The New Mexico Environment Department (NMED) has asked the state Environmental Improvement Board (EIB) to adopt 20.2.51 NMAC, Methane Abatement. The Board will take testimony on the proposal starting December 1, 2026, in a hearing scheduled to run through December 8. The rule would do two things. It would set up a state super-emitter program, under which certified third parties can report large methane releases detected by satellite, aircraft or other remote sensing. It would also require natural gas-driven pneumatic controllers at well sites, tank batteries, gathering and boosting stations, natural gas processing plants and transmission compressor stations to emit no methane beginning January 1, 2031. New Mexico is moving ahead while EPA heads the other way on federal methane requirements. On October 7, EPA Administrator Lee Zeldin said the agency would propose eliminating the federal Super Emitter Program in NSPS OOOOb and EG OOOOc. If the EIB adopts 20.2.51 NMAC, operators in New Mexico will have super-emitter and controller obligations under state law regardless of what the EPA decides. Below we summarize the proposal, compare it with federal and existing state requirements, and outline the steps we are recommending to clients with New Mexico assets. The Proposed Methane Rule Requirements NMED circulated a stakeholder draft on July 16, 2026, and filed its petition with the EIB on August 13 under docket EIB 26-78 (R). The summary below reflects the filed version, which may change after the hearing. Super-emitter program Under the proposal, a super-emitter event is a methane release of at least 50 kilograms per hour, detected with remote sensing technology NMED has approved. NMED would certify third-party notifiers, typically satellite and aerial monitoring firms. Notifiers would have 7 calendar days after detection to notify NMED, including the quantified emission rate and its measurement uncertainty, the coordinates, the detection technology used and supporting imagery. NMED would then notify the owner or operator of every source within 50 meters of the reported location. Each notified operator must investigate, identify the source and repair it. Under 20.2.51.104, investigation and repairs must be completed within three calendar days of receiving NMED's notification. A signed event report is due within 15 calendar days of the notification, and records must be kept for five years. The program applies to any stationary source of methane, so landfills, wastewater plants and other facilities outside oil and gas could receive notices as well. If an investigation cannot tie the event to a specific leak, the operator must repair all leaks found during the investigation and verify each repair by re-monitoring with Method 21 or OGI. Zero-emission process controllers From January 1, 2031, natural gas-driven process controllers at well sites, tank batteries, gathering and boosting stations, gas processing plants and transmission compressor stations would have to emit zero methane. Operators can meet the standard by routing controller exhaust to a process through a closed vent system, or by using self-contained gas-driven controllers. Routing emissions to a control device does not satisfy the standard. Emergency shutdown devices and process controllers that are not natural gas-driven are exempt. The proposal also sets design and operating requirements for closed vent systems, calls for initial and periodic inspections, and requires an annual report covering every inspection and repair. Operators already replacing controllers under the 2022 Ozone Precursor Rule (20.2.50 NMAC) should plan on 2031 as the end point of that program. Comparison With Federal and Existing State Rules NMED modeled its program on the federal one in NSPS OOOOb, with a lower threshold, broader applicability and a shorter response time. Provision Federal Super Emitter Program (OOOOb/c) Proposed NM 20.2.51 NMAC Detection threshold 100 kg/hr 50 kg/hr Sources covered Oil and gas facilities All stationary methane sources Operator response Begin investigation within 5 days; report within 15 days Investigate and repair generally within 3 days; report within 15 days Repair scope Source of the event All leaks found during the investigation, if the event cannot be traced to a specific leak Status Implementation paused to Jan. 22, 2027; EPA plans to propose rescinding it Takes effect on adoption Federal status EPA finalized a first set of revisions to the 2024 OOOOb/c rules earlier this year, which among other changes extended allowances for temporary flaring. The second set, announced October 7, would remove the Super Emitter Program and revisit provisions for marginal wells, associated gas and control devices. EPA puts the savings at $45 billion. The proposed text had not been published as of mid-October. Rescinding the federal program would have no effect on the state proposal. If both actions are finalized, the New Mexico program would be the only super-emitter requirement that applies to sources in the state. Existing state requirements Operators in New Mexico already comply with two state methane programs. NMED's Ozone Precursor Rule (20.2.50 NMAC) requires LDAR inspections, a compliance data system and phased controller replacement through 2030 in Chaves, Doña Ana, Eddy, Lea, Rio Arriba, Sandoval, San Juan and Valencia counties. The Oil Conservation Division's Methane Waste Rule (19.15.27 and 19.15.28 NMAC) regulates venting and flaring. 20.2.51 NMAC would add a remote-detection response obligation on top of both. The Independent Petroleum Association of New Mexico (IPANM) argued in its comments that the three-day repair deadline and the 2031 controller date are not achievable in practice. We expect both provisions to be contested at the hearing and some details to change in the final rule. Recommended Steps Remote detection is already producing data on New Mexico operations. Earthworks and Gas Leaks Project used public satellite data to identify 166 super-emitter events in the New Mexico Permian between January 2025 and April 2026, many of which had not been reported to the state. With a three-day response requirement, an operator that receives its first notice before it has a plan in place will have very little room to respond well. These are the steps we are recommending to clients now: Survey higher-risk equipment, such as tanks, compressors, flares, separators and controllers, so the largest emission sources are found and repaired before a third party reports them. Write a response procedure that covers who receives NMED notices, how a crew reaches the site within three days, which method will confirm the source, and who signs the 15-day report. Arrange investigation capacity in advance. When several facilities sit within 50 meters of a reported event, each one has to be surveyed quickly and the source confirmed at the component level. Build a controller inventory and compare it with your 20.2.50 replacement schedule and the 2031 date. Note which devices serve as emergency shutdown devices and decide, site by site, between closed vent systems and self-contained controllers. Review recordkeeping so that survey data, repair logs and imagery would support a signed event report and stand up to an agency review. Follow the docket. Filings are posted on NMED's docketed matters page under EIB 26-78 (R), and comments can be sent to the Air Quality Bureau at AQB-ControlStrategies@env.nm.gov. How Alliance Supports New Mexico Operators Most of what the proposed rule asks of operators falls within our LDAR and compliance services. Requirement Operator need How Alliance Helps Super-emitter notifications at 50 kg/hr or more Identify large emitters before a third party does We provide LDAR/OGI baseline surveys of higher-risk equipment to find and document large leaks Investigation of sources within 50 meters, generally within 3 days Determine which facility and component caused the event OGI surveys of each facility within the radius to confirm the source at the component level Repair of all leaks found during the investigation Confirmation that repairs were effective LDAR/OGI repair verification with imagery Signed event report within 15 days; records kept 5 years Documentation that supports the report Compliance services to compile survey data, imagery and repair records Zero-emission process controllers by January 1, 2031 An inventory showing which controllers still vent LDAR field inventory, with OGI to identify venting devices Closed vent system requirements and periodic inspections Inspections at the required frequency, properly documented LDAR/OGI inspection programs set up by facility Annual inspection and repair reports Complete records for each reporting year Compliance services for tracking and report preparation For most clients, these requirements will run alongside existing LDAR and controller obligations under 20.2.50 NMAC and NSPS OOOOa and OOOOb. We generally recommend managing them as a single program, so one set of field records serves both state and federal requirements. Our field teams work out of more than 80 offices across North America. Talk With Our Team The final details of the rule will be settled after the December hearing. Baseline surveys, response planning and controller inventories are worth doing under any likely version of it, and starting now gives operators time to fix what they find.

