If your facility emits enough air pollution to cross federal thresholds, you need a Title V Operating Permit to legally operate. This guide covers who needs one, how the permit process works, and what it takes to stay in compliance once your permit is issued. Overview of Title V Operating Permits In 1990, Congress authorized the U.S. EPA to require stationary emission sources to obtain an operating permit under Title V of the Clean Air Act Amendments (CAAA). These permits categorize emission sources as minor or major sources, depending on their annual emissions of key pollutants like NOx, SO2, and CO. What does this mean for your facility? Major sources (100+ tons/year of criteria pollutants) face stricter monitoring and reporting requirements. Facilities must renew permits every five years and maintain compliance through continuous emissions tracking. If your permit requires hourly or minute-by-minute data, a Continuous Emissions Monitoring System (CEMS) is essential. Who Must Obtain a Title V Operating Permit? Several categories of facilities and emission sources are required to obtain a Title V Operating Permit. Major Sources Beyond the 100 tons per year threshold for criteria pollutants, a facility also qualifies as a major source if its potential to emit reaches: 10 tons per year of any single hazardous air pollutant (HAP) 25 tons per year of any combination of HAPs Thresholds can be lower in areas that fail to meet national ambient air quality standards, known as nonattainment areas. A facility below these thresholds is considered a minor source. Acid Rain Program "Affected Sources" The Acid Rain Program (40 CFR Part 75) was created to reduce SO2 and NOx from fossil fuel-fired power plants. Any emission source subject to Acid Rain rules must obtain a Title V permit regardless of size, whether it qualifies as a major source or not. Solid Waste Incineration Units Under Section 129 Clean Air Act Section 129 sets standards for solid waste incineration units. All units regulated under Section 129 are subject to Title V permitting regardless of size, including: Municipal waste combustors (large and small) Hospital, medical, and infectious waste incinerators Commercial and industrial solid waste incinerators Sewage sludge incinerators Other solid waste incinerators Non-Major Sources Subject to NESHAP or NSPS The National Emission Standards for Hazardous Air Pollutants (NESHAP, 40 CFR Parts 61 and 63) and New Source Performance Standards (NSPS, 40 CFR Part 60) regulate air pollutants from stationary sources. Sources subject to these standards generally need a Title V permit even if they fall below major source thresholds, although EPA has exempted some area source categories in specific NESHAP subparts. Check the subpart that applies to your facility. How Do I Obtain a Title V Permit for My Facility? If your facility is required to obtain a Title V permit, start with your state or local air pollution control agency. The process generally follows these steps: You submit a permit application, and the permitting authority prepares a draft permit. The draft permit is opened to public comment for 30 days. The permitting authority sends the proposed permit to EPA, which has 45 days to review it and object if it does not meet Clean Air Act requirements. If EPA does not object, the public has 60 days to petition EPA to object. If EPA objects, the permitting authority has 90 days to revise the permit and resubmit. Once issued, the work shifts from obtaining the permit to demonstrating compliance with it. How Do You Demonstrate Title V Compliance? Your permit spells out exactly how your facility must prove it is meeting its emission limits. For most Title V sources, compliance comes down to three things: continuous monitoring, periodic testing, and reporting. Continuous Emissions Monitoring A CEMS paired with a Data Acquisition System (DAS) collects, validates, and stores the emissions data your permit requires, and generates the reports your permitting authority expects to see. Stack Testing Many Title V permits require periodic performance testing, commonly called stack testing, to demonstrate that emission units meet their permitted limits. Testing follows EPA Reference Methods (40 CFR Part 60, Appendix A) and typically covers pollutants such as particulate matter, NOx, SO2, CO, and volatile organic compounds. Facilities operating CEMS also need Relative Accuracy Test Audits (RATAs) to verify monitor accuracy under Part 60 Appendix F or Part 75. Test protocols, agency notifications, and final test reports all carry deadlines tied to your permit conditions, so scheduling matters. Reporting and Recordkeeping Title V facilities must submit monitoring reports at least every six months and an annual compliance certification signed by a responsible official. Any deviations from permit conditions must be reported promptly, and supporting records are typically retained for at least five years. How Can Alliance Technical Group Help You Comply With Your Title V Permit? Alliance Technical Group is a full suite provider for Title V compliance, from testing at the stack to the data and reports your permit requires: Stack Testing: As the largest stack testing provider in the U.S., Alliance performs the compliance tests, performance tests, and RATAs your permit requires. CEMS and DAS: Alliance offers a full suite of CEMS hardware and DAS software, including StackVision and the 8864 Data Controller, plus ongoing maintenance and support. StackVision helps run real-time emissions reports to meet air permit requirements. Managing different permit conditions across multiple sites is complex, but StackVision simplifies compliance by centralizing emissions data and automating reports. As a full suite provider, Alliance also supports the reporting side of your permit, helping keep semiannual monitoring reports and compliance certifications on schedule.

A Data Acquisition System — also called a Data Acquisition and Handling System (DAHS) — is software and hardware designed specifically to collect, validate, calculate, and store emissions data for regulatory compliance. It is the system of record for your facility’s air emissions reporting. If your facility operates a Continuous Emissions Monitoring System (CEMS), EPA regulations impose detailed, ongoing obligations on how your emissions data is collected, validated, calculated, and reported. Meeting those obligations accurately — without data gaps, documentation errors, or audit exposure — is harder than it sounds when you’re relying on general-purpose process systems or manual processes. A Data Acquisition System (DAS) is purpose-built to handle those requirements automatically. It’s not the only way to manage emissions data, but it’s the most reliable — and the approach used by the vast majority of regulated facilities for good reason. This guide breaks down what a DAS does, which regulations drive the need for one, how it compares to alternatives, and what Alliance Technical Group provides to regulated facilities across North America. What Does a Data Acquisition System Do? A purpose-built DAS handles the full scope of what compliant operation requires: Continuous data collection from analyzers, opacity monitors, and parametric monitoring equipment Daily calibration drift checks and automated recording, as required under 40 CFR Part 60 § 60.13 Real-time flagging of out-of-control periods and automatic application of data substitution procedures Quarterly audit tracking — RATA, CGA, and RAA — per Appendix F, Procedure 1 of Part 60 Emissions calculations using the specific methodologies your permit and applicable regulation require Long-term data storage with a complete, auditable record — minimum two years under Part 60 Compliance report generation and electronic submissions in agency-required formats, including ECMPS for Part 75 sources These are not optional features. They reflect the functions your CEMS must perform under federal and state regulation. A DAS is engineered around exactly those requirements. Which EPA Regulations Apply to Your Facility? The regulations don’t mandate a DAS by name — they mandate what your monitoring system must do. Use the table below to identify which regulations apply to your facility and what your CEMS is required to handle. Regulation Applies To Key CEMS Obligations Does Alliance's DAS Handle This? 40 CFR Part 60 (NSPS) Power plants, industrial boilers, cement kilns, glass furnaces, chemical plants, and other new source categories Continuous CEMS operation Daily calibration drift checks Documented out-of-control periods Quarterly accuracy audits (RATA/CGA/RAA) Written QC program 2-year minimum data retention Yes. Alliance’s DAS, StackVision, automates daily drift logging, flags out-of-control periods in real time, tracks quarterly audits, and retains your full data record. 40 CFR Part 75 (Acid Rain Program) Electric generating units and other affected units under the Acid Rain Program and NOx mass emission programs CEMS installation and certification Monitoring plan documentation and submission Missing data substitution procedures Quarterly electronic reporting via ECMPS RATAs and QA/QC per Appendix B Yes. Alliance configures StackVision for ECMPS 2.0 submissions (including the JSON format required), manages monitoring plan alignment, and applies correct Part 75 substitution methodology. 40 CFR Part 63 (NESHAP) Hazardous air pollutant sources across chemical manufacturing, petroleum refining, pulp and paper, glass, metals, and others CPMS/CEMS operation during all process conditions Defined handling of data during breakdowns, out-of-control periods, maintenance, and calibration Subpart-specific recordkeeping and reporting requirements Yes. Alliance configures StackVision to the specific NESHAP subpart applicable to your source category, including data handling requirements during out-of-control and maintenance periods. Your facility’s operating permit may also impose requirements more stringent than any federal baseline — tighter limits, additional monitoring obligations, or specific reporting formats driven by state or local air agencies. Alliance will configure your DAS to reflect your actual permit, not just the federal standard. Data Acquisition Systems vs. Alternatives Some facilities manage CEMS data through plant historians, distributed control systems (DCS), PLCs, or spreadsheet-based processes. The regulations don’t prohibit these approaches — but they create meaningful operational and compliance risk. What General-Purpose Systems Lack Plant historians and DCS platforms are engineered for process operations, not EPA compliance reporting. They collect data, but they are generally not built to: Apply EPA-specific emissions calculation methodologies for your source category and permit Automatically track out-of-control periods and apply the correct data substitution under Part 60 Appendix F or Part 75 Generate ECMPS-compliant quarterly submissions or other required electronic reports Maintain the QA/QC audit trail regulators review during inspections Flag calibration drift exceedances and document the required corrective response Building these functions into a process system requires custom engineering that your team then owns — and must maintain accurately as regulations and permits evolve. Where the Risk Shows Up The practical compliance risk isn’t always a hard violation on day one. It’s the accumulation of undocumented gaps — a missed drift check, the wrong substitution methodology applied, a report in a format the agency can’t process, or a data correction that was never re-submitted. These are the issues that surface during audits and cost facilities significant time and exposure. A purpose-built DAS removes most of that risk by design. The regulatory logic is built in and maintained by specialists who track regulatory changes. Your team operates the system rather than engineering it. Utilizing Alliance 's StackVision™ Data Acquisition System™ Ready to evaluate a DAS for your facility? Whether you’re replacing a legacy system, evaluating a DAS for the first time, or not sure if your current setup is still aligned with your permit — Alliance Technical Group can help you find out.

