Contact Alliance Technical Group for environmental testing, monitoring & lab services. 50+ locations across US & Canada. Call 256-351-0121 or email today. Reach out to us for your testing, monitoring, and lab needs. 256-351-0121 Experience a better way with Alliance. Request more information below or use the locations map to contact one of our offices directly. Our Reach With over 60 testing and laboratory locations across the United States and Canada, we are where you need us. Contact us

Environmental compliance solutions including regulatory strategy, air permitting & compliance tracking. Build your winning strategy with Alliance consultants. Services / Environmental Compliance / Compliance Compliance Services Navigating compliance with confidence. Alliance Technical Group provides end-to-end environmental compliance services including LDAR auditing, EHS program management, and OSHA training for chemical, petroleum, and manufacturing facilities regulated under federal and state environmental law. Streamlined support. Improve operational efficiency with a compliance partner you can trust—saving you time, money, and aggravation. Reduced risk. Tailored and timely solutions mean fewer failed inspections. We work with you to customize a plan that fits your specific needs. Confident compliance. With active roles in a multitude of trade organizations and regulatory bodies, we ensure you stay ahead of new regulations and changes. Services & Solutions Air Reporting Deadlines Interactive Map Staying compliant with environmental air reporting deadlines shouldn’t be a guessing game. That’s why we created a free interactive U.S. map that lets you: Find your state's specific air reporting deadlines Print a customized deadline list for your state Add key deadlines directly to your calendar Explore the map and take control of your compliance. VIEW AIR REPORTING MAP Environmental Compliance LDAR Compliance Audits & Management | EHS Compliance as a Service | Health & Safety Consulting and Training | Risk Assessments & Mitigation Planning | Industrial Hygiene Assessments | HON Fenceline/HON RTR Expertise The teams of environmental engineers, industrial hygienists, and industry specialists at Alliance Technical Group have decades of experience serving the environmental, health, and safety needs of clients in both the public and private sectors. We offer a full range of EHS services to help you protect your employees and the environment and to ensure your workplace stays in compliance, including: LDAR Compliance and Auditing Services Having extensive experience with Federal (NSPS, MACT, RCRA) and State-level LDAR standards impacting the chemical manufacturing, petroleum refining, and oil & gas industries, Alliance consultants are well-versed in enhanced LDAR programs required under US EPA Consent Decree. Our LDAR service offerings extensively include Audits, Analyses Assessments, Program development, Reporting, and more. EHS Compliance as a Service CaaS360 A proprietary fixed-fee monthly environmental program to provide full-service compliance assistance. By integrating regulatory and training expertise with our in-house supporting disciplines, we can ensure a seamless approach to project management and environmental compliance throughout the project lifecycle and beyond. Module I – Waste Management Module II – Stormwater & Wastewater Module III – Spill Prevention Control & Countermeasure Module IV – Emergency Planning & Community Right to Know Module V – Comprehensive Air Services REQUEST INFORMATION Health & Safety Consulting and Training Services We’re ready to help you achieve a higher level of health and safety in your industrial workplace by providing full-service compliance assistance and specialized training. Our experienced Environmental, Health, and Safety (EHS) team provides expert monitoring and testing services to ensure industrial and manufacturing facilities are in compliance and provide a safe workplace for employees. Consulting Services Industrial Hygiene Monitoring Asbestos Inspections Indoor Air Quality Assessments Mold & Fungal Testing Combustible Dust (DHA) Silica OSHA Program Audit OSHA Program Development Confined Space Awareness & Entry Control of Hazardous Energy (LOTO) Respirator Fit Testing Noise & Audiometric Testing Training Services RCRA Hazardous Waste Management DOT Hazardous Materials Transportation Wastewater Physical Chemical & Biological HAZWOPER 8, 24, 40 Confined Space Awareness & Entry OSHA 10 hr. & 30 hr. General Industry & Construction Hazard Communication First Aid CPR Bloodborne Pathogens Aerial Lift Truck Control of Hazardous Energy (LOTO) Arc Flash (NFPA 70E) Low Voltage Respirator Training Stay up on Compliance with Alliance. Back to All Services