Table of Contents: What changed with the RY2025 GHGRP reporting deadline? The reporting year (RY) 2025 Greenhouse Gas Reporting Program (GHGRP) deadline is now March 10, 2027. EPA signed the extension on October 8, 2026, and it was published in the Federal Register on October 14, 2026, taking effect the same day. It is the second extension this year. The deadline has changed, but the reporting obligation has not: Subpart W is still legally in effect. Subpart W, which covers petroleum and natural gas systems, got the biggest rewrite in its history in 2024, but most of those changes first show up in RY2025 reports. About 18 months later, EPA proposed pausing nearly all of it. The question for operators is now which version of the rule will actually apply. This article, based on Alliance's recent webinar with Trent Wade and Christoff Orr, covers where the rule stands, what changed for your equipment and how to prepare either way. Subpart W timeline: 2009 to today The RY2025 deadline has now moved twice since EPA proposed its rollback in September 2025. Date What happened 2009–2023 GHGRP established (2009); Subpart W added for oil and gas (2010); incremental revisions, including NSPS-aligned leak standards (2016) May 2024 Comprehensive rewrite: empirical data methods, new emission factors and a new onshore transmission pipeline segment March 2025 Congress disapproves the Waste Emissions Charge (WEC) rule under the Congressional Review Act July 2025 The One Big Beautiful Bill Act delays the WEC until 2034 emissions September 2025 EPA proposes suspending 9 of 10 segments until RY2034 and removing natural gas distribution. Still pending, with 53,000+ comments, including from API and AXPC arguing to keep reporting February 2026 RY2025 deadline extended from March 31 to October 30, 2026 October 14, 2026 Second extension, to March 10, 2027, published in the Federal Register and in effect Is Subpart W still in effect? Yes. Subpart W remains legally in effect, nothing has been repealed, and RY2025 reports are due March 10, 2027. The suspension is only a proposal. EPA has not finalized its September 2025 plan to pause reporting. Only the deadline changed. The extension changes nothing else in Part 98. EPA says it needs time to finish reviewing comments and to get its e-GGRT reporting tool ready. Litigation is likely regardless. The outcome could be challenged in court or reversed by a future administration, as happened with the NSPS OOOOa rollback. Who has to report under Subpart W? 10 industry segments are covered. 25,000 metric tons CO2e per year is the reporting threshold. For four segments, including onshore production and gathering and boosting, the threshold applies to specific listed sources rather than the whole facility. Reports are filed annually through EPA's electronic Greenhouse Gas Reporting Tool (e-GGRT). Why is pausing Subpart W controversial? EPA based the 2024 rewrite on five justifications: methane's priority under the Inflation Reduction Act, better measurement technology such as OGI, the weakness of generic emission factors, the link to the WEC's per-ton fee and a congressional mandate under Clean Air Act section 136(h). EPA now argues that with the WEC delayed, much of the reporting burden no longer serves a purpose. Critics say the other four justifications still stand. What did the 2024 Subpart W rule change? The 2024 rule pushes operators toward site-specific data and away from generic assumptions. It does that in three ways: better data (measured inputs and updated emission factors), more reporting (a new "other large release events" category and a new onshore transmission pipeline segment) and more QA/QC (heavier recordkeeping, documented assumptions and structured monitoring surveys). Here is what changed for the equipment operators manage most, and where Alliance can help. Production well sites Liquids unloading: methodology tiers, from continuous monitoring down to default factors, replace a flat per-event factor. Associated gas venting and flaring: quantification now includes gas that isn't routed to sales. Completions and workovers: updated venting calculations. Threshold: the 25,000 mtCO2e test applies to listed sources, not the whole facility. How Alliance helps: OGI surveys for every affected facility type, plus Subpart W reporting, recordkeeping and QA/QC documentation support across your well sites. Gathering and boosting compressor stations Applicability: a source-specific threshold means more stations may have to report. Reciprocating compressors: rod packing vents shift to measured or monitored rates, in line with NSPS OOOOb. Centrifugal compressors: wet and dry seal vents are handled separately, by control status. Blowdowns and starts: updated methods for maintenance, emergency shutdown and pneumatic-start venting. How Alliance helps: OGI surveys provide leak detection and quantification support tied directly to Subpart W and NSPS OOOOb, and our air compliance team supports reporting and QA/QC documentation. Pneumatic devices Pneumatics are the single biggest technical change, affecting nearly every segment. Operators choose among four methods, from most rigorous to most generic: Method Approach Method 1 Continuous flow monitoring Method 2 Manufacturer-specified emission rate × hours of operation Method 3 Engineering equations Method 4 Population default emission factors Facilities with 26 or more pneumatic controllers and pumps can phase in measurement over several years. How Alliance helps: we support all four methods, so you can weigh where measurement lowers reported emissions (see the WEC example below). Storage tanks Flashing emissions require measured or site-specific inputs, such as gas-oil ratio sampling or process simulation, instead of default factors. Bypassed or malfunctioning control devices must be reported as uncontrolled venting under "other large release events." Assumed vapor recovery or combustor control must now be verified as actually operating. A site run exactly as it was last year could report much higher emissions if it can't show its controls worked all year. How Alliance helps: our field teams verify that tank control devices are operating, so your reported emissions reflect the controls you actually have. Flare destruction efficiency tiers The old rule let any properly operating flare assume 98% destruction efficiency (DE). Now the assumed DE depends on the monitoring you can document: Tier Assumed DE Monitoring required Tier 1 98% Refinery-grade monitoring per 40 CFR 63 Subpart CC Tier 2 95% NSPS OOOOb-level monitoring Tier 3 92% Pilot flame, gas heating value and visible emissions only Without records that prove your tier, you default to 92%. Unlit or malfunctioning flares count as 0% control in every tier. Alternative performance testing can support DE above 98%. How Alliance helps: flare Tier 1–3 monitoring, DE optimization and the documentation to back up your tier. Equipment leak quantification Updated leaker emission factors come from recent field measurement studies. OGI and Method 21 results now feed quantification, scaled by the rigor of the inspection. AVO inspections can find a leak but can't size it. Survey frequency varies by segment. How Alliance helps: OGI and Method 21 surveys, with field data managed in our SkyBridge software, cover both finding leaks and quantifying them. Midstream: processing, transmission, storage and LNG New segment: onshore natural gas transmission pipelines now have their own reporting obligation. Compressor stations: the same compressor updates apply at transmission scale. Transmission, storage and LNG: OGI findings tie to quantification, with updated leak survey and blowdown methods. Midstream has fewer facilities than upstream, but each one carries more measurement and QA/QC work. How Alliance helps: OGI surveys, emissions monitoring and air compliance support, including Subpart W reporting, recordkeeping and QA/QC documentation. Why methodology choice matters: the Waste Emissions Charge Once the WEC applies, the method you use to quantify emissions turns directly into dollars. By statute (CAA section 136), the WEC is $1,500 per metric ton of methane for 2026 and later. The One Big Beautiful Bill Act delayed it to 2034 emissions, with payments starting in 2035. Example: one compressor station with 30 intermittent-bleed pneumatic controllers Quantification method Methane emissions Basis Default factor (Equation W-1B) 30.85 mtCH4/yr 8.8 scf whole gas/hr per device, about 1.03 mt per device per year LDAR survey data (Equation W-1C) 14.48 mtCH4/yr 10% malfunction rate, about 0.48 mt per device per year Using survey data instead of the default factor cuts reported methane roughly in half. At $1,500 per metric ton, that is a $24,560 per year difference in WEC exposure, from methodology choice alone. A second example points the same way. For a compressor station with 50 continuous low-bleed controllers, the Method 4 default factor gives about 1,264 mtCO2e per year. A measured value about 35% lower, consistent with published field studies, gives about 822 mtCO2e. Default factors are designed to be conservative, so in most cases they overestimate actual emissions. The timing matters too. Whatever methodology a facility is using when the WEC clock restarts in 2034 becomes the baseline for what it pays. That makes now the time to decide where more rigorous measurement pays for itself. How should operators prepare before March 10, 2027? Treat the extra time before March 10, 2027 as time to prepare, not as relief from the requirement. Plan for three scenarios: the rule is finalized as proposed, it is narrowed, or it is vacated in court. Good documentation protects you against a future reversal of the reversal. Improve equipment inventories and operational data collection now. If the 2024 rule takes effect, this data becomes far more valuable. Document methodology assumptions while institutional knowledge is fresh. Don't let your calculation approach live with one person who may leave or retire. Maintain QA/QC procedures regardless of federal deadline changes. Standardize calculation tools across sites and segments as far as is practical. If you export to Europe, track the EU methane intensity methodology, due August 2027. Stay engaged with the EPA docket and public comment. EPA is taking comments on the deadline extension through November 30, 2026 (Docket EPA-HQ-OAR-2025-0186). It's also worth starting an internal conversation now: if Subpart W goes away, is the data still meaningful to report? Would you keep using Subpart W methods, or build your own internal guidelines? What should operators watch next? Timing of the final Subpart W rule, and litigation over the rollback Further NSPS OOOOb/OOOOc actions The EU's methane intensity methodology (due August 2027) and state legislative sessions in 2027. See the beyond-EPA section below. How can Alliance help with Subpart W compliance? Whether you're preparing to file RY2025 reports, deciding where measurement pays off or building an internal GHG program, Alliance supports every step: OGI surveys: leak detection and quantification support tied directly to Subpart W and NSPS OOOOb requirements, for every affected facility type. Learn more → Emissions monitoring: instrumentation and data management for your highest-impact sources, including pneumatic device Methods 1–4, flare Tier 1–3 monitoring and destruction efficiency optimization, and tank control device verification. Learn more → Air compliance support: Subpart W reporting, recordkeeping and QA/QC documentation, NSPS OOOOb/OOOOc compliance, and readiness for EU MRV and OGMP 2.0. We can also help you build a roadmap or an internal GHG and methane reporting plan. Learn more → Want the full picture? For related context on federal rollbacks, see our earlier article on the partial repeal of the Carbon Pollution Standards and capacity factor for new combustion turbines. The common thread is that EPA, the EU and the market are all moving toward measurement-informed data instead of generic factors. Sources U.S. EPA, Extending the Reporting Deadline Under the Greenhouse Gas Reporting Rule for Reporting Year 2025 to March 10, 2027, Federal Register, October 14, 2026 Alliance Technical Group, "What's Next for GHG Reporting? Practical Guidance for Subpart W Compliance," webinar by Trent Wade and Christoff Orr

A final rule was signed by EPA Administrator Lee Zeldin on September 14, 2026 repealing many of the 2024 Carbon Pollution Standards (CPS) governing greenhouse gas (GHG) emissions from fossil fuel-fired power plants under Clean Air Act section 111. What was repealed: Emission guidelines for existing coal/gas/oil-fired steam generating units — including the requirement that long-term coal plants use 90% carbon capture and sequestration (CCS), and that medium-term coal plants use 40% natural gas co-firing. CCS-based standards for coal plants undergoing large modifications. "Phase 2" CCS-based standards for new base-load combustion turbines. EPA’s repeal also updated language in 40CFR60 Subpart TTTTa. While the Phase 2 standards for new base load combustion turbines were repealed, which would have required 90% CCS by January 1, 2032, the Phase 1 efficiency-based standards were left in place for all new turbines. Changes to Capacity Factor Definitions for Combustion Turbines Most coverage of EPA's September 2026 repeal of the Carbon Pollution Standards (CPS) focuses on the headline: the CCS mandates are out. The 2024 CPS put new turbines into three capacity-factor-defined tiers with Best System of Emission Reduction (BSER) requirements and the 2026 repeal changed some of those: Subcategory Capacity factor BSER (before repeal) BSER (after repeal) Base load ≥40% Two-part: (1) highly efficient generation, effective immediately; (2) 90% CCS by 1/1/2032 Only part (1) survives — efficiency-based limit, no CCS Intermediate load Below 40%, above 20% Highly efficient simple-cycle generation Unchanged — never had a CCS component Low load Below 20% Lower-emitting fuels Unchanged — never had a CCS component But the amendatory text in 40 CFR 60.5580a also changes how new combustion turbines are sorted into load tiers. The "and" and "or" in those definitions decide which turbines land in which tier. Three tiers, two criteria New combustion turbines are classified by how much of their potential electric output they sell to the grid. The rule tests this with two criteria at once: a 12-month rolling total and a 3-year rolling average. In some cases the new rule uses "both" criteria or "either" criteria which determine their CO2 emission limits. Tier Test Base load More than 40% on both 12-month rolling total and 3-year rolling averages Intermediate load More than 20% on both windows, and 40% or less on either window Low load 20% or less on either window What didn't change: the base load definition "Base load combustion turbine" is not among the definitions this rule revises. The amendment updates intermediate load and low load. Base load keeps its existing language: more than 40% of potential electric output as net-electric sales on both a 12-month rolling total and a 3-year rolling average basis. This definition makes sure that one strong year (12-month rolling total) doesn't make a unit base load, and neither does one strong three-year stretch (3-year rolling average). What did change: the intermediate and low load definitions The new "either" logic in the low-load and intermediate-load definitions is similar to the unchanged base-load definition, but provides better assurance to the operator regarding which limit applies. At the 20% line: a unit has to clear 20% on both windows to no longer be low load. If the units factor is 20% or below on just one window and it is low load. At the 40% line: a unit has to clear 40% on both windows to be base load. If either window is at or below 40%, it falls to intermediate. For example, a turbine at 45% on one window and 35% on the other. It isn't base load, because it didn't clear 40% on both. It isn't low load either. The new intermediate ceiling catches it. The gap this closes The earlier definitions used "both" at every boundary. Under that wording, a turbine at 45% and 35% satisfied neither the base-load test (not above 40% on both) nor the old intermediate test (not at or below 40% on both). A turbine at 15% on one window and 25% on the other failed both the old low-load test and the old intermediate floor. Both ended up in classification limbo. The new language fixes this. Mixed units at the 40% line go to intermediate. Mixed units at the 20% line go to low load. What this means in practice The change is not a loosening of the regulation. Nothing here makes base load easier to reach, since that bar is untouched. The "either" tests mainly make sure units straddling a boundary are assigned to a tier rather than left unclassified. It also matters more with the CCS requirement gone. Base load status no longer triggers a 90% CCS mandate, but the tiers still determine which efficiency or fuel-based limit applies to a new turbine. How Alliance Technical Group Helps As requirements change, facilities need a clear understanding of which standards apply and reliable data to demonstrate compliance. Alliance Technical Group brings together air quality consulting, industry-leading data acquisition systems, one-stop shop for all things CEMS, and stack testing to support your facility’s compliance program. Whether you’re evaluating requirements for a new turbine or reviewing your existing monitoring and reporting practices, Alliance works with your team to address the details and keep your compliance program aligned with your operations.

