to repeal all greenhouse gas (GHG) emissions standards for fossil fuel-fired power plants. U.S. EPA also proposes to find that Clean Air Act (CAA) Section 111 requires the Agency to make a finding that GHG emissions from fossil fuel-fired power plants contribute significantly to dangerous air pollution before regulating GHG emissions from the source category. U.S. EPA states in this proposal that GHG emissions from this sector do not contribute significantly to dangerous air pollution within the meaning of the CAA. As an alternative, U.S. EPA is proposing to repeal a narrower set of requirements as discussed below. 

What rules are included in the proposal? 

The proposal seeks to repeal all GHG components of the following rules, based on a legal and technical reassessment of the underpinnings of U.S. EPA’s efforts to regulate GHG emissions from fossil fuel-fired power plants: 

• 40 CFR Part 60, Subpart TTTT: Standards of Performance (NSPS) for GHG Emissions from Electric Generating Units (fossil fuel-fired power plants, or EGUs), promulgated on October 23, 2015 

• 40 CFR Part 60, Subpart TTTTa: NSPS for GHG Emissions from Modified Coal-Fired EGUs and New and Reconstructed Stationary Combustion Turbine EGUs promulgated in the Carbon Pollution Standards (CPS) on May 9, 2024 

• 40 CFR Part 60, Subpart UUUUb: Emission Guidelines for GHG Emissions from Existing EGUs, also promulgated in the CPS on May 9, 2024. 

U.S. EPA is proposing to eliminate these standards, claiming the regulation of GHG emissions from U.S. fossil fuel-fired power plants would not have a significant effect on GHG air pollution and GHG emissions. They believe the current regulations are overburdensome because U.S. fossil fuel-fired power plants are a small and decreasing part of global GHG emissions and the control measures required under the rules are not reasonably available. U.S. EPA’s goal for this regulation is driven by this Administration’s priority of energy dominance and independence.  

Alternatively, U.S. EPA proposes to repeal only the following elements of the above subparts: 

• Emissions guidelines for existing fossil fuel-fired EGUs, 

• Carbon capture and storage (CCS)-based standards for coal-fired steam generating units undertaking a large modification, and 

• CCS-based standards for new base load stationary combustion turbines. 

This alternate proposal is based on a review of the Best System of Emission Reduction (BSER) for the source category. U.S. EPA proposes that 90% CCS is not BSER for existing long-term coal-fired EGUs or for new base load combustion turbines because it is neither adequately demonstrated or cost-reasonable, and that 40% gas co-firing is not BSER for existing medium-term coal-fired EGUs because it is an inefficient use of natural gas and is impermissible generation shifting.  

Does this mean fossil fuel-fired power plants’ GHG emissions will no longer be regulated? 

If the proposal is finalized and survives legal action, fossil fuel-fired power plants will have no or very limited carbon dioxide (CO2) or other GHG emissions standards.  

There are GHG emissions reporting requirements other than the standards in 40 CFR Part 60 that will remain in place for now. Unless and until U.S. EPA repeals its Mandatory GHG Reporting Rule, power plants will still need to comply with 40 CFR Part 98 and any state-level GHG emissions standards, reporting programs, or reduction programs, such as those in place in New York, Oregon, Washington, and California that remain in effect.  

What does this mean for power plants and carbon reduction strategies? 

The proposal, if finalized, will ease short-term federal regulatory burdens such as the following: 

• GHG emissions standards for fossil fuel-fired combustion turbines 

• CCS requirements for coal-fired electricity generating units (EGU)  

• Periodic GHG performance reports under NSPS 

Although the current U.S. EPA seems determined to roll back GHG emissions-related requirements, owners of fossil fuel-fired power plants should not necessarily interpret this as a signal to pause or slow down GHG planning, especially given the unknowns around whether a final rule would be stayed or survive litigation, what GHG emissions standards a future administration may establish, the economic implications of continuing to operate certain fossil fuel-fired resources, the evolving state of energy technology, and the fact that many energy companies have already committed to carbon reduction plans. Instead, this is a strategic moment to reassess, adapt, and future-proof energy generation and carbon reduction approaches. 

What is next? 