Accurate air emissions data is critical for regulatory compliance — even small discrepancies can lead to reporting issues, audits, and penalties. While daily and weekly data reviews are not required by regulations, they provide a proactive approach rather than a reactive one to any data discrepancies. What Does Your Emissions Data Include? Emissions data consists of hourly readings for measured parameters, calculated emissions values for each hour, calibration data for instruments, and summarized aggregate data. Your emissions file should cover one full calendar quarter of hourly and aggregate emissions measurements for a specific unit or group of units. This includes your: Monitoring Plan Quality Assurance (QA) files (such as linearity, RATA, Gross Calorific Value, and QA Certification Events) Any certification events related to CEMS maintenance. These events are necessary for activities like analyzer replacements, umbilical maintenance, or any other CEMS-related upkeep. Quarterly Reporting Tip: Don't wait until the end of the quarter to generate your quality assurance and emissions files. Instead, generate and review your EDR files regularly throughout the year. This allows you to break the quarter into smaller, manageable parts, helping you catch issues early and make the final submission process smoother. Alliance Technical Group's Regulatory & Reporting team offers daily and weekly data review services. Reviewing Emissions Data & Reporting With StackVision StackVision, Alliance Technical Group's Data Acquisition System (DAS), simplifies emissions monitoring by automating data collection, processing, and reporting while mitigating risks associated with using traditional tools. Challenge Solution Disorganized or Unclear Emissions Data — Analyzing emissions data across multiple systems including multiple spreadsheets can be complex and time-consuming, making it difficult to identify trends, discrepancies, or compliance risks. StackVision's Comprehensive Reporting Tools — StackVision offers a variety of automated reports that organize emissions data in an easy-to-read format. Users can select specific parameters and timeframes, making quarterly reporting reviews more efficient. Identifying Calibration and QA Issues Early — Undetected calibration failures or QA issues can lead to reporting errors and regulatory non-compliance. Daily Part 75 Review – Calibration Detail Report — Automatically compiles all calibration sequences — including daily calibrations, interference checks, and linearity checks. Problem values are color-coded for quick identification, ensuring immediate corrective action. Missed Data Gaps or Compliance Exceedances — Unnoticed missing data, exceedances, or out-of-control conditions can lead to compliance violations and inaccurate reporting. Exception Events Report — StackVision pulls detailed reports on missing data, exceedances, out-of-control events, invalid readings, and suspect data — helping facilities address issues proactively. Identifying Significant Changes in Emissions Data — Tracking emissions data trends can be difficult when you need to detect gradual shifts or anomalies, increasing the risk of compliance issues. Average Data Reports & Trending Reports — StackVision automatically calculates rolling and block averages (hourly, daily, monthly, yearly) to align with permit requirements. The Average Data Trending Report helps users quickly identify significant changes in data trends, allowing for early intervention and more proactive emissions management. Tracking and Managing Missing Data Substitutions — Part 75 mandates that all missing emissions data be properly substituted, which can be difficult to track. Missing Data Substitution Hours Report — Automatically monitors the number of substituted hours for a selected parameter, simplifying compliance tracking. Ensuring Stack Flow Monitoring Accuracy for Coal Plants — Failing a flow-to-load test at the end of the quarter can cause compliance delays and reporting errors. Daily Stack Flow Monitoring via ProcessNow — StackVision performs daily flow-to-load tests, ensuring continuous accuracy. Users can monitor test results and make adjustments throughout the quarter to prevent failures. Ensuring Compliance with Part 60 Opacity Monitoring — Opacity exceedances and downtime events must be carefully tracked to comply with Part 60 regulations. Opacity Matrix & Opacity Duration Reports — StackVision provides color-coded Opacity Matrix Reports, as well as automated Opacity Downtime & Exceedance Reports, making it easier to monitor and report required opacity data. Troubleshooting and Editing Data Efficiently — Sifting through emissions data for troubleshooting can be tedious and error-prone. DataLab for Advanced Data Analysis — StackVision's DataLab allows users to: ✔ View, edit, and export data to Excel ✔ Apply linear adjustments and perform data replacements ✔ Customize and save data views for faster daily reviews ✔ Use color-coded flags for quick anomaly detection Managing Large-Scale Data Processing for EDR Compliance — Ensuring that emissions data is correctly formatted and error-free for EPA/state reporting can be overwhelming. Automated Data Processing & Compliance Management — StackVision's ProcessNow feature transforms data into a reportable format. Data is assembled into the records necessary to build an EDR or any permit reports — ideally on a daily basis. Maintaining error-free processed data ensures an easily generated JSON EDR (or other reportable product) at the end of the quarter. Communication failures between your DAS and CEMS — Data loss and inaccuracies The industry-standard 8864 Data Controller — Acts as a powerful and reliable hardware bridge between StackVision and your emissions monitoring rack. The 8864 delivers consistent performance even in high-traffic and complex network environments, ensuring seamless data acquisition and protection. Client Success Story: Preventing Reporting Discrepancies One common reporting mistake occurs when data is modified after the official submission period without proper re-submission. Alliance Technical Group recently helped a facility that faced a discrepancy in their NOx Percent Monitor Data Availability (PMA). Their internal database showed a 95% PMA, while the EPA's records reflected only 80%. After investigation, it was discovered that data was reprocessed after the submission deadline, but the updated files were never sent to the EPA's Host System. Without correction, this type of oversight can lead to compliance issues or potential fines. How StackVision's Database Locking Wizard Helps Prevent Emissions Data Discrepancies To prevent these types of errors, StackVision provides a Database Locking Wizard, which allows facilities to lock down their emissions database after submitting reports. This ensures data integrity and prevents accidental modifications after the deadline. If adjustments are needed, users can unlock specific portions of the database in under five minutes. Be Proactive with Your Emissions Data Regular emissions data reviews help facilities stay ahead of potential issues rather than scrambling at the last minute. By using StackVision, facilities can streamline emissions data management, automate reporting, and reduce the risk of compliance errors. Want to see how StackVision can simplify emissions monitoring for your facility?