What's Happening Virginia has finalized a new emissions standard for data center generator sets into its air regulations. On August 18, 2026, the State Air Pollution Control Board adopted Article 7 of 9VAC5-50, "Emission Standards for Data Center Engine Generator-Sets." It publishes in the Virginia Register on October 5 and takes effect November 4, 2026. The effective date of the regulation matters less than it might seem. The regulation implements a law — Va. Code § 10.1-1322.6, from House Bill 507 — that's already governing permit decisions. Air permit applications filed since July 1, 2026 are already being processed under that statute, ahead of the regulation's formal effective date. Who It Affects The rule applies to data centers that submit a DEQ air permit application on or after July 1, 2026, including applications for coverage under a general permit. Applications to modify an existing permit may also be subject to the requirements. For applications submitted before July 1, applicants should confirm with DEQ whether subsequent revisions affect applicability. "Data center" is defined broadly, borrowed from the tax code: a facility whose primary services are the storage, management, and processing of digital data, housing at least one megawatt of equipment for managing electrical power and cooling. That threshold is low enough that most colocation, hyperscale, and enterprise sites qualify. The applicability trigger is the permit application date. An application submitted before July 1, 2026 falls outside Article 7's requirements; an application submitted on or after that date falls within them. The Core Requirements of the Data Center Gen-Set Rule "For a data center permit issued by the department, including coverage under any general permit, the department shall not issue such permit unless the emission limit for each gen-set established by such permit is equal to or less than the emissions achieved by a Tier 4 equivalent gen-set." 9VAC5-50-630 A. The rule's operative sentence is aimed at DEQ, not the applicant: DEQ cannot issue a data center permit unless the emissions limit for each generator is equal to or better than what a "Tier 4 equivalent" generator would achieve. This standard has three defining features: It's per-unit, not fleet-wide. A facility-wide average or a site cap doesn't satisfy the requirement. Every individual generator has to clear the bar. It's a performance test, not a certification requirement. "Tier 4 equivalent" is defined by three control devices — or their proven equivalents: SCR (selective catalytic reduction) for NOx DOC (diesel oxidation catalyst) for CO DPF (diesel particulate filter) for particulate matter "Tier 4 certified" never appears in the statute or the regulation. What counts as "equivalent" is left to DEQ's judgment on a case-by-case basis — which is exactly why the permit limit, and the test proving it, end up mattering more than the label on the engine. It's a floor, not a ceiling. DEQ keeps full authority to require a more strict limit through BACT, LAER, RACT, or applicable NSPS/NESHAP determinations. This rule sets the minimum; it doesn't cap what DEQ can require. How to Prove Compliance "Initial performance tests shall be conducted for CO and NOX to determine compliance with the emission limits listed in the permit. Emissions testing of each pollutant for each selected engine-generator set shall consist of three one-hour test runs under load. The average of the three runs shall be reported as the short-term emission rate for that engine-generator set. Testing shall be conducted with the engine(s) operating at greater than 90% capacity, unless multiple load band testing is approved by DEQ." APG-576, section I, Testing Requirements (data centers). Article 7 itself is short — three sections and a definition. It doesn't specify how a facility demonstrates that a generator meets the standard. That detail is set out in DEQ's guidance memo, APG-576 (revised April 9, 2026), which supplies the standard permit conditions DEQ writers use for data center gen-sets. That boilerplate requires: A presumptive NOx limit of 0.60 g/hp-hr, reflecting SCR control, with monitoring conditions on catalyst bed temperature and urea/ammonia injection. An initial performance test for CO and NOx on each selected generator: three one-hour runs, above 90% load, with the average of the three runs reported as the compliance rate. A Method 9 visible emissions evaluation — 30 sets of 24 observations at 15-second intervals, also run above 90% load. Testing on a sample, not every unit — typically 20 to 25% of the units of each generator type at a site. A fixed notification calendar built around construction start, startup, and test dates, each with its own advance-notice window. Why It Matters Projects currently in the design phase need to finalize the generator specification and the permit strategy together. An application filed on or after July 1 that proposes units without SCR, DOC, and DPF, or a documented equivalent, does not meet the standard in 9VAC5-50-630 A, and DEQ cannot approve it. Testing also has to work around a fixed scheduling constraint: data center generators are typically commissioned in phases, often before the building itself is occupied. A three-run test above 90% load requires a load bank, fuel, an SCR brought up to temperature before the test, and a test crew — all coordinated within your testing schedule. Multiple things belong in the project plan now: Fix the application date and the permit path early. Any application submitted on or after July 1, 2026, including general permit coverage, is subject to Article 7, and the unit specification has to incorporate SCR, DOC and DPF or a documented equivalent before the application is filed. Confirm the NOx, CO, PM and opacity limits DEQ includes in the permit. Ensure all notifications and testing, including the Method 9 evaluation, are built into the commissioning schedule. Investigate the availability of a load-bank sufficient to ensure greater than 90% capacity during the test. Build any required downtime, including moving test equipment and warming up the SCR to the required temperature, into the testing schedule. A Compliance Partner That Won't Slow You Down None of this changes what your team is already juggling — commissioning phases of units on a tight schedule with a lot of other things depending on the outcome. What it adds is a compliance step that has to happen on time, get reported correctly the first time, and not become the bottleneck. That's the job Alliance Technical Group is built for. We run EPA reference-method performance testing on stationary engines and generator sets — CO, NOx, and PM test programs, plus Method 9 visible emissions evaluations — with test plans built around your commissioning schedule, not the other way around. Fast turnarounds, results delivered on time, and no need for do-overs from a botched test run. If a Virginia data center permit is in your pipeline, we can help design the initial compliance demonstration before your units go live.

On September 28, 2026, the EPA proposed changes to the Gasoline Distribution rules, covering equipment leak (LDAR) requirements, thermal oxidizer temperature compliance options, and vapor recovery provisions. The 2024 rule remains in effect until EPA finalizes these changes. Equipment Leak (LDAR) Provisions Here's what would change under NSPS XXa: New capital expenditure threshold for “modification.” Process-improvement projects costing no more than 8% of the replacement cost of the facility's “collection of equipment” (CPI-adjusted) won't trigger NSPS XXa applicability. New provision at 40 CFR 60.500a(e)(3). First LDAR survey due within 180 days. Newly affected facilities get 180 calendar days from becoming subject to equipment leak monitoring to complete their first instrument survey (40 CFR 60.502a(j)(1)). Where a NESHAP subpart cross-references this requirement, the survey is still due by that subpart's own compliance date — no extra 180 days (May 8, 2027 due date still applies for NESHAP R and 6B). Here’s what would change for NSPS XXa, NESHAP R, and NESHAP 6B: Surveys must occur during active loading. Instrument monitoring surveys must be conducted while the facility is actively loading gasoline into a cargo tank (40 CFR 60.502a(j)(1)). Pre-performance test leaks aren't automatically a violation. A transition away from the “operated with no detectable emissions” standard to a find-and-fix standard of “has no leaks at or above 500 ppmv” (40 CFR 60.503a(a)(2)). A leak triggers repair, not an automatic violation, and the leak must be repaired prior to the test (i.e., delay of repair provisions do not apply). Backup/secondary control systems monitored only when in use. The “in gasoline service” definition changes from “used in a system that transfers” to “contains or contacts” gasoline or vapors — so periodic instrument monitoring is only required if these systems are actively processing gasoline during the scheduled monitoring event. No removal of monitoring for bulk plants and pipeline pumping stations. NESHAP BBBBBB monitoring requirements for these facilities stay as-is. The EPA is seeking comments for possible exclusions or less stringent requirements for “small” or “remote” facilities. Thermal Oxidizer Operating Limit: Two Options on the Table Here’s what would change for NSPS Subpart XXa, NESHAP R, and NESHAP 6B: In addition to various technical updates, including revisions related to net heating values and air-assisted thermal oxidizers and flares, EPA is proposing two alternative ways to demonstrate a thermal oxidizer is meeting its temperature limit, and is requesting comment on which one to finalize. Option 1 — Shorter Test, Normal Loading Option 2 — Fixed 400°F Mid-Stack Floor Minimum performance test drops from six hours to three (at least thirty-six 5-minute loading intervals, normal mixed-product operations). The 3-hour rolling average temperature limit still applies. For units under the 10 or 35 mg/L limit: mid-stack temperature ≥ 400°F for every 5-minute period of active loading. Mid-stack = at least 19 ft above the burners (or 3 ft from the top of a shorter stack). Note: The limit set by a facility's most recent test stands until the next required test. Vapor Recovery Unit (VRU) Provisions Here’s what would change for NSPS XXa, NESHAP R, and NESHAP 6B: 6-hour rolling average for concentration limits. The VRU concentration emission limits would be evaluated on a 6-hour rolling average (seventy-two 5-minute periods) instead of the current 3-hour rolling average. Site-specific monitoring plan for CEMS downtime. Facilities must develop a site-specific monitoring plan, submitted through CEDRI, to use during CEMS downtime — replacing the current approach of basing operating limits on the 10 previous operational cycles. Records must include the most recently approved plan and the start and end date and time of each use (the 240-hour per calendar year limit on using the plan still applies). Key Dates: Date: What Happens: Oct. 5, 2026 Deadline to request a public hearing Oct. 13, 2026 Virtual hearing (held only if requested) Oct. 28, 2026 Paperwork Reduction Act comments due to OMB Nov. 12, 2026 Public comments due — docket EPA-HQ-OAR-2025-0302 May 8, 2027 Existing-sources under NESHAP R and NESHAP 6B compliance date (unchanged); first equipment leak survey due What to Do Now Decide whether to submit comments on the proposed rule changes (due November 12, 2026). Pull your last thermal oxidizer performance test — review loading rate, temperature during testing, and assess stack height and thermocouple placement. Review the requirements for the CEMS downtime site-specific monitoring plan a vapor recovery unit would need under the proposal. Review available data for 3-hour versus 6-hour rolling averages on VRU CEMS to determine potential effect on compliance. Determine whether the proposed LDAR revisions would require program changes for your facility. Don’t forget that comments in favor of the proposed changes are important too! Prepare for the upcoming compliance date. Conduct a gap assessment between current operations and new rule requirements. Prepare an implementation plan and schedule to ensure compliance no later than May 8, 2027. Consider scheduling your first Method 21 or OGI equipment leak survey as well as any required performance testing for a day when you're actively loading gasoline. Sources: 91 FR 61175 (Sept. 28, 2026) eCFR 40 CFR 63 Subpart BBBBBB eCFR 40 CFR 60 Subpart XXa