Because energy is a priority for this administration, we expect that U.S. EPA will finalize their determinations fairly quickly after reviewing comments received on the proposal. However, it is certain that U.S. EPA’s final action will be litigated, and it is possible that a court would stay any final action that eliminates the GHG emissions standards, pending the outcome of such litigation. Companies submitting permit applications for energy projects will have to watch the regulatory and legal developments closely.  

U.S. EPA is currently accepting comments on the proposed action until August 7, 2025. Comments can be submitted at https://www.regulations.gov/ or via email (a-and-r-docket@epa.gov with the docket number EPA-HQ-OAR-2025-0124 in the subject line). There will also be a public hearing held on July 8, 2025 starting at 11 am ET and the public hearing registration link will be posted on U.S. EPA’s website. 

Need help understanding how this affects you? 

If you are wondering how this proposal will affect your facility or ongoing projects directly, please reach out to your ALL4 project manager or contact me at lshaffer@all4inc.com.

Update on the California Climate Disclosure Laws

The California Air Resources Board (CARB) hosted a virtual workshop, which was open to the public, to discuss the state’s climate disclosure laws on May 29, 2025. The two climate disclosure laws are the Corporate Climate Data Accountability Act (commonly known as Senate Bill 253 or SB 253) and the Climate-Related Financial Risk Act (SB 261). These laws were passed in 2023 and compliance deadlines for both laws are rapidly approaching, in 2026. The workshop attendance reflected the level of interest in these laws with more than 3,000 stakeholders participating from several continents and pushed the meeting well beyond the scheduled three-hour duration. 

The purpose of the workshop was for CARB to present an overview of the laws, provide a summary of the process being followed to develop regulations, and to provide an opportunity for public comment. The workshop also included a presentation by Montrose Environmental, summarizing a study performed for CARB to review climate disclosure regulations from other jurisdictions around the world, and a presentation by the University of California, Los Angeles (UCLA) Anderson School of Management summarizing the state of corporate sustainability disclosure. 

As ALL4 has posted previously on the California climate disclosure laws (see the January 6, 2025 article and the February 26, 2025 webinar recording), the Climate Accountability Package is comprised of the following laws: 

• Climate Corporate Data Accountability Act, or SB-253, requires the disclosure of Scopes 1, 2, and 3 of greenhouse gas (GHG) emissions by reporting entities, public or private, doing business in California with $1 billion or more in gross annual revenue. Reporting for Scopes 1 and 2 will be required in 2026, based on 2025 data, and reporting for Scope 3 will be required in 2027, based on 2026 data. The reporting deadline for SB 253 will be set by the pending CARB regulations. 

• Greenhouse Gases: Climate-Related Financial Risk, or SB-261, requires the disclosure of climate-change-associated financial risks by reporting entities, public or private, doing business in California with $500 million or more in gross annual revenue. In addition to the financial risks climate change poses, businesses must also disclose plans to address those risks. The first disclosure must be made available through the company’s website by January 1, 2026, and bi-annually thereafter. This deadline is in the law and cannot be changed by CARB. The disclosure must be prepared following the Task Force for Climate Related Financial Disclosure (TCFD) Guidance or a reporting framework, such as the International Sustainability Standards Board (ISSB) standards, which evolved from the TCFD. 

In 2024, the legislature amended the laws through SB 219, to provide administrative updates, add flexibility for parent-company level reporting, and extend the deadline for CARB’s regulatory development to July 1, 2025. However, according to the presentation during the CARB workshop, CARB will be working through the summer and fall of this year to develop the SB 253 regulations, with a timeline to finalize by the end of the year. CARB indicated in a December 5, 2024, Enforcement Notice that it will not take enforcement action on companies that make a good faith effort to report during the first year. 

One of the key points of the regulations is the definition of “doing business in California.” According to the SB 253 and SB 261 text, reporting or covered entities: 

means a partnership, corporation, limited liability company, or other business entity formed under the laws of this state, the laws of any other state of the United States or the District of Columbia, or under an act of the Congress of the United States with total annual revenues in excess of [one billion dollars ($1,000,000,000) for SB 253 and five hundred million United States dollars ($500,000,000) for SB 261] and that does business in California. Applicability shall be determined based on the reporting entity’s revenue for the prior fiscal year.   

During the workshop, CARB indicated that it is considering using the definition of “doing business” from the California Revenue and Tax Code (CRTC) section 23101. CARB did request comments on this approach.  