Refineries operate under some of the most demanding emissions monitoring requirements in the industry. The EPA's Refinery Sector Rule (RSR) sits at the top of that list — complex, data-intensive, and unforgiving when monitoring systems fall short. More than one-third of U.S. refineries — 35% — rely on StackVision as their data acquisition system (DAS). That's not coincidental. RSR compliance puts pressure on every part of a facility's monitoring infrastructure, and the right DAS is the difference between staying ahead of a deviation and scrambling to explain one. Here's what RSR actually demands, and how StackVision is built to handle it. What Is the Refinery Sector Rule? The Refinery Sector Rule (RSR) — codified under EPA 40 CFR Part 63 Subpart CC (MACT CC) — makes flare minimization a regulatory mandate. When regulated material does flow to the flare, facilities must monitor and report both the quantity and the destruction and removal efficiency (DRE) at which elevated flares operate: 96.5% combustion or 98% DRE. RSR also requires active monitoring and immediate response to maintain minimum efficiencies. On average, it quadruples the amount of data facilities are required to collect and report. Meeting those requirements without a capable DAS is, in practice, not feasible. Five RSR Requirements That Expose Gaps in Your Monitoring System 1. 15-Minute Block Averages and Full Algorithm Documentation The EPA requires facilities to measure and report key flare parameters: Net Heating Value of the Combustion Zone (NHVcz), Net Heating Value Dilution Parameter (NHVdil) when perimeter assist air is used, Flare Tip Velocity (Vtip), and Pilot Flame Presence and Visible Emissions (VE). Operating limits for NHVcz, NHVdil, and Vtip are based on 15-minute block averages calculated from multiple monitored inputs — flows, temperatures, pressures, and vent gas net heating value. Compliance is determined at the close of each 15-minute block, which demands a DAS that can handle real-time data reduction without gaps. The EPA also requires facilities to provide a copy of the DAS algorithm used to reduce measured data into reportable form. Invalid data — out-of-control periods, maintenance windows, CPMS breakdowns, calibration checks — must be excluded from compliance averages. If your DAS doesn't handle that automatically, you're responsible for documenting your own exclusion procedure. StackVision excludes invalid data in real-time as it's acquired, captures status codes, and provides a complete chain of calculations, data handling, and reduction. System design reports and full configuration control make algorithm documentation straightforward rather than a last-minute scramble. 2. Increased Quality Control Activities and Associated Recordkeeping RSR monitoring often means adding flow meters, analyzers, temperature monitors, and pressure sensors — sometimes in multiples across different streams. Many refineries use a gas chromatograph or mass spectrometer to determine vent gas net heating value, which introduces its own QC demands, including modified PS-9 calibration protocols that can require multiple calibration bottles per check. StackVision provides dedicated tools for monitoring the status of your monitoring systems: displays, reports, alarms, and notifications that catch flatlining before it becomes a data gap. It supports test record management, cylinder gas management, and automated calibration checks — reducing technician exposure and ensuring recordkeeping keeps pace with the monitoring workload. 3. Ready Access to Compliance Parameters for Operators The EPA requires that values from monitored operating parameters be readily accessible onsite for operational control and inspection. That means your operators need quality-assured data in front of them, not buried in a reporting system. StackVision delivers quality-assured values through operator displays and directly to the DCS and historian. Real-time feeds to the DCS allow operators to control flows manually or automatically. Alarms and notifications can be routed to Environmental, Operations, Controls, or any combination of internal teams — so the right people have the right data when they need it. 4. Reporting, Retaining, and Making Data Available Periodic RSR reports include emergency flaring events and deviations from operating limits. Getting to a completed report requires daily or weekly review, logging, coding, and investigation — followed by final compilation and submission. Moving large quantities of data from a historian into spreadsheets is slow and introduces error. Beyond reporting, all required values must be retained for five years, along with a substantial amount of contextual supporting data (per CFR Part 63 recordkeeping requirements). All of it must be available for inspection within 24 hours upon request. Spreadsheet-based systems aren't built for that kind of retrieval. StackVision automates scheduled reports, provides purpose-built displays, and keeps five-year-old data as accessible as data from yesterday. When an inspector asks for something, the answer isn't "we'll have to pull that together." 5. Emergency Flaring Limits — No Startup, Shutdown, or Malfunction Exceptions RSR's emergency flaring provisions hold most flares to the performance standard of the best-operating flares in the industry. Force Majeure events are excluded, but most other emergency flaring events that meet the EPA's criteria are treated as preventable — meaning operator error and poor maintenance are automatic violations with no leeway. That raises the stakes on every aspect of flare monitoring and QC. You need systems that respond to flaring events in real time, maintain continuous quality control, and produce meticulous records that hold up under scrutiny. StackVision provides the monitoring, alerting, and documentation tools to track and prove compliance — and to demonstrate that any deviation was not the result of poor maintenance or operator failure. StackVision Is Built for Refinery Compliance RSR doesn't leave room for monitoring systems that require manual workarounds, struggle to produce documentation on demand, or fall short during a 15-minute block. That's why 35% of U.S. refineries run StackVision. If your facility is navigating RSR requirements — or evaluating whether your current DAS is keeping pace — Alliance Technical Group's CEMS/DAS team can walk you through what StackVision does in a refinery environment.

The end of the year is the right time to get ahead of stack testing season — not the beginning of January when contractors are already booked and procurement is back-logged. Most of what makes Q1 testing go smoothly gets decided in Q4. This checklist covers the year-end actions that protect your compliance schedule, reduce last-minute scrambling, and set your CEMS up for a clean test season. 1. Audit Your Permit Testing Calendar Pull your Air Pollution Control Permit and identify every test requirement due in the upcoming year. Note the applicable regulation, the test method, the emission source, and any operating condition requirements that must be met during testing. This is the foundation — everything else on this list flows from knowing exactly what's due and when. Key things to confirm: Which emission points require testing and under which regulation (Part 60, Part 63, state permit) Whether any rule changes or ICRs issued this year added new testing requirements Deadlines for any initial compliance tests triggered by new or modified sources 2. Review Your RATA Frequency Status If your facility operates under Part 75, your RATA result from this year determines whether you test semi-annually or annually next year. Review your relative accuracy result now to confirm your testing frequency for the upcoming year and factor it into your scheduling decisions before you close out the year. 3. Schedule Your Q1 Testing Now — Before the Holidays Testing contractors book up quickly in January. Facilities that wait until the new year to start the conversation often find their preferred window is already gone. By planning ahead with Alliance, you gain a partner that helps coordinate your testing strategy—not just perform the test. When you schedule with Alliance, we help you: Reserve testing dates before peak-season availability becomes limited Review your testing requirements to confirm the correct scope and regulatory obligations Develop a testing schedule that aligns with your compliance deadlines and facility operations Provide timely proposals and contract support to help avoid Q1 procurement delays Coordinate testing logistics to minimize operational disruption and keep projects moving The earlier planning starts, the more flexibility you have. 4. Confirm Notification Letter Readiness Most stack tests require advance regulatory notification — 30 days for Part 60 and Part 61, 60 days for Part 63. These letters must be signed by the Designated Representative and the Responsible Official. Confirm before year-end that: Your DR and Responsible Official are current and authorized A signed notification letter template is ready to submit when the test window is confirmed You know which agency (EPA, state, or local) the notification goes to for each applicable test Getting this wrong delays your test date and can create compliance exposure if you miss a deadline. 5. Coordinate Unit Outage Schedules With Operations Get the Q1 outage schedule from your operations team before the holidays. Stack testing requires planned downtime and specific operating conditions — normal or worst-case operations depending on the applicable method. Without this coordination in hand, you can't confirm test windows with your contractor or submit notification letters on time. 6. Review Your Gas Cylinder Inventory Gas vendors typically shut down or operate on reduced schedules over the holidays. Before year-end, confirm: You have sufficient calibration gas cylinders on hand to carry you through the holiday period and into early Q1 Reference gas cylinders needed for upcoming linearity checks and RATAs are ordered, NIST-traceable, and not approaching expiration Cylinder concentrations still match your current span settings Running out of reference gas during a test window is an avoidable problem that a year-end inventory check prevents. 7. Review Hourly Max Values and Span Settings Pull the highest hourly values recorded for SO2, NOx, CO2, and flow rate over the past year. If any values are approaching your current span or range settings, you may need a different blend of calibration or linearity gas cylinders heading into the new year. Catching this in December gives you time to adjust before testing begins. 8. Verify CEMS Readiness for Test Season Your CEMS needs to be in a clean, passing state before a stack testing contractor arrives on site. A year-end CEMS review should confirm: No unresolved out-of-control periods in recent calibration history Daily calibration drift is within acceptable limits Monitoring plan and QA/QC plan reflect current equipment configuration Data Acquisition System is generating and archiving QA files correctly A CEMS that isn't ready when the tester arrives can delay the test, invalidate runs, or require retesting — all of which add cost and compliance risk. One Vendor for Both Sides of the Test Most facilities manage CEMS compliance and stack testing through separate vendors. Alliance Technical Group is the one exception. As the largest stack testing provider in the U.S. and a full-service CEMS solutions provider — including our StackVision DAS, CEMS hardware, regulatory services, and ongoing compliance support — Alliance can coordinate both sides of your year-end planning through a single point of contact. That means your CEMS readiness review, reference gas inventory, DAS configuration, and stack test scheduling can all be handled by one team that already knows your system.