Sources subject to October 6, 2022 40 CFR Part 63, Subpart DDDDD revisions were required to comply with a number of revised emission limits. The revisions affected both new and existing boilers and process heaters, changing 34 emission limits — most only modestly, but some significantly enough to require control-equipment modifications or upgrades. The most dramatic change was the new-source HCl limit for solid fuel-fired units, which dropped from 2.2E-02 lb/MMBtu to 2.1E-04 lb/MMBtu, a reduction of two orders of magnitude. Because some sources needed more time to meet the revised limits, the EPA built optional alternative limits into the rule — contained in Tables 14 and 15 for new and existing sources, respectively — as a grace period. Those alternative limits sunset on October 6, 2025, meaning affected sources are now held to the limits in Tables 1 and 2. The rule doesn’t specify additional compliance-demonstration requirements tied to that sunset, so many facilities are heading into their regularly scheduled performance tests without realizing their applicable limits have changed. Some facilities conducting their first performance test under the Table 1 and Table 2 revised emission limits are finding that their units do not meet the applicable limits. Alliance Technical Group’s testing teams have encountered this challenge on-site, underscoring the importance of evaluating current performance before the required test. Engineering and investigative testing can help facilities assess that uncertainty earlier. Alliance develops targeted testing programs to evaluate emissions, investigate performance concerns, and inform adjustments before the required compliance performance test. Which Boiler MACT Limits Changed in 2022? Of the 34 revised limits, 28 became more stringent and six became less stringent. For existing sources, the relevant changes: Subcategory Pollutant Former Table 15 limit Current Table 2 limit Change Solid Fuel HCl 2.2E-02 lb/MMBtu 2.0E-02 lb/MMBtu ~9% lower Solid Fuel Mercury 5.7E-06 lb/MMBtu 5.4E-06 lb/MMBtu ~5% lower Liquid Fuel HCl 1.1E-03 lb/MMBtu 1.1E-03 lb/MMBtu No change Liquid Fuel Mercury 2.0E-06 lb/MMBtu 7.3E-07 lb/MMBtu ~64% lower Gas 2 (other) HCl / Mercury 1.7E-03 / 7.9E-06 1.7E-03 / 7.9E-06 No change Gas 2 (other) PM 6.7E-03 lb/MMBtu 7.3E-03 lb/MMBtu ~9% higher Source: EPA's October 6, 2022, final rule and the current Table 2 and Table 15 to Subpart DDDDD of Part 63. Facilities should confirm the applicable limit for their specific unit, fuel subcategory, pollutant, and compliance method. The HCl limit decreased for solid-fuel units. The mercury limit decreased for both solid-fuel and liquid-fuel units, with the liquid-fuel reduction representing the largest numerical change in the table. Liquid-fuel and Gas 2 HCl limits did not change in this amendment. These existing-source figures aren’t the full picture. New-source limits tightened as well — as noted above, the solid fuel new-source HCl limit fell by two orders of magnitude — and fluidized bed biomass-fueled units saw sharp particulate matter reductions on both sides: the new-source PM limit dropped from 9.8E-03 to 4.1E-03 lb/MMBtu, and the existing-source PM limit dropped from 1.1E-01 to 7.4E-03 lb/MMBtu. How Fuel and Operating Conditions Affect HCl Compliance Margin HCl emissions correlate with fuel chloride content as well as control-device performance. A facility without add-on acid gas controls can see HCl levels shift with fuel variability alone, independent of control-equipment condition. This affects testing frequency as well. Under §63.7515, a facility demonstrating emissions at or below 75% of the applicable limit for two consecutive years may qualify for reduced-frequency testing, once every three years instead of annually. A lower emission limit also lowers the numerical value of that 75% threshold, reducing the available margin even without a change in actual performance. The same consideration applies to compliance demonstration via fuel analysis: compliance via fuel analysis for HCl requires monthly sampling by default, and may be reduced to quarterly only after 12 consecutive months at or below 75% of the compliance level. A single result above that threshold returns the facility to monthly analysis. Managing Mercury Compliance Under the Revised Boiler MACT Limits Mercury compliance is subject to the same reduced-frequency testing mechanics as HCl under §63.7515. A facility qualifying for reduced-frequency mercury testing before the 2025 transition may no longer qualify under the current, lower limit, depending on recent test results. Mercury compliance via fuel analysis follows the same monthly-to-quarterly structure described above. Facilities relying on fuel analysis for mercury should confirm that recent results still support their current testing frequency under the applicable Table 1 or Table 2 limit. When to Conduct Engineering Testing Before Your Compliance Test Engineering and investigative testing may be valuable before your next required performance test if: Your facility is preparing for its first performance test under the revised limits and has not yet evaluated whether current emissions meet the applicable standards Your previous results were close to the now-applicable HCl, mercury, or particulate matter limit Your facility has changed fuels, operating loads, reagent feed rates, or control-system settings Your dry scrubber, sorbent injection system, baghouse, or electrostatic precipitator has undergone maintenance or modifications Your team has observed changes in control-device performance or emissions trends You want to evaluate performance under new representative operating conditions before your required compliance performance test. How Alliance Helps You Prepare Alliance’s testing professionals can develop a targeted measurement program around your facility’s specific pollutant, equipment, and operating concerns. The resulting data can help your team: Understand its current compliance margin Identify factors contributing to performance variability Evaluate emissions across different operating scenarios Make informed adjustments before the required test Approach test day with fewer unknowns and greater confidence Backed by the nation’s largest stack testing network, Alliance Technical Group brings the technical expertise and national resources needed to investigate potential concerns and help your facility prepare. If your facility has not yet tested under the newly-applicable Boiler MACT limits, now is the time to assess current performance. Alliance can help you identify potential concerns and determine what adjustments may be needed before your required compliance test. Learn more about Alliance’s Engineering/Investigative Test Programs → Boiler MACT Frequently Asked Questions Which pollutants are regulated under Boiler MACT? Subpart DDDDD covers particulate matter, HCl, mercury, and carbon monoxide, with limits and work-practice requirements that vary by unit design, fuel type, and source classification. When did existing sources have to comply with the revised limits? The alternative limits in the rule gave new and existing sources a voluntary grace period to come into compliance after the EPA finalized the revised limits in October 2022. That grace period sunset on October 6, 2025, so sources that had been relying on the alternative limits are now required to meet the current limits in Tables 1 and 2. What changed for HCl versus mercury in 2025? The HCl limit decreased for solid-fuel units only. The mercury limit decreased for both solid-fuel and liquid-fuel units, with liquid-fuel mercury reflecting the largest percentage reduction of any pollutant addressed in the rule change. What happens if a performance test result is above 75% of the applicable limit? It may affect eligibility for reduced-frequency testing under §63.7515. This is a separate consideration from exceeding the emission limit itself. What happens if a performance test exceeds the applicable emission limit? It may trigger reporting, corrective-action, and other compliance obligations, depending on the unit, pollutant, and permit conditions. How is an engineering test different from a compliance test? A compliance performance test is the formal demonstration submitted to regulators. An engineering or investigative test uses applicable reference methods to evaluate performance beforehand, so risk can be identified and addressed before the required compliance performance test.