CARB also indicated that it is considering using the definition of gross receipts, as set forth in CRTC Section 25120(f)(2) for “total annual revenue.” CARB also requested comments from stakeholders on this approach. 

Next Steps 

Based on the CARB Workshop, companies that may be affected by the legislation and CARB regulations should continue to follow this issue closely. Companies that are potentially affected by the California laws should be making “good-faith” efforts and taking action now to comply with the reporting requirements. This will include collecting GHG and climate risk data for 2025 and beginning the process of performing a climate-related risk analysis, following the TCFD guidance.  

Many companies have already begun or are well on the way to quantifying Scope 1 and 2 GHG emissions as a result of other market pressures. Of the two regulations SB 261 is a heavier lift, with a near term defined due date of January 1, 2026. Therefore, ALL4 recommends focusing on SB261 first, for those companies that qualify. The good news is that while the effort to develop a TCFD compliant Climate Financial Risk Disclosure is not insignificant, the work is critical to business risk and opportunity quantification and planning and can be beneficial. For example, understanding the physical risks to assets, operations, market access, and supply chains posed by climate forces – such as extreme heat, wildfires, hurricanes, water stress, and floods is a critical element of good risk management practices and an obligation of fiduciaries.  

Companies should also familiarize themselves with applicable frameworks such as the GHG Protocol, the TCFD Guidance, and the Climate-Related Disclosure standards of the ISSB. This will help companies prepare for whatever regulations are finalized. Look to ALL4 to keep you updated through our 4 The Record Articles and Insights. 

If your company needs assistance with determining applicability for the California regulations, GHG data collection, performing a climate-related risk analysis, or doesn’t know where to start, we’re here to help. Feel free to reach out to Daryl Whitt at dwhitt@all4inc.com or 864.894.1312, or James Giannantonio at jgiannantonio@all4inc.com.  

Best Practices for Importing Data into Digital Tools

The ability to import and export bulk data in digital tools is key for administrators to be able to add, modify, and extract multiple records in the tool quickly and efficiently.

Having and adhering to best practices when using this powerful capability is critical to reduce risk and increase accuracy when importing and exporting data. This article looks at some best practices to consider when using these processes. 

Use an Example or Test Case 

Ensure you understand how the data import works by using an example or test set. Select a specific record to test with or add a test record to the system. Export these records and tweak them in a few places to test how the import will modify the record(s). Add a new test record in the file to assess how new records will be imported to the system. Then import the adjusted file to confirm your understanding of the import. 

Remove Any Unnecessary Fields from Import Data 

If you have any columns that will be null or will not be updated as part of the import, delete those columns from your data set. As long as the field is not required, the records should be able to import without these columns. This approach minimizes the risk of accidentally modifying data that is not intended to be updated as part of the import. 

Remove any Unnecessary Rows 

Certain types of imports will overwrite the data that is already in the system. If you have any data records you are not intending to change, delete those from the import. This approach minimizes the risk of accidentally modifying data that is not intended to be updated as part of the import. 

Export a Backup Copy of the Table Data before Starting the Imports 

Save a set of data from all the tables that you will be modifying. An archived copy of the data allows you to look back at what the data was before you made the changes. It also gives you a way to reset any records you might accidentally modify. 

Save Your Export and Import Files in a Specific Place and Label Clearly 

If you are doing multiple rounds of imports, the best practice is to keep the backup copies and import copies in specifically labelled folders with clear names on the files. Clear file names help you select the correct file to import into each table. If you are doing multiple rounds of imports, labelling the folder where you are saving the files assists in referencing the history of the imports. 

Order of Operations 

If you are importing data into linked tables, there is often an order of operations you need to follow to successfully import the data. For example, if you are importing into a table of equipment property values, each row of which reference a record in the master equipment table, you will likely need to import updates to the equipment table first, then the equipment property values table. 

Keep a Checklist 

A checklist is key if you are importing data into multiple tables to ensure no steps are skipped in the import process. A checklist also documents the order of operations, increasing the efficiency of the import by reducing the risk of error from linked values that do not exist. A checklist makes the import process smoother, more repeatable, and more accurate. 

Use Error Reports 

Most systems automatically generate error reports. The error report lists one error for each line that did not successfully import. Use this tool to review whether your import worked correctly and to revise the import file and retry the import if necessary. 