Any facility operating a Continuous Emissions Monitoring System (CEMS) or Continuous Opacity Monitoring System (COMS) is required by federal regulation to maintain a QA/QC manual. Manuals are often missing when a new system is purchased, or become outdated after equipment upgrades or replacements. This article outlines the regulatory requirements and the standard elements a QA/QC manual should contain. QAQC Manual Guidance Requirements QA/QC manual requirements are governed by the applicable EPA regulation for your facility: 40 CFR Part 75, Appendix B — applies to electric generating units and other large combustion sources subject to the Acid Rain Program or CSAPR 40 CFR Part 60, Appendix F — applies to sources subject to New Source Performance Standards (NSPS) 40 CFR Part 63 — applies to sources subject to National Emission Standards for Hazardous Air Pollutants (NESHAP) The original equipment supplier typically develops the QA/QC manual, as it requires detailed technical knowledge of the specific equipment and a working understanding of the applicable regulations. Plant personnel can develop or maintain the manual but will generally need significant input from the supplier or manufacturer. What a QA/QC Manual Must Include A complete QA/QC manual typically contains the following sections: 1. Introduction: Defines the objective of the manual, the facility's QA/QC policy, the scope of the plan, and document control information. Identifies the applicable regulations and references the facility's operating permit. 2. Description of Facility and Equipment: Describes the facility, organizational structure, and personnel responsible for QA/QC activities. Includes equipment details — make, model, and serial numbers — and describes the overall measurement process and monitoring technology. This section requires updating as personnel change and equipment is replaced or upgraded. 3. Quality Assurance Activities: The core of the manual. Describes all QA activities that ensure the CEMS or COMS remains a compliant measurement system. Covers daily calibrations, quarterly audits, and annual testing, including test methods, drift limits, allowable errors, and timing requirements for each activity. 4. Quality Control Activities: Details the corrective actions taken when QA activities identify problems. Includes maintenance schedules, technician training requirements, and spare parts inventory practices. 5. Data Recording and Reporting: Describes how data is recorded and reported, including notification requirements, recordkeeping procedures, and documentation for component additions, maintenance events, and equipment replacements. 6. Glossary of Terms and Acronyms 7. Attachments: Typically includes copies of report types generated by the system and any equipment certificates of compliance. Keep Your CEMS QA/QC Manual Current The manual must be reviewed and updated whenever equipment changes are made — analyzer replacements, system upgrades, or personnel changes all require corresponding updates. An outdated QA/QC manual is a common audit finding. Beyond regulatory compliance, a current manual is a practical training tool for personnel maintaining the equipment. Alliance Technical Group is an end-to-end CEMS solutions provider — from system design, installation, and hardware to DAS configuration, regulatory services, and ongoing compliance support. That includes QA/QC manual development, permit reviews, and ensuring your DAS is aligned with your monitoring and QA/QC plans. If you operate a CEMS, we can support every layer of it.

This guide covers the fundamentals: what air emissions compliance reporting is, what drives the requirements, and what those requirements look like under the two most common federal frameworks — 40 CFR Part 60/63 and 40 CFR Part 75. What Is Air Emissions Compliance? Air emissions compliance means operating your facility within the emissions limits and monitoring requirements established by your applicable regulations and operating permit. For stationary emission sources, this involves continuous or periodic monitoring of pollutants, maintaining records of that monitoring data, and submitting reports to the relevant regulatory agencies that demonstrate ongoing compliance. Non-compliance — whether from actual emissions exceeding permitted limits, monitoring systems that fail to operate as required, or reports that are incomplete or late — carries real consequences: compliance orders, penalties, and in serious cases, operational restrictions. Operating Permits: The Foundation of Your Compliance Obligations Every stationary emission source subject to federal air quality regulations must have an operating permit that authorizes its operation. The U.S. Environmental Protection Agency began rolling out these permits under Title V of the 1990 Clean Air Act Amendments in 1995, creating a nationwide permitting program for significant emission sources. Major vs. Minor Sources Each emission source at a facility is categorized as either a major or minor source based on how much of a given pollutant — or combination of pollutants — it releases annually. Under the Clean Air Act, a facility is classified as a major source if its estimated emissions of the six Criteria Air Pollutants exceed 100 tons per year in aggregate. The six Criteria Air Pollutants are: Carbon monoxide (CO) Lead (Pb) Nitrogen oxides (NOₓ) Sulfur dioxide (SO₂) Particulate matter (PM) Ground-level ozone (O₃) Sources that fall below the major source threshold are classified as minor sources. The distinction matters because monitoring and reporting requirements are significantly more stringent for major sources, which is why many facilities invest in pollution control equipment — such as selective catalytic reactors (SCRs) or SO₂ scrubbers — or switch to cleaner-burning fuels to stay below major source thresholds. Your Permit Defines Your Obligations Your Title V operating permit lists every emission source at your facility and specifies the applicable regulations, emission limits, monitoring requirements, and reporting obligations for each one. The permit is the primary document your facility must comply with — and it may be more stringent than the federal baseline if your state or local air agency has added requirements. Understanding exactly what your permit requires is the starting point for any compliance reporting program. Part 60 and Part 63 Reporting Requirements 40 CFR Part 60 (New Source Performance Standards) and 40 CFR Part 63 (National Emission Standards for Hazardous Air Pollutants) apply to a broad range of industrial sources. Facilities subject to these regulations must submit reports to EPA and applicable state agencies on a quarterly, semiannual, and annual basis. Reports are due within 30 calendar days of the end of each reporting period and must be signed by the facility’s Responsible Official. Quarterly Exception Reports Quarterly reporting under Part 60 and Part 63 is exception-based — meaning the report documents instances where compliance requirements were not met during the quarter, rather than summarizing all operations. Each quarterly report for a monitoring system covers two categories of events: Exceedance events: periods when the monitoring system was operating correctly and producing valid data, but that data showed emissions exceeded the applicable limit or standard. The report must identify when the exceedance began, when it ended, and the cause. Downtime events: periods when a required monitoring system was not functioning as expected while the unit was operating. Any inability to produce valid compliance data is considered a deviation from permit requirements and must be documented with timing and cause. Common causes of exceedance events include startup/shutdown conditions, control equipment problems, and process upsets. Common causes of downtime events include monitoring equipment malfunctions, non-monitoring equipment malfunctions, and quality assurance calibrations. If the total percentage of downtime for the quarter exceeds 5%, or the total percentage of exceedances exceeds 1%, a detailed report is required for each event. Otherwise, a summary report is sufficient. Semiannual Monitoring Reports Semiannual monitoring reports document periods during the previous six months when required monitoring did not occur. The types of monitoring that may be subject to semiannual reporting include: Continuous monitoring systems (CEMS for SO₂, NOₓ, CO₂, or other pollutants; SCR inlet temperature monitors) Periodic monitoring (daily fugitive dust records, opacity readings) Equipment inspection rounds (daily or weekly monitoring of operating equipment) Periodic testing as required by permit Annual Compliance Reports The annual compliance report is the most comprehensive of the three. It lists every compliance requirement in the facility’s permit, characterizes each requirement as continuous, intermittent, or periodic, and states the compliance status for each requirement over the full calendar year. This report gives regulators a complete picture of how the facility performed against its permit obligations for the year. Part 75 Reporting Requirements 40 CFR Part 75 was established by EPA in support of the Acid Rain Program and applies primarily to electric generating units (EGUs) and other affected sources under cap-and-trade programs for SO₂, NOₓ, and CO₂. Unlike Part 60/63’s exception-based reporting, Part 75 operates as an accounting system: EPA assigns annual emissions allowances to each source, and facilities must report actual emissions continuously throughout the year to demonstrate they are operating within their assigned limits. Quarterly Electronic Reporting Facilities subject to Part 75 must submit emissions reports four times a year — one per calendar quarter — to EPA’s Clean Air Markets Division (CAMD) via the Emissions Collection and Monitoring Plan System (ECMPS). Reports must be submitted as Electronic Data Report (EDR) files by the applicable quarterly deadline. Late or missing submissions can be interpreted as an intent not to comply. Each quarterly submission must include: Facility and unit identification information Hourly emissions data, operating data, and QA test results as specified in the monitoring plan Unit operating hours for the quarter and cumulative operating hours for the calendar year and/or ozone season Tons of SO₂ emitted during the quarter and cumulative SO₂ mass emissions for the calendar year (for applicable units) Average NOₓ emission rates (lb/mmBtu) for the quarter and year-to-date (for applicable units) Tons of CO₂ emitted during the quarter and cumulative CO₂ mass emissions for the calendar year (for applicable units) Tons of NOₓ emitted during the quarter and cumulative NOₓ mass emissions for the calendar year and/or ozone season (for applicable units) Total heat input (mmBtu) for the quarter and cumulative heat input for the calendar year, unless exempted Part 75 Quality Assurance Requirements Part 75 reporting is inseparable from a mandatory QA/QC program. Facilities must conduct and document QA activities at the following frequencies, and results must be included in the quarterly EDR submission: Frequency Required QA Activity Purpose Daily Calibration error checks of all monitors; interference checks of flow monitors Confirm analyzers are reading accurately; detect and document any out-of-control conditions before they accumulate Quarterly Linearity checks of gas monitors Flow-to-load ratio tests Leak checks of DP-type flow monitors Verify analyzer response is linear across the full measurement range; confirm flow measurement accuracy Semiannually or Annually Relative Accuracy Test Audits (RATAs) Validate CEMS accuracy against independent reference method measurements at the stack. Frequency depends on prior RATA results — facilities with consistently good RA scores may qualify for annual frequency. QA data — calibration records, linearity results, and RATA results — must be included in the quarterly EDR submission alongside hourly emissions data. Missing or incomplete QA data in a submission is a common source of compliance findings. Part 60/63 vs. Part 75: Side-by-Side Overview Many facilities are subject to both frameworks. The table below summarizes the key differences to help you understand what each regulation requires. 40 CFR Part 60 / Part 63 40 CFR Part 75 Who It Applies To Broad range of stationary sources: boilers, kilns, furnaces, chemical plants, and others subject to NSPS or NESHAP standards Electric generating units (EGUs) and other affected sources under the Acid Rain Program, CSAPR, and related cap-and-trade programs Reporting Model Exception-based: reports document non-compliance events (exceedances and downtime) during the period Accounting-based: continuous emissions tracking against annual allowances; full hourly data submitted each quarter Reporting Frequency Quarterly exception reports, semiannual monitoring reports, annual compliance reports Quarterly electronic submissions via ECMPS Submission Method State and local agency submission (format varies by jurisdiction) Electronic Data Report (EDR) submitted to EPA’s CAMD via ECMPS QA Requirements Quarterly audits required (RATA, CGA, or RAA); written QC program; daily calibration drift checks per §60.13 Daily calibration checks, quarterly linearity checks and flow tests, semiannual or annual RATAs Key Risk Incomplete documentation of exceedance or downtime events; missing semiannual or annual reports Late EDR submissions; incomplete QA data in the submission; out-of-control periods not properly substituted How Alliance Technical Group Supports Air Emissions Compliance Reporting Alliance Technical Group provides environmental compliance consulting and reporting services to regulated facilities across power generation, manufacturing, chemical processing, and other industries throughout North America. Our regulatory specialists and reporting analysts work directly with facility teams to manage the full scope of compliance reporting obligations. Alliance helps facilities by: Navigating complex reporting programs across Part 75, Part 60, and Part 63 requirements. Keeping DAS and CEMS configurations aligned with permit changes and regulatory updates. Identifying and resolving data quality issues before they become reporting or audit findings. Providing experienced regulatory and technical support to help bridge staffing gaps and knowledge loss. Managing reporting workflows and submissions to support accurate, timely compliance reporting. Need Help with Air Emissions Compliance Reporting? Whether you’re new to compliance reporting, managing complex dual-regulation obligations, or looking for a more reliable reporting partner, Alliance Technical Group can help.