A focused guide to DEP review tracks, backup generation, air monitoring and reporting under Executive Order 2026-05 and Act 21 of 2026 Regulatory information reviewed September 18, 2026. Key Takeaways For DEP permit or authorization applications submitted after August 18, 2026, data center projects with peak demand over 25 MW face two review tracks. Signing a GRID consent agreement enables rolling review; nonsigners face additional prerequisites. Separately, applicants for tax-program certification must submit an executed GRID agreement under the Department of Revenue’s August 2026 guidelines. DEP's template addresses backup emissions, at least three continuous air monitors with public data, and third-party-verified reporting. These are selected terms within a broader agreement; the executed project-specific consent order controls. Act 21 of 2026 separately requires operating data centers with peak electric demand of 10 MW or greater to report energy and water consumption by July 1, 2027, and annually thereafter. Reporting noncompliance carries a $10,000-per-day civil penalty until submission. On August 18, 2026, Governor Shapiro signed Executive Order 2026-05, published September 5, 2026, at 56 Pa.B. 5898 and codified at 4 Pa. Code §§ 7.1081 to 7.1089. Effective immediately, the order integrates the Governor's Responsible Infrastructure Development (GRID) Requirements into DEP's permitting process. For covered DEP applications, executing a project-specific Consent Order and Agreement (COA) determines the review track. DEP’s template, revised August 18, 2026, addresses energy, community and workforce commitments as well as environmental obligations. It allows changes for project-specific facts. The discussion below describes selected template provisions; the executed agreement controls each project’s obligations. Act 21 of 2026 (SB 146, approved July 12, 2026) added Subarticle B to Article XVIII-B of the Fiscal Code, establishing annual energy and water reporting for qualifying data centers at 10 MW or greater. Separately, the executive order directs DEP to examine potential changes to generator regulations without setting a deadline for that examination. These eight questions focus on selected permitting, backup-generation, air-monitoring and reporting issues. They are not a complete GRID compliance checklist. Evaluate the full executed agreement, tax-program requirements and applicable air and water permits together. 1. Will peak demand exceed 25 MW? Section 7.1082(a) sets the peak-demand threshold for the special DEP review process at over 25 MW. The two tracks in § 7.1082(b) and (c) apply to DEP permit or authorization applications submitted after the order’s effective date for projects above that threshold. This is a project electricity-demand threshold, not a general threshold for needing an air permit. At 25 MW or less, these two special review tracks do not apply. Ordinary air and other environmental authorizations may still be required. Section 7.1082(e) excludes data center projects from the PA Permit Fast Track Program regardless of size. Separately, Act 21 reporting reaches qualifying operating facilities at 10 MW or greater, and tax-program certification has its own GRID requirement. Establish the project’s peak demand and anticipated expansion before evaluating applicability. Confirm the air-permitting authority. DEP directs air-permit applicants in Allegheny County and Philadelphia to the Allegheny County Health Department and Philadelphia Air Management Services, respectively. Evaluate those local requirements alongside applicable DEP authorizations and GRID obligations. 2. Will you sign the GRID consent order? Executing the consent order is required for the rolling-review track; the order also provides a nonsigner track. Under § 7.1082(b)(1), before submitting new applications, a participating developer must notify DEP of its intent, meet with DEP about the permits and local approvals, and execute a project-specific consent order based on the template. Under § 7.1082(b)(2), DEP reviews applications on a rolling basis. It may issue qualifying permits on that basis only after receiving documentation of consistency with the local comprehensive plan and all applicable local subdivision and zoning approvals. The Payback and Permit Decision Guarantee processing timelines begin only after the required local-approval documentation is received. Signing does not guarantee permit approval. Signing also matters outside these DEP review tracks. Section II of the Department of Revenue’s August 2026 tax-program guidelines requires applicants for Computer Data Center Equipment Exemption Program certification, as of August 18, 2026, to include an executed DEP consent agreement implementing GRID. That application requirement has no stated 25 MW cutoff. Evaluate certification and exemption eligibility separately from the DEP review-track threshold; a smaller project should not assume it is outside GRID for tax-program purposes. 3. What happens if you do not sign? Section 7.1082(c) establishes the nonsigner track. DEP does not begin review until the applicant documents local comprehensive-plan consistency, all applicable subdivision and zoning approvals, and any required water-withdrawal or wastewater-discharge authorizations. DEP does not issue permits on a rolling basis and cannot issue them until all necessary applications have been received and reviewed. These applications are excluded from PAyback and the Permit Decision Guarantee. Schedule the complete DEP permit package and its prerequisites together. A nonsigner review track does not satisfy the separate executed-agreement requirement for tax-program certification described above. 4. Does your backup system meet the template emissions terms? Paragraph 6.b of the template provides for zero-emission energy generation and storage or backup generators with emissions no greater than those achieved by a Tier 4 or Tier 4 equivalent generator. It also calls for reduced runtime and limits backup generation to emergencies and limited testing and maintenance consistent with federal and state air requirements. Paragraph 3.z defines Tier 4 equivalent as an engine-generator set equipped with selective catalytic reduction (SCR) or equivalent nitrogen oxides (NOx) control, a diesel oxidation catalyst (DOC) or equivalent carbon monoxide (CO) control, and a diesel particulate filter (DPF) or equivalent particulate matter (PM) control. This template definition is not an EPA certification. A Tier 4-certified unit need not use that exact hardware; confirm its certification and permit-specific emission limits. For comparison, Virginia’s APG-576 provides presumptive controls for diesel engine-generator sets at data centers for applications submitted on or after July 1, 2026. It retains case-by-case best available control technology (BACT) review and specified exceptions for certain backup roles and existing-unit modifications. Its boilerplate does not cover Prevention of Significant Deterioration (PSD) or nonattainment permit review. It is a separate permitting framework, not Pennsylvania’s GRID standard. Compliance demonstrations depend on engine type, certification, configuration and permit conditions. For stationary compression-ignition engines, evaluate 40 CFR Part 60, Subpart IIII, including § 60.4211. For spark-ignition engines, evaluate Subpart JJJJ. Assess applicable Part 63, Subpart ZZZZ requirements or exemptions separately. Federal rules allow certification-based compliance for certain engines and require performance testing in other circumstances; permits can add requirements. EPA’s stationary-engine compliance guidance distinguishes these categories. Determine whether source testing is required for the actual fleet and permit. Assess source-wide potential emissions, relevant source-aggregation rules and any required air-quality modeling; Tier 4 performance alone does not establish that a project satisfies all air-permitting requirements. Plan maintenance and readiness testing within all governing federal, state, local, permit and agreement limits. Identify startup-triggered obligations before commissioning. 5. Have you planned at least three continuous air monitors? Paragraph 6.c of the template calls for at least three continuous air quality monitors at or near the site in DEP-approved locations. Collected data must be made available to the public and the relevant municipal and county governments. The template calls for an Air Monitor Plan at least [60] days before commercial operation; the bracketed value is subject to project-specific completion. The plan identifies proposed locations, parameters, installation schedule and data-publication arrangements. It provides for installation no later than 180 days after commercial operation begins. Confirm the final deadlines in the executed consent order. Select pollutants, measurement methods and locations for the site’s emissions, meteorology, nearby receptors and monitoring objectives, subject to DEP approval. For assessments involving ambient air standards, consider PM2.5, PM10 and nitrogen dioxide (NO2), with NO/NOx and meteorological measurements where useful. EPA’s ambient standards distinguish NO2 from total NOx. These are site-specific recommendations, not a fixed GRID monitoring package. SCR reduces NOx; controlled engines still warrant evaluation. Use a documented quality-assurance plan with appropriate calibration, data validation, completeness objectives and public-reporting procedures. Ambient monitoring, stack testing and dispersion modeling answer different questions; a monitoring network does not automatically satisfy a required permitting demonstration. Interpret measurements with background conditions and operating records before attributing concentrations to the facility. 6. Will your verified report be submitted at least 30 days before commercial operation? Paragraph 7.a calls for a third-party-verified report at least 30 days before commercial operation. It identifies material changes in the developer’s performance of obligations in paragraphs 4 through 6 and includes confirmations concerning ratepayer costs, community outreach, investment and jobs required to date, and environmental compliance status. Paragraph 7.b separately calls for an annual third-party-verified report by July 1. It documents continued compliance with the energy and community/workforce obligations in paragraphs 4 and 5, the amount and source of water used, and electricity use. It also requires certification that water use has not adversely affected the quantity or quality of water for other uses or users, including designated and existing uses under 25 Pa. Code Chapter 93. This annual report does not expressly repeat every paragraph 6 environmental obligation; those obligations still apply according to their terms. The verifier descriptions in paragraph 7 are bracketed for project-specific completion. Arrange appropriately qualified verification for the full report scope. Paragraphs 7.c and 7.d address inclusion of these reporting obligations in individual permit or authorization applications under the Air Pollution Control Act, Clean Streams Law and Dam Safety and Encroachments Act, and bar challenges to their inclusion as permit conditions. Paragraph 10 provides stipulated civil penalties in addition to other applicable remedies: generally $25,000 per day for each violation, with a separate bracketed rate of $25,000 to $100,000 per MW of rated capacity, per day, for each paragraph 4 energy-obligation violation. Confirm the rate and terms in the executed agreement. These are distinct from Act 21’s reporting penalty. 7. Is peak demand 10 MW or more? This reporting requirement includes existing operating facilities. Section 1812-B defines a qualifying data center as a facility, campus or interconnected array predominantly housing working servers or similar data storage systems with peak electric demand of at least 10 MW. Section 1813-B requires reports to DEP on the preceding calendar year's consumption by July 1, 2027, and each July 1 thereafter. The statutory report includes monthly energy and water consumption, peak-load energy use, maximum daily water demand, efficiency measures, generation, waste-heat recovery, projected demand and water-protection measures. Section 7.1083(c) of the executive order also specifies parent-company identity, monthly natural-gas consumption, air-protection measures, generation quantities and public-water-system agreements. Its peak-load energy metric uses MWh; the statute uses kWh. Use DEP’s required reporting format and units, reconciling conversions as needed. Section 1816-B provides a $10,000-per-day civil penalty for reporting noncompliance until submission. Proprietary information is protected; aggregated and anonymized data is public. 8. Are you counting on today's generator rules? Section 7.1085(a) directs DEP to examine whether generator regulations should require different technologies or emissions controls, more fully consider cumulative impacts at a facility or nearby facilities, or address generators deployed as grid resources. DEP must recommend any new regulations it identifies as necessary to address impacts unique to data center development and operation. The order sets no deadline for that examination and does not itself enact those future controls or authorize grid-service operation. Apply current engine classifications, operating restrictions and permit conditions. Evaluate any proposed grid-support operation against the specific federal and state rules, orders, permits and agreement terms that govern it. What Sustained Compliance Requires Build a schedule that distinguishes permit and initial-startup obligations from the template’s commercial-operation milestones. Confirm all deadlines, verification requirements and operating conditions in the executed agreement and permits before selecting equipment or committing to an operating schedule. Establish peak demand; evaluate the over-25 MW threshold for the special DEP review tracks, the at-least-10 MW reporting threshold and the separate tax-program certification requirement. Identify the air-permitting authority and schedule local approvals. Evaluate the full generator fleet, applicable engine rules, emissions and required permitting demonstrations. Select compliant equipment and plan source testing where required, along with maintenance and operating records. Develop a site-specific Air Monitor Plan for DEP review, including measurement methods, locations, quality assurance and public reporting. Coordinate the pre-operation report, annual COA report and statutory consumption report as distinct obligations. Alliance Technical Group provides data center generator and stack testing, environmental consulting, and ambient and fenceline monitoring. Our team can help scope the applicable permitting, testing and monitoring work early in project development.