Meet all your environmental lab testing and analysis needs seamlessly with our full-service laboratory in Seattle, WA. Services / Lab Testing & Analysis / Environmental Labs / Seattle Environmental Lab Seattle Environmental Lab About Alliance Technical Group's Seattle Branch is a full service environmental laboratory in the Fremont neighborhood of Seattle, Washington. Founded in 2007 as Fremont Analytical, Inc., and joining Alliance Technical Group in 2023, we continue to provide high-quality laboratory services to a broad client base. All staff members are trained professionals whose technical knowledge and analytical skills are reinforced by extensive and varied experience within the environmental science industry. Alliance Technical Group’s Seattle laboratory is certified by the National Environmental Laboratory Accreditation Program (NELAP), Washington State Department of Ecology (WADOE), Alaska Department of Conservation (DEC), and the Department of Defense (DOD) for organic, inorganic, and general chemistry analyses. The laboratory follows approved methods (EPA, Standard Methods, ASTM, State specific methods) for the examination of sediment, soil, water, and air. 206-352-3790 REQUEST INFORMATION Core Capabilities Organic Analysis of Soil & Water Volatile Organic Compounds (VOCs) – EPA 8260 / 624 Semi-Volatile Organic Compounds (SVOCs) – EPA 8270 / 625 Polyaromatic Hydrocarbons (PAH) – EPA 8270 SIM / 625 SIM Diesel/Heavy Oil Range Organics (DRO) – NWTPH / EPA 8015 / AK 102+103 Gasoline Range Organics (GRO) – NWTPH / EPA 8015 / AK 101 Organochlorine Pesticides – EPA 8081 / 608 Polychlorinated Biphenyls (PCBs) – EPA 8082 / 608 Herbicides – EPA 8151 Dissolved Gases (Methane, Ethane, Ethene) – RSK-175 EPH – NWTPH-EPH VPH – NWTPH-VPH Inorganic Analysis of Soil & Water MTCA 5, RCRA 8, PP Metals, TAL Metals – EPA 6020 / 200.8 / 245.1 Mercury – EPA 7470 / 7471 / 245.1 Cation Exchange Capacity Ferrous Iron – SM 3500 Fe B Hexavalent Chromium – SM 3500 Cr B / EPA 7196 TCLP Extraction – EPA 1311 General Chemistry Anions – EPA 300.0 Biological / Chemical Oxygen Demand (BOD/COD) Cyanide (Total or Amenable), Sulfide (Total or Soluble/Dissolved) Grainsize Flashpoint / Ignitability Nutrients (Ammonia, Phosphorus, Nitrate/Nitrite) Oil & Grease (HEM) – EPA 1664 Solids: TDS, TSS, TS, SS TOC / DOC – SM 5310B Total Coliform / E coli, Fecal Coliform, Enterococcus pH, Alkalinity, Hardness, Conductivity, Salinity, Turbidity Air/Soil Vapor/Stack/RNG Volatile Organic Compounds – TO-15 APH – TO-15 / MASS APH Sulfur Compounds – ASTM D5504 Siloxanes – ASTM D8230 Major Gases – EPA 3C Fuel Parameters – EPA 1945 / 3588 Helium – EPA 3C MOD Metals / Mercury – NIOSH 7303 / 6009 Particulates, Hexavalent Chromium, Ammonia Wide variety of passivated canisters, cylinders, and glass Lab Information Sample Receiving Hours: Monday-Friday, 8:00 AM - 5:00 PM Saturday and Sunday receiving as per request Samples received after 4:00 PM begin TAT next business day at 8:00 AM Turnaround Times Standard TAT is 5 business days for most analyses. A subset of analyses involving extra handling or trace-level sensitivity require a standard TAT of 10 business days. Contact lab for details. Expedited options available: Standard 5-day TAT 4 days 3 days 2 days Next day Same day Standard 10-day TAT 7 days 5 days 3 days 2 days Next day Same day *Expedited TAT should be coordinated in advance Sample Pickup & Delivery Courier service available for sample pickup & supply delivery Service radius: typically, 100-mile radius from lab Courier fees apply, contact lab for details Containers & Supplies Sampling containers provided upon request Chain-of-custody forms, coolers, and ice available upon request 5035 soil sampling kits: green handle & syringes Air sampling: canisters, high pressure cylinders, flow regulators, manifolds, tedlar bags available upon request Contact lab for specific container requirements, holding times, and preservatives Reporting & Data Deliverables QC Packages Level II, IIb, III Level IV Drinking Water reporting available DOH panels available upon request Electronic Data Deliverables (EDD) Wide range of existing EDD templates Custom EDD formatting available, tailored to specific project or client requirements. Certifications & Programs State Certifications WADOE TNI accreditation via ORELAP Alaska DEC DoD QSM 6.0 Programs Washington MTCA ADEC CULs RCRA View Accreditations & Certifications Additional Resources Client Portal Login → Chain of Custody Forms: Chain of Custody (Standard) pdf fillable form Chain of Custody (Air) pdf fillable form Chain of Custody (Drinking Water) pdf fillable form Container Requirements pdf printer friendly Seattle Laboratory Get the Best of Both Worlds. Together. One National Network. ALL Your Lab Needs. Reach an experienced lab advisor today for help at your site. First name* Last name* Phone* Email* How can we help?* Talk to an Expert map Back to All Services

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.