Decatur, AL – June 22, 2026 – Alliance Technical Group, the leading provider of environmental testing, monitoring, and compliance services, is pleased to announce the appointment of Amit Kapur as Chief Financial Officer. Amit joins the executive leadership team at a pivotal time in the company’s continued growth, bringing extensive experience in finance, operations, capital strategy, and organizational leadership. Amit Kapur, Chief Financial Officer of Alliance Technical group With more than 25 years of global experience spanning public companies, private equity-backed organizations, and multinational enterprises, Amit has built a distinguished career leading financial and operational transformation. Throughout his career, he has successfully overseen large-scale capital allocation initiatives, mergers and acquisitions, treasury operations, investor relations, and strategic growth programs that have strengthened organizational performance and shareholder value. Most recently, Amit served as Chief Financial Officer of DRI Healthcare, where he led strategic capital deployment initiatives, enhanced investor engagement, and supported significant value creation. Prior to DRI Healthcare, he held CFO and senior executive leadership positions with Enwave Energy Corporation, ATS Corporation, Canaccede Financial Group, General Electric, and George Weston Limited. In addition to his executive leadership experience, Amit serves on several boards and audit committees and brings a strong academic and professional background. He holds an MBA from Cornell University, the CFA designation, CPA credentials in both Canada and the United States, and has completed advanced executive education through Harvard Business School. In his role as Chief Financial Officer, Amit will oversee Alliance’s financial strategy, capital planning, and financial operations while supporting the company’s continued growth and long-term value creation. His leadership will play a key role in advancing Alliance’s mission and positioning the organization for continued success.