Our third year of recognition highlights Alliance’s commitment to clear communication, meaningful connections, and a positive hiring experience. DECATUR, Alabama - September 16, 2026 — Alliance Technical Group has earned a 2026 Candidate Experience (CandE) Award, continuing its recognition for delivering a positive experience to job candidates throughout the hiring process. The CandE Benchmark Research and Awards Program, part of Survale, evaluates employers through company assessments and direct feedback from job candidates. The awards recognize organizations that provide a fair, transparent, and positive hiring experience. For Alliance, that means keeping candidates informed, respecting their time, and helping them understand the role and the company before making a career decision. This award reflects the work of our talent acquisition team, hiring managers, and employees who take part in the hiring process. We thank them for the care they bring to recruiting and the candidates whose feedback helps us improve. We’re proud to receive this recognition again and will continue using candidate feedback to strengthen our hiring process. Interested in joining Alliance? Explore our open positions.

The Environmental Protection Agency uses audits to safeguard health and the environment by helping facilities discover and fix federal and state law violations. The EPA may audit your facility for several reasons — increased failed calibrations, questionable data for CO2 audits, flow-to-load or heat input changes, reporting errors, late quarterly reports, or as part of an EPA, state, or annual compliance review. This process can be time-consuming and stressful. Your facility can best handle an audit with preparation and a data acquisition system (DAS) like StackVision, Alliance's industry-leading DAS, for monitoring, reporting, and compliance. How Your Data Acquisition System Helps You Pass Regulatory Audits It's essential that you can walk the person certifying compliance at your facility through how all of your compliance averages are calculated and how to make adjustments to parameters. With a DAS like StackVision, you decide how you need to comply and how you want to configure your system — while starting within the framework of a robust compliance engine that gives you full transparency and control. StackVision creates, calculates, records, and retains each of these averages and data points for verification purposes. This traceability is extremely valuable during audits with regulators, since you can show the exact values, processes, and calculations behind any questioned average. Being able to easily prove that quality assurance procedures are in place — and being followed precisely — also gives you firm ground to stand on during an audit. A quick review of a few displays or scheduled reports each morning tells you the state of your system and lets you plan your day. If a monitor is drifting out of control, you can respond. If a calibration check fails, you can act quickly to fix it and reduce downtime. Since much of what used to eat up your time is automated, you have more time to investigate anything trending toward a problem. That doesn't mean the process is out of your hands, though. A good DAS configures the system to fit your needs and the automation level that's right for you. You should also be able to use the software to dig into your data, see charts comparing factors, edit operational data, and add notes, codes, and flags to explain any unusual situation. Additionally, a DAS can provide predictive averages and alarming to help you avoid hazardous or legally challenging situations like exceedances and deviations — helping you stay out of trouble from an environmental or permit perspective while maximizing operating efficiency. Download Our CEMS Regulatory Audit Checklist: CEMS Regulatory Audit Checklist CEMS Audit Checklist: General Questions To prepare for an audit, know the answers to the following general questions. Has this facility ever been through an audit? If yes, when? What was the outcome of the audit, and what was the response to the audit report? What training have plant operators received to understand the permit, their obligations under the permit, and plant management expectations? How often is refresher training provided? What training have the CEM system operators received to understand the permit, their obligations under the permit, and plant management expectations? How often is refresher training provided? What kind of training have the CEM system operators received on maintaining the hardware? How often is refresher training provided? Are there records showing when all the training occurred? Is there documentation describing the topics covered for all the training mentioned? CEMS Audit Checklist: Recordkeeping Questions To prepare for an audit, know the answers to the following record-keeping questions. Does the plant have organized record-keeping or a filing system? Does the plant have a designated area for retaining all working records for the CEM/COM systems? Usually, these are the records for the current year. Does the plant have a designated area for the long-term retention of past operating and maintenance records (at least five years or more)? Remember, even on days the unit does not operate, you still need records proving that the full complement of records isn't required. CEMS Audit Checklist: Quality Assurance Quality Control (QA/QC) Plans To prepare for an audit, know the answers to the following QA/QC plan questions: When was the last time the QA/QC Plan was updated? When was the last time the CEM operators reviewed the QA/QC Plan? Are there any records documenting the dates of review? Are the Designated Representative and Alternate Designated Representative identified in the plan by title and name? Has the plan ever been submitted to the local or state agency for review? If yes, what was the result of that review? What was the plant's reaction to the regulatory review? Is there an outline or written procedure for each of the quality assurance tests in the plan? Does the plan describe how to address invalid data for Part 75 reporting and apply Missing Data algorithms? Does the plan describe how to address invalid data for Part 60 reporting? How to add reason and action codes? Does the plan describe how opacity data is processed when invalid or during maintenance work? Does the plan describe how to calculate monitored values for: 6-minute opacity averages 1-hour averages for Part 75 1-hour averages for Part 60 3-hour averages Extended averages for 24-hour, 30-day, or 30-boiler operating averages CEMS Audit Checklist: Acid Rain Program Questions To prepare for an audit, please do the following: Review the Part 75 CEM Field Audit Manual Have up-to-date copies of the following documents: Part 75 regulations Reporting instructions for Monitoring Plan records Quality Assurance and Certification Emission records Plain English Guide to the Part 75 Regulations Establish a designated location for all correspondence with the EPA, including: Notices for Commencing Certification/Recertification activities Notices for RATAs Submission notices and feedback reports from the EPA via ECMPS Have an up-to-date written procedure for how to prepare, generate, and evaluate EDR files for: Updating and revising Monitoring Plan records Quality Assurance and Certification records Emission Records Have an up-to-date written procedure to review Part 75 submission files prior to submission. Have a written procedure outlining the facility's plans for balancing any SO2 or NOx mass emissions versus allowances (federal or state programs). CEMS Audit Checklist: ECMPS Questions To prepare for an audit, know the answers to the following ECMPS questions: Does the plant know where to find ECMPS information? Does the plant have the latest set of reporting instructions for: Monitoring Plan records Quality Assurance and Certification records Emissions records Does the plant have a procedure for securing and updating the passwords for ECMPS used by the various agents? Need assistance? We're here to support you and make sure your facility is audit-ready.

Working in an environmental group at a facility means managing competing responsibilities — all of which require close attention to detail. When you have in-house procedures, checklists, QA/QC plans, and other organizational aids, you achieve greater consistency and perform tasks more efficiently. Our Monitoring Plan Checklists serve as a built-in reminder for infrequent but recurring activities that can't be missed. Having standardized workplace procedures in place keeps you in compliance and out of trouble with auditors. There's a Better Way — and it starts with planning ahead. Data Review Checklists for CEMS Use the following data review checklists to stay organized and audit-ready: Data Review Checklist for Full CEM Systems Data Review Checklist for Appendix D CEM Systems Data Review Checklist for Appendix E CEM Systems Data Review Checklist for LME (Low Mass Emitting) Monitoring Systems Additional Activities to Keep on Your Radar Quarterly Linearities Before attempting a linearity check, confirm you have more than 500 psi remaining in each cylinder. Review the last few daily calibration checks to verify monitors are responding within normal expectations. Routine Maintenance Equipment and Supplies Routine maintenance is typically performed on a monthly schedule. Set aside time for it, and keep extra equipment and supplies on hand to minimize downtime. Maintaining spare equipment and a contingency plan for unexpected situations is a sound practice. Gas Cylinder Supplies Track your gas cylinder inventory carefully — Protocol I gas cylinders require at least 28 days from order to ship after the vendor receives your request. If you're down to your last set of linearity or daily gas cylinders, order at least two more sets immediately. Shelf life is not a concern; certification sheets typically confirm cylinders remain valid for at least seven years. Compliance Reports Compliance reports are high-stakes documents with specific content requirements. Reporting frequency varies by program — quarterly, semi-annually, or annually. A checklist approach ensures consistency and completeness. Key reports include: Quarterly acid rain files, review documents, and submission records Quarterly excess emissions, downtime, and performance summary reports for state or local agencies Semi-annual monitoring status reports for your operating permit Annual compliance reports for your operating permits Reports for Management Review Facility management needs visibility into unit performance to stay prepared — staffing levels, supply chains, and operational decisions all depend on it. Standard reports to prepare include: Unit/Turbine/Generator Performance Reports Fuel Consumption Reports Generation Reports Multiple Unit Operating Reports A well-maintained set of procedures and supporting documents reduces the burden of ongoing compliance obligations. In the event of staff turnover, documented processes also help new team members understand their responsibilities and get up to speed quickly. Alliance's StackVision DAS includes built-in tools to support your monitoring plan. The QA Test Deadline Report tracks scheduled QA activities — including upcoming linearities, cylinder gas audits, RATAs, annual fuel flow meter calibrations, and NOx Correlation testing (required every five years) — and shows how many days remain before each deadline. The report can be scheduled to print or email automatically, or configured to generate an alarm when a warning threshold is reached. It's one of the more practical tools for avoiding missed QA milestones. Alliance Technical Group also provides regulatory and reporting services for facilities that need additional support managing compliance obligations.

Alliance Technical Group's regulatory experts created an extensive Guide to Part 75 Audit Preparation to help plants stay audit-ready. These helpful checklists are a useful starting point to prepare for an inspection or audit by either a state agency or the Environmental Protection Agency (EPA). For more information, consult the EPA's Field Audit Manual. Download the free 40-page Guide to Part 75 Audit Preparation.