Verify Data through the User Interface 

Review imported data through the user interface or front end. Checking in the user interface can reveal if any mismatches have occurred between values that are expected and what was imported. 

These best practices empower administrators to add or modify large amounts of data efficiently while reducing the risk of unintended consequences. If you are looking for a partner and advisor who can help administer or implement digital tools, ALL4 can help with implementation and ongoing support. Contact Julie Taccino at jtaccino@all4inc.com for more information.

So You Have To Do A Stack Test…

This article will briefly describe some best practices to determine particulate matter (PM) emissions using United States Environmental Protection Agency (U.S. EPA) Methods 5 and 202 for filterable particulate matter (FPM) and condensable particulate matter (CPM), respectively. The best practices provided below address sensitivity, contamination, representativeness, and consistency of implementation. While this article focuses on particulate matter, the concepts presented are applicable to source testing in general, regardless of the analyte or methodology.

Background

Particulate matter in stationary source emissions is determined gravimetrically. That is, gas is withdrawn from the duct and passed through a filter. The weight gain on the filter is related to the volume of gas withdrawn to determine FPM loading. This approach (i.e., Method 5) is completed by rinsing the sampling system upstream of the filter and combining the weight gain from the rinse with the weight gain from the filter. Determination of CPM is completed by measuring any matter that condenses after the filter. This is done in a (nominally) dry impinger. CPM is recovered by a rinse of the appropriate contact surfaces with water and with solvent.

Best Practices

Sensitivity

The result of the measurement should be in a robust portion of the analytical system. Any analytical system has upper and lower thresholds (think about measuring length with a yard-stick, anything below ~¼ inch and above ~35 ¾ inches is outside the meaningful measurement range). So, we want the results of our measurement to be in a well-characterized portion of the analytical range. And if the results are below that level, we want to feel confident that the conclusion around our decision point is minimally impacted by the uncertainty associated with measurements near zero. This is accomplished by collecting enough sample gas during testing to put the decision point (i.e., the emissions limit) an order of magnitude above the detection limit. Here’s an example calculation to illustrate this concept:

• Target limit: 0.02 lb/hr
• Gas flow rate: 12,000 scfm
• Method detection limit (MDL): 2 mg/sample (this is for Methods 5/202 – the detection limit or DL is 0.5 mg/fraction and there are 4 fractions in a sample train).
• Targeted mass: 20 mg/sample (one order of magnitude increase from MDL)
• Calculations:
  • 2 lb/hr à 1.5 g/min
  • 5 g/min and 15,000 scfm à 0.00013 g/cf or 0.13 mg/cf
  • To get 20 mg in a train, 20 mg and 0.13 mg/cf à 180 scf
  • Because the sampling rate is 0.75 cfm (typical for M5 sampling), we want to sample for 240 minutes, or 4 hours.

The result from this calculation must guide the sampling specifications, to ensure the data are usable for the intended purpose.

Contamination

As described above, emissions may be very near the lower threshold of the measurement system. As such, it is imperative that background and contamination be minimized:

• Reagent selection: Use high quality reagents. For a stand-alone test program, consider using unopened reagent bottles.
• Media selection: Use high-quality quartz filters only.
• Document glassware system cleaning activities.
• Collect and analyze blank samples. These can include proof blanks, field blanks, reagent blanks, media blanks.

Representativeness

It is crucial that any testing be conducted under the appropriate operating conditions:

• Operating conditions should be specified, numerically, in advance, in more detail than “within 10% of full load”. For example, “4500 watts” or “22 gpm of fuel flow”.
• Operating conditions are often reflected in stack gas volumetric flow rate; verify that the flow rate is as expected.
• Communication between all parties is necessary; the test planner needs to communicate with the facility operator and the stack tester.
• Define and understand steady state before testing commences; wait the appropriate and necessary times.
• If a test occurs after any kind of delay (overnight, for example), return facility operations as closely as possible to the earlier operating scenario.
• Any field-expedient changes (e.g., not achieving targeted load) need to be made carefully and documented appropriately.