Reflects EPA’s May 2024 final rule (89 FR 38508). Monitoring frequency thresholds, emission limits, and applicability definitions are current as of publication. Who This Guide Is For This guide is written for environmental managers, compliance officers, and terminal operators at bulk gasoline facilities classified as major or area HAP sources. It covers applicable regulations, technical changes, LDAR program structure, Appendix K OGI requirements, and the specific actions facilities should be taking now to meet the May 2027 deadline. This article is based on insights shared during Alliance Technical Group's recent webinar on the EPA's Bulk Gasoline Terminal Rule updates. For a deeper discussion of the requirements, compliance timelines, and implementation considerations, watch the full webinar on demand. The EPA's 2024 final rule is the most significant overhaul of bulk gasoline terminal air regulations in over forty years. New Source Performance Standards Subpart XXa and revised NESHAP Subparts R and 6B tighten loading rack emission limits by as much as 97%, replace monthly AVO inspections with formal LDAR instrument monitoring, and add CEMS, flare monitoring, and electronic reporting obligations that many terminals have never managed before. For existing sources, the compliance deadline is May 8, 2027. The deadlines vary by regulation and source type. Here is the full compliance timeline: Regulation Source Type Compliance Deadline NSPS Subpart XXa New / modified / reconstructed (after June 10, 2022) July 8, 2024 or upon startup NESHAP Subpart R & 6B New / reconstructed sources July 8, 2024 NESHAP Subpart R & 6B Existing sources May 8, 2027 NESHAP R & 6B — certain storage tank controls Existing sources May 8, 2034 The Three Rules Governing Bulk Gasoline Terminals Three federal regulations now govern bulk gasoline terminals. NSPS 40 CFR Part 60, Subpart XXa applies to terminals that commenced construction, modification, or reconstruction after June 10, 2022, and replaces the older Subpart XX for those sources. NESHAP 40 CFR Part 63, Subpart R covers major source gasoline distribution terminals. NESHAP 40 CFR Part 63, Subpart BBBBBB (6B) covers area source facilities including bulk terminals, bulk plants, and pipeline facilities. Subpart XX (40 CFR Part 60) remains in force for sources built or modified between December 17, 1980, and June 10, 2022. Many facilities will operate under both Subpart XX and XXa simultaneously, with different rules for different units within the same fence line. Identifying which subpart governs each affected unit is the necessary first step. What the Rule Actually Changed Loading Rack Emission Limits The amended rules cut allowable loading rack emissions substantially from the prior Subpart XX standard of 35–80 mg/L: NSPS XXa (new sources, thermal oxidation): 1 mg/L TOC NSPS XXa (modified/reconstructed, thermal oxidation): 10 mg/L TOC NSPS XXa (VRU-controlled): 550 ppmv new; 5,500 ppmv modified/reconstructed NESHAP Subpart R: revised from 35 mg/L to 10 mg/L NESHAP Subpart 6B: revised from 80 mg/L to 35 mg/L Terminals with older vapor recovery units or thermal oxidizers should evaluate now whether existing control equipment can meet the new thresholds or whether upgrades are required before compliance deadlines arrive. Storage Tank Requirements Internal floating roof (IFR) tanks must maintain vapor concentrations above the floating roof below 25% of the lower explosive limit (LEL), with annual LEL monitoring now required. External floating roof (EFR) tanks face additional fitting control requirements aligned with NSPS Subpart Kb. Certain storage tank provisions under NESHAP Subparts R and 6B are delayed until May 8, 2034, but that delay applies only to specific tank control provisions. LEL monitoring and IFR vapor space requirements for new sources are not among the delayed items. New Monitoring and Control Equipment Requirements Beyond emission limits, the rule adds: flare monitoring requirements modeled on EPA's refinery rules; continuous temperature monitoring for vapor combustion units; CEMS for VRUs where concentration-based limits (ppmv) are elected instead of mass-based limits; submerged fill requirements for loading racks; and electronic reporting under all three regulations. Some area sources under Subpart 6B may be required to install CEMS for the first time. LDAR: The Biggest Operational Shift for Most Terminals Before these rule changes, LDAR at bulk terminals meant monthly AVO inspections. The amended rules replace that framework entirely. All equipment in gasoline service, including valves, pumps, connectors, pressure relief valves, sampling connections, and open-ended lines, is now subject to formal instrument monitoring. Open-ended lines are no longer permitted and must be capped or plugged. Method 21 or OGI: Choosing Your Approach Terminals can comply using Method 21 or Optical Gas Imaging under Appendix K. Method 21 uses a portable hydrocarbon detector with surveyor contact at each component; a reading at or above 10,000 ppmv is a leak. It builds on a component inventory, making it a natural fit where that inventory already exists or state permits already require Method 21. OGI under Appendix K uses an infrared camera to survey equipment areas without component-by-component contact, six to twenty-two times faster than Method 21, and does not require a detailed component inventory, only an equipment list and route map. OGI does require a structured compliance program under Appendix K (see section below). Alliance Technical Group provides both Method 21 and Appendix K OGI services with nationwide scheduling capacity. Repair Requirements First repair attempt: within 5 days of detection. Final repair: within 15 days. If a repair cannot be completed within 15 days, the component must be tagged, the delay documented, an expected repair date established, and management sign-off obtained and recorded. LDAR reports, which are structured differently from standard semiannual air compliance reports, must break out total leaks by detection date, monitoring method, and component type, and flag any instance where a 5-day repair attempt was not made. If You Choose OGI: What Appendix K Requires Appendix K to 40 CFR Part 60 is a structured federal protocol that governs every aspect of OGI survey conduct, documentation, and quality assurance, from technician qualification and site-specific monitoring plans to daily weather verification and video recordkeeping. Terminals that elect OGI, or that hire vendors to conduct OGI surveys on their behalf, need a site-specific program that satisfies all of the following. Technician Qualification Initial training requires classroom instruction on the regulation and camera theory, three hours of field observation, twelve hours of side-by-side work with a qualified senior operator, fifteen hours of supervised surveying, and a final skills assessment. Semiannual performance audits and biannual refresher training are ongoing requirements. A senior OGI operator under Appendix K must have more than 1,400 documented lifetime survey hours and at least 40 survey hours in the preceding 12 months. Site-Specific Monitoring Plan Each facility requires a written monitoring plan covering interference conditions and stop/pause criteria (steam, fog, solar glare, heat reflections); safety protocols; required instrumentation (anemometer, temperature gauge, distance meter); camera calibration and maintenance; and defined operating envelopes for the specific camera model(s) in use, accounting for all configurations — lens type, sensitivity mode, handheld vs. tripod, external display use. Survey Execution and Daily QA Each survey day begins with a verification check — or a full field check if operating outside the camera’s defined envelope. Two viewing angles per scene are required, with dwell time minimums: at least 10 seconds per angle for scenes of 10 or fewer components, and at least 2 seconds per component for larger groupings. Weather conditions (ΔT and wind speed) must be recorded at the start and end of each survey and rechecked every two hours for surveys exceeding four hours. A five-minute QA verification video must be recorded each survey day. Confirmed leaks and completed repairs both require video documentation. Storage Tank Emission Testing: A Methodology Problem Most Operators Don’t Know They Have Regulators are increasingly requesting emissions testing directly from storage tank vents. What many terminal operators don’t realize is that standard single-point testing can significantly overstate a tank’s actual emission rate — and agreeing to that test plan without discussion can produce a number that follows the facility for years. A storage tank and its headspace form a closed equilibrium system. When a test draws flow from the vent, it disturbs that equilibrium and induces additional evaporation. The more flow pulled during sampling, the higher the measured emission rate — not because the tank emits more under normal operation, but because the act of testing is generating the emissions. The defensible approach is a regression-based methodology: test at three distinct exhaust rates each separated by at least 500 scfm, measure VOC concentration at each rate, plot emission rate against flow rate, and extrapolate back to zero imposed flow. The intercept represents the tank’s natural breathing rate without any test-induced draw. Alliance Technical Group has developed and applied this regression-based methodology in regulatory settings where the resulting emission rate was later scrutinized by state agencies — and the approach has held up under that review. Five Actions Bulk Gasoline Terminals Should Take Now With the May 2027 compliance deadline approaching, facilities should be planning today. Permit modifications, equipment procurement, vendor availability, and initial monitoring requirements can take much longer than expected. 1. Determine Applicability Across Your Facility: Identify which tanks, loading racks, and equipment are subject to Subpart XX, XXa, R, and/or Method 6B requirements. Then create a compliance roadmap that aligns with the 2024, 2027, and 2034 deadlines. 2. Make Key Compliance Strategy Decisions Early: Decide whether your LDAR program will use Method 21 or Optical Gas Imaging (OGI) under Appendix K. Also determine whether you'll comply with emissions limits using a mass-based approach or a concentration-based approach that requires CEMS. These decisions impact equipment, staffing, training, testing, and reporting requirements. 3. Evaluate Air Permit Impacts: Review existing permits to identify needed updates. Many facilities will need permit modifications to address new control requirements, LDAR provisions, CEMS monitoring, averaging periods, and revised emission limits. Start discussions early, as agency review timelines can be lengthy. 4. Secure Vendors and Compliance Resources: Demand for OGI specialists, Method 21 technicians, CEMS providers, and stack testing services is expected to increase as 2027 approaches. Engage implementation partners now to avoid scheduling constraints later. 5. Develop a Compliance Plan and Assign Ownership: Establish a detailed project schedule that works backward from the compliance deadline. Assign internal owners for permitting, LDAR, monitoring, testing, reporting, and recordkeeping activities to keep implementation on track. How Alliance Technical Group Can Help Alliance Technical Group is one of the few environmental services firms that provides stack testing, LDAR, CEMS, and permitting support under one roof — which matters when a compliance program spans all four. Our terminals team includes Appendix K-certified OGI operators with nationwide coverage, in-house spectroscopists for Method 320 FTIR work, and laboratory infrastructure in St. Louis and Minneapolis for developing site-specific response factors on ethanol-blended streams. Alliance's offerings for bulk gasoline terminals include: LDAR programs using Method 21 or OGI (Appendix K) — certified operators, nationwide scheduling Stack testing: Method 25A and Method 320 (FTIR) with in-house response factor development for ethanol and oxygenated blends CEMS installation, performance specification testing, and ongoing RATA services Storage tank emission testing using regression-based methodology Applicability determinations, permit revision support, and multi-year compliance planning Regulatory References 40 CFR Part 60, Subpart XX — Standards of Performance for Bulk Gasoline Terminals (sources through June 10, 2022) 40 CFR Part 60, Subpart XXa — Standards of Performance for Bulk Gasoline Terminals (sources after June 10, 2022) 40 CFR Part 63, Subpart R — NESHAP for Gasoline Distribution Facilities (Major Sources) 40 CFR Part 63, Subpart BBBBBB (6B) — NESHAP for Gasoline Distribution Area Sources Federal Register, May 8, 2024 — Final Rule: 89 FR 38508 40 CFR Part 60, Appendix A-7, Method 25A and Method 320 40 CFR Part 60, Appendix K — Optical Gas Imaging Monitoring Protocol Frequently Asked Questions Specific applicability and compliance questions terminal operators commonly ask about NSPS Subpart XXa and the revised NESHAP Subparts R and 6B.