New Global Dashboards and Global User Management bring portfolio-wide visibility and centralized access control to multi-site organizations SkyBridge users can now see what is happening across their operations and manage teams across multiple sites from one place. Two major new features—Global Dashboards and Global User Management—reduce the time spent moving between individual sites, helping multi-site organizations access the information they need and manage user permissions more efficiently. See the Full Picture with Global Dashboards The new Global Dashboard gives SkyBridge users a single place to view compliance data across multiple sites, quickly, easily, and intuitively. No more jumping between sites to piece together a portfolio-level view. What the Global Dashboard delivers: Drill-down navigation: Most numbers and charts are interactive. Select any metric to see the details behind it and navigate directly to the relevant records in SkyBridge. This drill-down experience makes it easier to move from a high-level trend to the underlying information without searching through individual sites. Trend indicators: Color-coded arrow symbols show whether metrics are moving in the right direction. Green indicates favorable movement, while orange or red highlights areas that may require attention. Conditional formatting: This feature changes the appearance of values based on defined thresholds, allowing potential issues to stand out immediately. Time period controls: Switch between data timeframes with tabs or selectors. See today, this week, this month, or whatever timeframe matters most. Customizable and Expandable: A default set of dashboard widgets comes pre-configured and ready to use out of the box. Add additional widgets, rearrange, collapse sections you don't need, or build entirely new dashboards tailored to your workflow. Take the interactive Global Dashboard walkthrough to explore the new portfolio-wide view and drill-down capabilities. Manage Users Across Sites from One Place The new Global User Management feature gives SkyBridge administrators one centralized tool for managing users and permissions across every site they oversee. Managing users across dozens of sites one at a time is a thing of the past. Spend less time on admin. Gain more control over access. What the Global User Managerment feature delivers: Sites View: See all of your sites in one grid. Expand any site to view its users, their permissions, and their admin status. From the same screen, administrators can assign users to a site, update permissions for one or multiple users, or remove access. Users View: The Users view displays every user across the organization’s sites. Expand a user to see which sites they have access to and what permissions they hold. Assign them to additional sites, update their permissions, or remove their access to specific sites without touching their account. Add New Users: Create new SkyBridge user accounts, assign them to one or more sites, and set their default permissions in a single pop-up. No more managing account creation and site access as separate steps. Search and Filter: Both the Sites and Users grids support full-grid search and column-level filtering. Administrators can search by name, email address, or site or filter numerically by user or site counts, making it easier to locate the right record within a large organization. Permission Descriptions on Hover: Not sure what a permission controls? Hover over any permission name to see a plain-language description of exactly what it does. No tab-switching, no external documentation required. Smart Permission Logic: Elevated permissions behave intelligently. Selecting Client Admin automatically grants all other permissions. Selecting Maintenance restricts all other permissions and displays a clear warning. The system prevents invalid permission combinations, so your access configurations are always correct. Last Admin Protection: SkyBridge also protects against the accidental removal of a site’s last administrator. If a removal would leave a site without an admin, the action is blocked with a clear explanation — protecting your team from losing access without a way back in. Take the interactive Global User Management walkthrough to see how administrators can manage users, sites, and permissions from a centralized view. Who Can Access These Features? Global Dashboards are available to all SkyBridge users. Global User Management is available to users with Client Admin permissions. If you believe you should have access but do not see one of these features, contact your SkyBridge support representative. As always, if you have questions or need assistance getting started, our team is here to help.SkybridgeSupport@alliancetg.com What Is SkyBridge? SkyBridge is Alliance Technical Group's cloud-based software platform for managing LDAR, OGI, fenceline monitoring, cooling tower programs, and air permitting data in real time. Field data updates your records the moment it's captured, so teams get accurate, centralized compliance data without juggling spreadsheets or waiting on manual uploads. Learn more about SkyBridge.

The EPA has finalized changes to the Emergency Planning and Community Right-to-Know Act, or EPCRA, hazardous chemical inventory reporting requirements. The changes align the terminology and hazard categories used for EPCRA Sections 311 and 312 reporting with OSHA’s 2012 and 2024 Hazard Communication Standard updates. What Is Changing? For facility owners and operators, the main takeaway is: the hazard information reported on Tier II forms will more closely match the information already provided on your Safety Data Sheets (SDS). Who Does the Rule Apply To? EPCRA Sections 311 and 312 apply to owners and operators of facilities that are required under OSHA’s Hazard Communication Standard to prepare or maintain an SDS for a hazardous chemical. What Does This Mean for My Facility? This is a reporting-process change. The updated Tier II form will contain a larger and more detailed list of hazard categories. However, facilities should generally be able to select the applicable categories directly from the chemical’s SDS instead of interpreting how OSHA classifications fit within broader EPCRA groupings. This should: Reduce inconsistencies between SDSs and Tier II reports. Reduce the amount of interpretation required when preparing reports. Make it easier to transfer hazard information from an SDS to the inventory form. Provide emergency planners and responders with more precise information about the hazards present at a facility. What Should Facility Owners and Operators Do Right Now? No immediate changes are required for the Tier II reports covering calendar year 2026. When Will the Changes Apply? The final rule was published on June 22, 2026, and becomes effective on August 21, 2026. The compliance date for using the new hazard categories is January 1, 2028. EPA expects facilities to use the revised categories for their calendar year 2027 Tier II reports, due March 1, 2028. Preparing for the Change Facility owners and operators should expect a more detailed Tier II hazard-category section beginning with calendar year 2027 reporting. Facilities that need the complete regulatory language, category tables, definitions, and section-by-section revisions can review EPA’s final rule, EPCRA Hazardous Chemical Inventory Reporting Requirements: Conformity With the 2024 OSHA Hazard Communication Standard, published at 91 FR 37022. Navigating this reporting shift doesn't have to fall on your team alone. Alliance Technical Group's Compliance as a Service (CaaS360) includes Tier II Reporting under EPCRA Section 312 — from SDS review and hazard categorization to inventory calculations and LEPC/fire department submission — with one partner managing your compliance calendar.

Alliance Technical Group's Geospatial Measuring of Air Pollutants (GMAP) service is a breakthrough in how we monitor and manage air quality. Geospatial Measurement of Air Pollution is like a high-tech detective for air pollution. It's a mobile service, meaning our team can travel around, gathering information on various air pollutants. It uses sophisticated technology to analyze this data and create detailed maps showing where these pollutants are most concentrated, helping to pinpoint the sources of pollution. Understanding Air Quality Challenges Air pollution is a complex issue. It's not just about the amount of pollutants in the air, but also about understanding how they move and change over time. Traditional stationary monitoring methods only give us a snapshot of the situation, often missing the bigger picture. Pollution doesn't stay put; it spreads and changes with the wind, weather, and other factors. GMAP's ability to move and track pollution in real time gives us a much clearer view of what's happening with our air quality. How GMAP Makes a Difference GMAP is essentially a mobile laboratory. Our team is equipped with advanced instruments to measure different types of air pollutants at numerous points across the facility, including along the fenceline and surrounding roadways. These instruments include multiple gas analyzers and highly accurate GPS systems for mapping. This technology allows for real-time, on-site air quality assessments, which are crucial for quick and effective environmental management. Alliance also collects weather data, bringing together gas analyzers, wind data, and GPS to generate maps. Wind direction is essential to this process as it allows our team to backtrack from the observed pollutant concentration to the potential emission source(s). Picture a petroleum refinery that needs to ensure it's not exceeding pollution limits. GMAP can be brought in to monitor the air both within and around the facility boundary at any location accessible by vehicles (including the facility fenceline, neighboring communities, etc.), giving instant feedback and helping to pinpoint potential areas of concern relevant to environmental regulatory compliance. Tech Trends and Advancements The technology behind GMAP is part of a larger trend towards smarter, more connected environmental monitoring systems. We're seeing a rise in the use of real-time data analysis, Internet of Things (IoT) devices, and advanced mapping software in environmental science. These tools are making it possible to understand and respond to environmental challenges more quickly and accurately than ever before. Benefits of GMAP Real-time Data and Analysis: The ability to gather and analyze data in real time is a significant advantage. It enables quicker responses to potential environmental hazards and helps in making informed decisions to mitigate risks. Advanced Mapping and Analysis: GMAP's geospatial mapping program enhances the understanding of air pollutant dispersion and source identification, which is crucial for effective air quality management. Mobility and Flexibility: Alliance's GMAP can move across a facility and monitor in real time, a significant advantage compared to stationary monitoring devices. This allows for a full picture of pollutant concentrations across the entire site and is less dependent on wind direction. Contribution to Public Health and Environment: By ensuring better compliance with air quality standards and providing accurate data on pollutant levels, GMAP plays a crucial role in protecting public health and the environment. Potential Results and Impact of Using GMAP By providing real-time, accurate information about air pollution, GMAP can have a significant impact on: Improved Public Health: By identifying and addressing pollution sources more quickly, we can reduce exposure to harmful pollutants, leading to healthier communities. Increased Corporate Responsibility: Businesses can use GMAP to monitor their own emissions, helping them to operate more sustainably and responsibly. Alliance Technical Group's GMAP (Geospatial Measuring of Air Pollutants) capabilities combines on-demand mobile monitoring with real-time data to help facilities quickly identify unknown emission sources, strengthen existing monitoring programs, support EPA inspections, and respond rapidly during environmental incidents. Live data is accessible while in the field, enabling faster decisions and more immediate compliance actions. Backed by extensive expertise from the EPA's Office of Research and Development (ORD) GMAP program, Alliance delivers customized monitoring solutions that provide detailed snapshots of air quality conditions and reduce environmental risk. By combining advanced mobile technology with deep regulatory and technical expertise, GMAP helps organizations gain actionable insights, protect public health, and make more informed environmental decisions.

Decatur, AL and Edmonton, AB — 7/14/2026 – Alliance Technical Group, a leading provider of environmental testing, monitoring, and compliance services, announced today the acquisition of Emissions Test Group (ETG), a trusted provider of industrial source emissions testing services headquartered in Edmonton, Alberta. The acquisition strengthens Alliance's presence in the Canadian environmental services market while adding a highly experienced field team with deep expertise across a broad range of emissions testing disciplines. Founded in 2012, ETG has built a strong reputation for delivering safe, accurate, and efficient emissions testing services to industrial clients across Western Canada. The company supports sectors such as oil refining and upgrading, wood products, power generation, chemical production, paper production and mineral/metal refining and production. Its work includes all aspects of source emissions testing, including manual stack surveys, CEMS commissioning and performance tests (RATAs & CGAs), gas turbine DLN tuning, pollution-control efficiency and guarantee testing and process optimization studies. "Emissions Test Group has earned an outstanding reputation in Western Canada through a genuine commitment to client relationships, data integrity, and field excellence," said Chris LeMay, CEO of Alliance Technical Group. "Daryl and his team have built something special; a practice grounded in technical precision and long-term partnerships with the clients they serve. That approach aligns perfectly with Alliance's values, and we're thrilled to welcome them to our growing network." With the addition of ETG, Alliance expands its source emissions testing capabilities in Canada while providing ETG's clients and team members with access to Alliance's broader resources, technical depth, and national platform. "Joining Alliance marks an exciting new direction for ETG and the team we've built over the past decade," said Daryl Zander, Founder of Emissions Test Group. "Our focus has always been on doing the work right, building real relationships with our clients, and earning their trust one project at a time. Alliance shares those values, and this partnership gives us the platform to serve our clients even better while opening doors to new opportunities we couldn't reach on our own." This acquisition underscores Alliance's continued commitment to expanding its environmental testing and compliance capabilities across North America.