Consistency of Implementation

At first glance, every test effort is a standalone effort. Resources are mobilized and testing happens in a fairly short timeframe (i.e., hours or days). Retesting can be another standalone effort. It can be problematic if testing devolves from a demonstration of compliance to a diagnosis of unexpected results. This type of situation can be minimized with the following considerations:

• Address all the issues above (sensitivity, contamination, representativeness) before the initial test effort. Don’t change the approach without a valid reason; document differences between subsequent test efforts.
• Do not change reagents or media. Ask the testing firm to acquire media and reagents specific to your program and to use them for all testing efforts.
• Do not change human resources. As best possible, use the same facility operations personnel and the same test personnel.
• Ambient conditions change. Review testing and operational details to minimize any differences due to weather.

ALL4 has decades of experience with simple and complex stack testing efforts, from concept through planning, execution, and interpretation of data. If you have any questions, please contact Gene Youngerman at 512.649.2571 or eyoungerman@all4inc.com.

How To Develop A Regulatory Compliant QA/QC Program For Your CMS – Part 1

During a regulatory inspection or audit you may be asked to provide a Quality Assurance/Quality Control (QA/QC) Plan for your Continuous Monitoring System (CMS). You provide the QA/QC Plan, and the inspector/auditor determines that the QA/QC Plan is robust enough or has an ample number of pages and checks the box that the facility has a QA/QC Plan for their CMS. But does simply having a QA/QC Plan satisfy the regulatory requirement? The regulatory requirement for a QA/QC Plan is primarily driven by 40 CFR Part 60, Appendix F, Procedure 1 for Continuous Emissions Monitoring Systems (CEMS) [Appendix F (P1)] and Procedure 3 for Continuous Opacity Monitoring Systems (COMS) [Appendix F (P3)]. Of course, there are similar requirements in applicable General Provisions and/or specific Subparts which we will explore later. But where does a regulatory requirement actually say that a QA/QC Plan is necessary for your CMS? See Appendix F (P1) §3.0 [with similar language in Appendix F (P3) §9.0]:

“Each source owner or operator must develop and implement a QC program. As a minimum, each QC program must include written procedures which should describe in detail, complete, step-by-step procedures and operations for each of the following activities…”

Let’s explore these (and similar) requirements that will be the focus of an upcoming series of ALL4 4 The Record articles on CMS. The series on QC Programs for CMS will include:

1. Terminology – Where is the QA? I am as guilty as the next person who interchangeably uses QA and QC. In fact, saying QC just feels wrong because I have been misusing the terms for so long. So, I guess it is time that we all change the way we use QA and QC. The proper use of the terms QA and QC is further discussed in this article.
2. Requirements – Where is the requirement for a QA/QC Plan? What is the requirement for a QA/QC Plan? There is a clear connection between written procedures and plans, but the more important requirement is in the terminology of develop, implement, and program. Does just having a QA/QC Plan for your CEMS make it a program that is implemented? How do we assess compliance with terms like implemented? That sounds like a great topic for an upcoming article on QC Programs.
3. Nuances – There may not be much ambiguity about written, but what about detail, complete, step-by-step? Developing detail[ed], complete, step-by-step procedures (based on your interpretation) can take a lot of effort and iterations. Should the procedures be detailed and complete enough so I can give them to someone off the street to complete the QC activities for my CMS? Another great topic for an upcoming article on QC Programs for CMS.
4. Miscellaneous – With anything, there are a lot of caveats and other things to consider. Wrapping up those items warrants an article as well!

But for this first 4 The Record article on QC Programs for CMS, let’s explore the terminology QA and QC.

What is QA/QC?

The terms QA and QC are often used interchangeably, but let’s explore the difference. QC, which stands for Quality Control, can be defined as activities performed to provide a reproducible quality product. It addresses how the facility will handle issues that arise with the CMS. One example of a QC activity is corrective maintenance. Corrective maintenance should be performed if an issue arises with the CMS [e.g., a cylinder gas audit (CGA) fails, a daily validation exceeds the allowable drift limit, etc.]. It is performed to ensure data quality is not compromised following an issue with the CMS. After the corrective maintenance is completed, additional QC activities such as an analyzer calibration and/or calibration drift test need to be completed. In addition, QC activities are typically performed by a person who works at the facility and include activities during the CMS procurement, certification, and ongoing operation. QC activities are sometimes referred to as internal quality control.