Decatur, AL — May 18, 2026 – Alliance Technical Group, the leading provider of environmental testing, monitoring, and compliance services, announced today the acquisition of the Leak Detection and Repair (LDAR) assets from Atlas Technical Consultants LLC., a nationally recognized leader in infrastructure and environmental services. The acquisition brings a focused team of industrial air quality and emissions compliance specialists into the Alliance family, deepening Alliance's capabilities in LDAR program management across the Gulf Coast and beyond. Atlas' LDAR group has built a strong, client-focused practice over more than two decades, serving major industrial operators primarily across the Gulf Coast, with additional presence spanning from Wyoming to Delaware. The group's expertise covers LDAR program development, auditing, and implementation; emissions reporting and data management; and onsite field services. Their technicians bring deep familiarity with complex industrial regulatory environments and a track record of delivering practical compliance solutions for clients in oil and gas, refining and petrochemical sectors. "The LDAR professionals joining us from Atlas bring exactly the kind of specialized, field-proven expertise that strengthens Alliance's position as a comprehensive environmental services provider," said Chris LeMay, CEO of Alliance Technical Group. "Their deep relationships with major industrial operators, combined with their technical depth across LDAR program management and air quality compliance, make this a compelling addition to the Alliance team. We're excited to welcome their team and look forward to growing together." "Joining Alliance opens a meaningful new chapter for our team and the clients we serve," said Nick James, Director of Operations. "Our work has always been built on technical precision and long-term client relationships in some of the most demanding industrial environments in the country. Alliance shares that commitment, and their platform gives us the ability to grow those relationships and reach new clients in ways we couldn't before." This acquisition reflects Alliance's continued strategy to grow its environmental testing and compliance capabilities while strengthening its presence across key industrial markets throughout North America. The Environmental Financial Consulting Group, LLC (“EFCG”), through its registered broker-dealer affiliate EFCG Transaction Services LLC, served as advisor to Alliance Technical Group on the transaction.

Decatur, AL and Wellington, OH — 4/27/26 Alliance Technical Group, a leading provider of environmental testing, monitoring, and compliance services, announced today the acquisition of Grace Consulting, Inc. (GCI), a nationally recognized air sampling and stack testing firm specializing in air emissions testing and environmental compliance services. Founded in 2000 and operating out of offices in Ohio, Indiana, North Carolina, and Texas, GCI has established itself as one of the largest privately held stack testing companies in the nation. Over the past two decades, GCI has served clients across a broad range of industries, providing comprehensive air sampling services backed by the latest sampling techniques and technical advancements. "Grace Consulting has built a remarkable reputation as a premier stack testing firm in the country, with deep technical expertise and a strong commitment to client service," said Chris LeMay, CEO of Alliance Technical Group. "Their capabilities in air emissions testing, combined with their extensive equipment inventory and highly credentialed field teams, make them an outstanding addition to the Alliance family and significantly strengthen our national footprint." With the addition of GCI, Alliance further deepens its technical capabilities in source emissions testing while broadening its geographic reach across the continental United States. GCI's experienced field teams will integrate with Alliance's expansive environmental services network, providing clients with greater resources, enhanced technical depth, and expanded coverage. "Becoming part of Alliance Technical Group marks an exciting new chapter for GCI and the team we've built since 2000," said Scott Teague, President of Grace Consulting, Inc. "We share a commitment to delivering high-quality, reliable environmental testing services, and joining Alliance gives us the platform to offer our clients even greater resources and capabilities as we continue to grow together." This acquisition reflects Alliance's ongoing strategy to strengthen its environmental testing and compliance services and extend its reach across North America. The Exit Group supported Alliance Technical Group in sourcing and executing the transaction.

Facilities preparing for Appendix K optical gas imaging (OGI) monitoring requirements often face a common challenge: managing documentation, inspection data, videos and reporting across multiple systems. This often creates challenges during audits when records must be compiled or verified. Appendix K programs require structured documentation of OGI inspections, including daily verification checks, weather conditions, and video documentation.  What Data Must Be Collected for Appendix K OGI Inspections Inspection records must capture operational parameters such as: Temperature Wind speed Sky conditions Gas type Flow rate  Camera distance  This information is stored directly within the inspection record within SkyBridge, ensuring that verification documentation remains linked to the survey data. How SkyBridge Supports Appendix K OGI Monitoring and Documentation SkyBridge Software includes integrated functionality designed to support Appendix K workflows, helping environmental teams capture and manage the required documentation directly within a single platform. SkyBridge is part of Alliance Technical Group’s suite of environmental compliance software tools designed to streamline monitoring programs and reduce manual data management. SkyBridge operates as a cloud-based compliance management system, allowing organizations to manage LDAR, OGI, and Cooling Tower and Fenceline Monitoring programs in one centralized database. Core capabilities include: LDAR scheduling and repair tracking Method 21 monitoring support Visual leak documentation Visible vapor and OGI camera integration Leak management tracking Recordkeeping and LDAR reporting GPS tracking for field technicians Because SkyBridge integrates web and mobile applications, technicians can collect inspection data in the field while syncing information directly to the system. OGI Monitoring and Appendix K Verification and Documentation SkyBridge includes specific functionality designed to support Appendix K OGI monitoring documentation requirements. Field technicians can document and upload verification data directly from the inspection location, including: Daily verification check documentation and video uploads - Creating a traceable record that verification checks were completed prior to surveys, helping facilities demonstrate that OGI cameras were operating properly and that monitoring procedures were followed.  Daily field check documentation and video uploads - Ensures required checks are consistently recorded in real time, reducing reliance on manual logs and minimizing gaps in documentation. Weather and environmental conditions documentation - Captures required conditions at the time of monitoring, supporting data validity and helping avoid challenges to inspection results. Leak Image and video file documentation - Provides visual evidence of findings, improving transparency, supporting repair prioritization, and strengthening compliance records. QA Verification video - Documents quality assurance activities, reinforcing program credibility and helping facilities demonstrate adherence to Appendix K requirements. Supporting Scalable OGI and Appendix K Compliance Programs As OGI monitoring programs continue to expand, environmental teams need tools that help simplify field documentation and maintain consistent records. By combining inspection documentation, leak management, video uploads, and reporting into one system, SkyBridge provides a structured approach to managing Appendix K monitoring programs.

Stack testing — also called performance testing or source testing — is used to measure a facility's air emissions and verify compliance with emission limits established under the Clean Air Act (CAA). A stack test tends to go one of two ways: planned and predictable, or compressed and reactive. The difference comes down to coordination. Delays in scheduling or execution can quickly lead to retesting costs, missed compliance deadlines, production disruptions, and increased regulatory risk. What starts as a timing issue can escalate into a much larger operational and financial impact. This guide breaks down what stack testing is, when it is required, and how to execute it in a way that supports compliance and operations. What Is Stack Testing? Stack testing quantifies regulated air emissions at the source and is required to demonstrate compliance under federal programs, including NSPS, MACT, and NESHAP. It is used to demonstrate both initial and ongoing compliance under major federal programs, including New Source Performance Standards (NSPS) under 40 CFR Part 60, Acid Rain Program (Part 75, CEMS), National Emission Standards for Hazardous Air Pollutants (NESHAP) under 40 CFR Part 61, and Maximum Achievable Control Technology (MACT) standards under 40 CFR Part 63. When Is Stack Testing Required? Initial Compliance New or modified sources typically face specific regulatory deadlines for completing an initial stack test: NSPS (40 CFR Part 60): Within 180 days after initial startup, or 60 days after reaching maximum production rate MACT (40 CFR Part 63): Notice of Compliance Status is typically due within 150 days for certain subparts Ongoing Permit Requirements Facilities with an Air Pollution Control Permit are commonly required to conduct periodic testing to demonstrate continuous compliance. Regulatory agencies can also require a test at their discretion, particularly when no continuous monitoring system exists or when previous results showed a narrow compliance margin. Specific Operational Triggers Stack testing is also required in these situations: CEMS evaluations – Relative Accuracy Test Audits (RATA) and linearity checks to verify Continuous Emission Monitoring Systems Rule changes – Updates to federal standards (Residual Risk and Technology Reviews, revised PM thresholds) can trigger new testing mandates Information Collection Requests (ICRs) – EPA may require testing under CAA Section 114 to support new rulemaking Engineering and Investigative Testing Not all stack testing is regulation driven. Facilities routinely test for internal purposes — process optimization, control device evaluation, and emissions profiling for future planning. Core Requirements for a Valid Stack Test To produce defensible data, stack tests must meet strict regulatory criteria: Representative Conditions: testing must reflect normal or worst-case operations  Run Structure: compliance is based on the average of three consecutive valid runs   Advance Regulatory Notification: These windows exist to give the regulatory agency the opportunity to observe. 30 days (Part 60, Part 61)  60 days (Part 63)  Data Integrity: invalid runs must be reported and may require replacement  Failure to meet these requirements can result in rejected data or required retesting. How a Stack Test Works Most compliance tests follow the same general structure: Pre-test planning and method selection Site-specific test plan development and agency notification Equipment setup and calibration Three test runs per emission point, with QA/QC checks Final report preparation and submission A straightforward test typically takes one to two days per emission point. Complex programs — multiple pollutants, restricted access points, or extended run times — take longer. What Does a Stack Test Report Include? The final report is the primary compliance document. A well-structured report should include: Executive summary – What was tested, why, and how results compare to limits Test program summary – Facility details, regulatory drivers, emission sources, control systems, and site-specific plans Summary of results – Emissions data alongside operating conditions, compared directly to permit limits Methodology – EPA reference methods used and any method-specific considerations Appendices – Field data sheets, calibration records, process data, and example calculations Stack testing is as much about scheduling coordination as it is about testing execution. Facilities that align planning, operations, and testing early gain flexibility and reduce risk. Those that delay often face limited options and higher costs. Alliance is the largest stack testing provider in the U.S. Alliance Technical Group provides stack testing services nationwide, with accredited laboratories (NELAC, LELAP, TCEQ), on-site FTIR capabilities, and integrated field and analytical teams. Whether you're planning an initial compliance test or managing an ongoing permit requirement, we help you get through it with reliable data and fewer surprises. If you are approaching a compliance deadline, the most important step is simple: Secure your test window early. Frequently Asked Questions