A Continuous Emissions Monitoring System (CEMS) is used to continuously measure and record pollutant emissions — such as SO₂, NOₓ, CO, and opacity — from industrial stacks to demonstrate compliance with air quality regulations. These systems operate in harsh industrial environments where heat, moisture, particulate matter, and corrosive gases degrade equipment over time. Most CEMS failures are preventable. Drawing from years of field experience across power generation, industrial manufacturing, and chemical processing facilities, Alliance technicians have identified the most common failure patterns and the maintenance practices that prevent them. 1. Plugged Probe Filters Probe filters are designed to protect the sample system, but excessive particulate loading can quickly overwhelm them. Common causes: Excessive eductor pressure creating too much suction, incorrect probe selection for the application, missing impingement shields, and high particulate loading from the process itself. How to identify it: Watch for frequent filter replacements, reduced sample flow rates, analyzer instability, and rising maintenance frequency. Any one of these can indicate a filter that’s working harder than it should. How to prevent it: Optimize eductor pressure settings, install probe impingement shields where appropriate, and evaluate process conditions that generate excess particulate. Most importantly, match the probe to the application — a standard probe is not always the right tool. In one facility, a standard probe struggled with high particulate loading from a furnace process. After evaluating the application, technicians recommended replacing it with a dilution probe better suited for harsh conditions, significantly reducing maintenance requirements. Failed Probe Filter Dirty Air Purge Filter 2. Moisture Passing Through the Sample Conditioning System Water slip is one of the most common issues encountered in CEMS sample conditioning systems. When moisture bypasses the chiller, analyzers can experience erratic performance, calibration drift, and potential damage. Common causes: Excessive sample flow rates, chiller temperatures set too high, undersized heat exchangers, and inefficient or degraded moisture removal components. How to identify it: Look for unstable analyzer readings, unexplained calibration drift, or visible moisture in sample lines downstream of the chiller. These symptoms are often misdiagnosed as analyzer problems when the root cause is upstream in the conditioning system. How to prevent it: Verify sample flow rates against system design specifications, maintain chiller temperatures appropriate for your application, evaluate heat exchanger capacity relative to actual process conditions, and inspect moisture removal components on a regular schedule. Even small adjustments to flow rate and temperature can dramatically improve moisture removal and protect analyzers from long-term damage. 3. Dirty Instrument Air Systems Instrument air systems provide clean, dry air to analyzers and other sensitive equipment. When neglected, contaminants such as moisture and oil can impact system performance. Common causes: Poor air dryer maintenance, saturated filters, moisture accumulation, and oil contamination. How to identify it: Unexplained analyzer performance issues affecting multiple instruments at once, visible moisture or oily residue in air lines, and accelerated component wear can all indicate a compromised instrument air supply. Because these symptoms mimic other failure modes, instrument air quality is often the last thing checked. How to prevent it: Replace desiccant and filters routinely, inspect tubing for moisture or contamination, and include air cleanup systems in preventative maintenance programs. A clean instrument air supply is foundational to CEMS reliability. Facilities that treat air system maintenance as optional tend to experience recurring, difficult-to-diagnose analyzer problems that disappear once the air supply is properly addressed. Fresh tubing for this Air Clean up System Fresh desiccant, clean filters and new tubing will go a long way to ensure that your daily drift is kept to a minimum 4. Corrosion from Acidic Condensate Corrosion is often a hidden problem that develops gradually until instrumentation begins to fail. Common causes: Acidic condensate formation, incompatible tubing materials, and harsh operating environments. How to identify it: Green deposits on tubing and fittings are a reliable early warning sign of active corrosion and should never be ignored. Unexplained sample flow restrictions, fitting failures, and analyzer contamination can also indicate that corrosion has progressed beyond the surface. How to prevent it: Use corrosion-resistant materials, routinely inspect and flush sample lines, and address moisture issues before corrosion develops. Corrosion frequently appears as green deposits on tubing and fittings — a warning sign that should never be ignored. 5. Improper Shelter HVAC Systems Analyzer shelters require stable environmental conditions to support reliable measurements. Common causes: Undersized air conditioning systems, lack of heating capability, and large temperature fluctuations. How to identify it: Calibration issues that correlate with outdoor temperature changes, analyzer alarms that appear during summer heat or winter cold, and visible condensation inside the shelter are all signs that environmental conditions are outside acceptable limits. How to prevent it: Install HVAC systems designed for year-round operation, maintain stable shelter temperatures, and monitor environmental conditions routinely. Maintaining shelter temperatures between approximately 72°F and 78°F can help improve analyzer stability and reduce calibration issues. Improper HVAC Proper HVAC 6. Dirty Gas Coolers Gas coolers are often overlooked until performance begins to suffer. Common causes: Infrequent inspections, lack of preventative maintenance, and dirt and corrosion buildup. How to identify it: Rising sample temperatures, increased moisture in the sample downstream of the cooler, and declining analyzer stability can all indicate a cooler that’s no longer performing adequately. Because cooler degradation is gradual, the connection to downstream analyzer problems isn’t always obvious. How to prevent it: Conduct regular visual inspections, establish cleaning intervals, and inspect for corrosion and performance degradation. Dirty Gas Cooler 7. Damaged Umbilicals Umbilicals are critical to maintaining sample integrity between the probe and analyzer. Once moisture enters an umbilical, damage can accelerate rapidly, particularly during freeze-thaw cycles. Common causes: Water intrusion, damaged insulation, poor sealing practices, and aging components. How to identify it: Unexplained moisture in the sample system, calibration instability that can’t be traced to the analyzer or conditioning system, and visible physical damage to the umbilical jacket are all indicators. Problems often surface — or worsen — after the first hard freeze of the season. How to prevent it: Inspect umbilicals regularly, verify heater operation, seal connection points, and address leaks before winter weather arrives. Melted Umbilical Tubing 8. Neglected Probe Tubes and Sample Ports Probe tubes and sample ports often receive attention only after a failure occurs. Routine inspections can prevent complete sample flow loss and unexpected outages. Common causes: Lack of preventative maintenance, particulate accumulation, corrosion, and mechanical damage. How to identify it: Declining sample flow, increased pressure drop across the probe, and unexplained analyzer instability can all indicate that probe tubes or sample ports are partially restricted. Complete flow loss is typically the point at which neglected probes are first discovered — at which point an outage is already underway. How to prevent it: Inspect every 12–24 months, remove buildup before restrictions develop, and replace damaged components proactively. Damaged Tube Damaged Probe Tube Stack Probe Tube Damaged Probe Tube 9. Winter-Related Sample System Failures Cold weather can expose weaknesses throughout a CEMS installation. Common problems: Flange leaks, frozen sample lines, calibration instability, and restricted flow paths. How to identify it: Calibration instability that appears during cold snaps, reduced or lost sample flow, flange leaks that develop or worsen in cold weather, and frozen sample lines are the most common winter failure patterns. Systems that performed adequately through fall may fail quickly once sustained cold arrives. How to prevent it: Verify insulation integrity, maintain adequate heat tracing, and inspect vulnerable areas before winter arrives. Preparing for seasonal changes is often far less expensive than responding to winter-related failures. Exposed Spool Weather Damage 10. Installation Errors Even new systems can experience reliability issues when installation details are overlooked. Common causes: Incorrect flange bolt patterns, poor alignment, and improper component placement. How to identify it: Persistent flow problems, unexplained leaks at flanges or connections, and calibration issues that begin at startup and don’t resolve with standard troubleshooting are often indicators of installation errors. Systems with these characteristics frequently benefit from an installation review before further component-level troubleshooting. How to prevent it: Verify flange drawings before installation, follow installation QA procedures, and perform thorough post-installation inspections. A few extra minutes during installation can prevent hours of future troubleshooting. 11. Disorganized CEMS Racks Poor organization can make troubleshooting and maintenance significantly more difficult. Common causes: Unlabeled components, inconsistent tubing routing, poor documentation, and difficult equipment access. How to identify it: Technicians spending excessive time tracing lines before performing routine maintenance, unlabeled or inconsistently labeled components, tubing runs that don’t match current system diagrams, and difficulty locating isolation points or service connections are all signs of a rack that needs organizational attention. How to prevent it: Label components clearly, maintain current documentation, organize tubing and wiring, and conduct periodic system reviews. A well-organized rack not only looks better — it reduces troubleshooting time and improves long-term maintainability. Disorganized CEMS Rack Alliance's CEMS Craftsmanship What Most CEMS Failures Have in Common While the issues above vary, most share the same underlying causes, including deferred maintenance, inadequate inspection frequency, environmental exposure, improper equipment selection, and small issues that go unaddressed until they become outages. The most effective CEMS programs share three traits: scheduled inspections tied to operational cycles, documentation that tracks component condition over time, and a clear escalation path when field technicians identify emerging issues. CEMS Field Services from Alliance Technical Group Alliance Technical Group provides CEMS field services to industrial and utility facilities across North America. Our technicians perform preventative maintenance programs, system inspections and assessments, analyzer troubleshooting and repair, umbilical replacement, calibration and QA/QC support, emergency field service response, and CEMS upgrades and retrofits. Facilities working with Alliance typically use our field services to address recurring reliability issues, prepare for regulatory audits, evaluate aging equipment, or establish a structured maintenance program where none previously existed. If your facility is experiencing unexplained downtime, calibration drift, or compliance data gaps, a CEMS system assessment is a practical starting point. Alliance technicians can evaluate your current installation, identify emerging issues, and recommend a maintenance approach based on your process conditions and regulatory requirements.