QA, which stands for Quality Assurance, can be defined as activities implemented to ensure quality control activities are being performed adequately. QA addresses how the facility can be confident that the data produced by the CMS is accurate and reliable. One example of a QA activity is a CGA for CEMS. Once every quarter, an audit gas containing a pollutant of known concentration is injected into the system at two different audit points three times each and read by the analyzer to assess if the analyzer is providing accurate readings. If the readings are within the specification, the analyzer is correctly measuring concentrations of that particular pollutant. This is an example of quality assurance because the activity is performed for the purpose of confirming the reliability of the data. In addition, it may be performed by a third party (not a regulatory requirement) – someone outside of the normal routine operations. This is another indication of a QA activity, which is sometimes referred to as external quality control.

QA and QC activities are both required to be implemented as part of a facility’s QA/QC Program (or QC Program). To support the program as opposed to the document, there must be written, detailed, step-by-step procedures and operations for the various required QA and QC activities at the facility. Many times this procedure is referred to as a QA/QC Plan or a Quality Assurance Plan (QAP). This document is part of the program that attempts to answer the two questions, “How can quality of data be assured?” (QA) and “What actions will be taken (implemented, revised, modified) to address issues with QA activities?” (QC).

Conclusion

In conclusion, QA/QC programs define QC activities (internal, first-step) and QA activities (internal or external, second-step, oversight) that frame oversight for collection of usable, understandable, meaningful data. As part of a QA/QC program, QA/QC Plans codify activities and responses necessary to maintain CMS data quality at acceptable levels. However, they are only part of the overall QA/QC program required at facilities with a CMS. The second part of this series will address the specific elements required in a QA/QC Program to execute a QC Program that is fully developed, implemented, and executed. ALL4’s CMS-focused team is committed to publishing several follow-up blogs for QA/QC Programs for CMS throughout 2025. If you have any CMS-related questions, need help assessing or updating a CMS QA/QC Program, or want to suggest additional topics please email Eric Swisher (eswisher@all4inc.com) or Corey Weiss (cweiss@all4inc.com).

CWA Hazardous Substances FRP: Implementation Delay Loading

ALL4 has been tracking the Clean Water Act (CWA) Hazardous Substances Facility Response Plan (FRP) rule since the proposed rule was published in 2022. The final rule was published last year, and even before the 2024 election, the U.S. Environmental Protection Agency (U.S. EPA) was raising the alarm that resources to implement the rule (or lack thereof) could result in implementation delays. In late 2024, U.S. EPA was targeting late 2025 to provide guidance on the rule, including the nebulous and extensive modeling requirements. Fast forward to mid-2025, following the change in administration, headcount reduction across the federal government, and industry pushback (including a letter from the Alliance for Chemical Distribution requesting recension of the rule, among others), implementation delay now appears certain.

What Do We Know?

Per an American Public Power Association article published in early June 2025, U.S. EPA plans to issue a notice soon that will extend the compliance deadline by up to five years. The notice may be issued as an interim final rule (IFR) which would become effective upon publication in the Federal Register. The current deadline for initially regulated facilities is June 1, 2027; a five-year delay would push that date to 2032.

According to the same article, U.S. EPA will issue a second notice, an advance notice of proposed rulemaking (ANPRM) seeking input on a number of changes to the rule, including:

• Changes or clarifications to definitions including adverse weather conditions and conveyance;
• Increasing the threshold quantity to the originally proposed 10,000x reportable quantity (RQ) rather than the 1,000x reportable quantity (RQ) in the final rule;
• Guidance on measuring the one-half mile screening criterion;
• Modifying requirements around modeling the impact of worst case discharges and the substantial harm certification form;
• Removing mention of environmental justice and climate change; and
• Modifying exemptions including substances covered by 40 CFR Part 112 (Oil Pollution Prevention Program) and “wastewater treated by privately owned treatment works under National Pollutant Discharge Elimination System Permits;”
• Changing how chemical reaction intermediates and byproducts are to be treated; and
• Changing FRP requirements.

Many of the proposed clarifications will be welcome news to those who have spent time attempting to decipher the rule and its applicability to their facilities.

Where Do We Go From Here?

ALL4 will continue tracking for updates and keeping our readers informed as U.S. EPA publishes notices related to the CWA Hazardous Substances FRP rule. If you have already begun applicability evaluations based on the current threshold quantities, we recommend completing those analyses and keeping them available and accessible for consideration in the future.

For more information on the current rule, check out ALL4’s previous blogs and webinars. If you have any questions, please reach out to me at lsmith@all4inc.com.