Facilities subject to NSPS Subpart OOOOb must monitor flare performance to demonstrate proper combustion and emissions control. One of the key parameters required under the rule is Net Heating Value (NHV) .  Understanding how NHV sampling works, which equipment is affected, and current compliance timelines is critical for oil and gas operators preparing for NSPS OOOOb. We asked our experts to answer the most common NHV sampling questions facilities ask, including practical considerations shaped by real fieldwork. Here’s what to know before you start building or adjusting your program. How Alliance Technical Group Supports OOOOb NHV Compliance  Preparing for NSPS OOOOb compliance requires coordination across sampling, laboratory analysis, and reporting. With the June 1, 2026 deadline approaching, any gaps in personnel, process, or data management can slow you down. Alliance Technical Group supports oil and gas operators through the full scope of NSPS OOOOb compliance. From applicability determinations and NHV sampling program development to laboratory analysis and data interpretation, our teams help facilities implement monitoring programs that meet current requirements and stay ahead of upcoming deadlines. Meet Our Experts  MaryBeth Clifford Emissions Compliance Specialist Dan Smith Project Director, Air Quality Steve LaRue Sr. Operations Manager Frequently Asked Questions

On April 4, 2026, the U.S. EPA finalized revisions to portions of the 2024 oil and natural gas regulations under the Clean Air Act, commonly referred to as OOOOb/c. These updates follow industry petitions, additional data submitted after the 2024 rule, and a formal reconsideration process initiated in 2025.   While the structure of the original rule remains in place, several key provisions have been adjusted to address implementation challenges, particularly around flaring and net heating value (NHV) monitoring.   Here is what changed and what it means for your compliance program.   What Changed in OOOOb/c   1. Temporary Flaring Extended to 72 Hours   The allowable duration for temporary flaring of associated gas has been extended from 24 hours to up to 72 hours for troubleshooting and repairs.   The rule also introduces a new "exigent circumstances" provision that grants additional time beyond 72 hours in cases where site access is limited due to:   Severe weather  Personnel shortages  Supply chain constraints  Operators must document and report these events.   2. Adjusted NHV Monitoring Requirements   Operators are no longer required to perform routine Net Heating Value (NHV) sampling for flares or enclosed combustion devices (ECDs)   unless conditions exist that could lower heating value , such as the presence of inert gases.   3. Associated Gas Exemption Removed   Additionally, the general exemption from NHV monitoring for associated gas at well sites has been removed. Going forward, associated gas sources will be subject to the same monitoring framework as other affected facilities.   4. Updated Parameters for Alternative Performance Tests   The revised rule also finalizes several updates to the alternative performance test option for both new and existing sources. Specific changes include:   NHV grab sampling can now be conducted upstream of the inlet to the control device.  The performance test window is set to 14 operating days, with weekend and holiday breaks allowed, provided sampling is spaced no more than 3-operating days apart from the previous sampling day.  Block hourly averaging is required for continuous samples.  A one-hour minimum sampling time applies to twice-daily samples, with an exception for sites where low or intermittent flow makes that duration infeasible.  5. Sampling Demonstration Clarification   The finalized rule also adds clarifying language confirming that the sampling demonstration can serve as an alternative to continuous monitoring for all air-assisted and steam-assisted flares and ECDs.   What Has Not Changed   It is important to note that the broader structure of OOOOb/c remains intact:   Performance standards for new, modified, and reconstructed sources still apply  States are still responsible for implementing emissions guidelines for existing sources  Documentation, reporting, and defensibility remain central to compliance  Current Compliance Deadlines   The EPA issued an Interim Final Rule on December 3, 2025, extending several OOOOb compliance deadlines. Those deadlines remain in effect.   What Oil & Gas Operators Should Do Next   Re-evaluate NHV compliance strategies:  Determine where sampling is still required and where it may no longer apply  Review flare and ECD operations:  Identify scenarios where inert gases or variable gas streams could still trigger monitoring  Update internal procedures and documentation:  Especially for flaring events exceeding 72 hours and exigent circumstances  Monitor upcoming rulemaking:  The EPA has indicated that additional revisions to the 2024 rule are still under development  Navigating OOOOb Requirements with Alliance   These revisions do not remove compliance obligations, but they do change how those obligations are met once they take effect. As the June 1, 2026, NHV compliance date approaches, many facilities are operating in a narrow window where the existing requirements remain in effect, even as the EPA has finalized changes that will soon alter monitoring and testing expectations.   Alliance Technical Group helps operators navigate this transition—clarifying what is required today, what will change once the amendments become effective, and how to implement a compliant, defensible approach that minimizes rework and enforcement risk while positioning facilities for the updated rule.   Read the official press release on the EPA Website.

The Biogas Regulatory Reform Rule (BRRR) has tightened federal oversight of Renewable Natural Gas (RNG) production under the Renewable Fuel Standard (RFS). RNG from landfills, dairies, and wastewater treatment plants must now be measured, sampled, and verified using EPA-approved methods before it qualifies for RIN generation or downstream sale. This shift makes RNG compliance, RNG sampling, and data verification under the Renewable Fuel Standard central to maintaining eligibility and supporting RIN generation.   What Is Required for RNG Compliance Under BRRR? BRRR introduces standardized, auditable requirements for RNG facilities across the Renewable Fuel Standard. Operators must now demonstrate: Verified RNG sampling and measurement using EPA-approved methods Documented gas composition and flow rate data Traceable records supporting RIN generation under the RFS Audit-ready documentation aligned with EPA reporting expectations These requirements apply across the RNG value chain, including landfill operators, dairy digesters, wastewater treatment plants (WWTPs), and RNG developers. BRRR implementation began July 1, 2024 for new facilities , required registration updates by October 1, 2024, and is fully enforceable for all RNG pathways as of January 1, 2025. Facilities that did not align registration, sampling, and reporting processes ahead of these deadlines are now operating under increased compliance risk. Sampling and measurement are no longer supporting tasks—they are now part of the core compliance framework for RNG operations.   How to Meet RNG Sampling Requirements Under BRRR To meet BRRR requirements, facilities must implement structured RNG sampling programs that are consistent, repeatable, and defensible. A compliant RNG sampling program includes: Flow rate measurement to quantify gas production volumes Gas composition sampling to confirm methane content and renewable gas quality Certified laboratory analysis using validated testing methods Chain-of-custody documentation to track sample handling and transfer Audit-ready records that connect field sampling to RFS reporting These elements verify methane yield and renewable content, which are required for RIN qualification and compliance under the Renewable Fuel Standard.   Data Verification and Audit Requirements for RFS Compliance BRRR places increased emphasis on data integrity, traceability, and audit readiness. Facilities must ensure that: RNG sampling data is consistent and reproducible Laboratory results are certified and traceable Documentation connects field sampling to final RFS reporting Records can withstand third-party and EPA audit review Certified lab results and third-party audit trails protect project owners, off-takers, and marketers by ensuring that RNG data is defensible. Without verified sampling and traceable data, RNG does not meet compliance requirements under BRRR. How Alliance Helps Facilities Meet BRRR Compliance Requirements Alliance Technical Group supports RNG facilities with end-to-end gas quality programs designed to meet BRRR and Renewable Fuel Standard requirements. From field sampling and chain-of-custody control to certified laboratory analysis (CH₄, CO₂, H₂S, O₂, siloxanes, moisture) and regulatory-grade RFS reporting, our programs are built to produce consistent, traceable, and audit-ready data. Through this work, advisors like Shane Lee partner with facilities to translate regulatory requirements into practical, defensible sampling and reporting programs. Shane Lee RNG/Biogas Project Manager