EPA Finalizes GHG Reporting for Oil and Natural Gas Operators

By Georgette Reeves


Reporting Source Categories

On November 8, 2010, the EPA finalized GHG reporting for oil and natural gas systems. The regulation was originally proposed in April 2010.  The effective date of the final rule is 30 days after publication in the Federal Register or December 31, 2010, whichever is earlier, which means that data collection is to begin on January 1, 2011, with the first report due to EPA in March 2012.  Certain “facilities” belonging to the following sectors of the oil and gas industry are required  to report under this subpart: offshore petroleum and natural gas production, onshore petroleum and natural gas production, onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, liquefied natural gas (LNG) storage, LNG import and export equipment and natural gas distribution. 

Facilities emitting greater than 25,000 metric tons (MT) CO2 equivalent (CO2e) will be required to report their GHG emissions for a wide variety of activities including fugitives from equipment leaks as well as directly vented carbon dioxide and methane emissions.  The rule defines “facilities” in the onshore production and distribution sectors differently than the general facility definition provided in Subpart A.  As published in the proposed rule, the final rule requires oil and natural gas production sites (i.e., wellheads) to be aggregated by hydrocarbon basin when considering the 25,000 MT reporting threshold.  Also, for distribution, Subpart W defines "facility" as a collection of emissions from distribution pipelines, metering stations and regulating stations operated by a Local Distribution Company (LDC) that is regulated as a separate operating company by a public utility commission or that are operated as an independent municipally-owned distribution system.

In the finalized rule, for the onshore production sector, EPA has provided emission factors based on component population counts in place of the originally proposed direct measurement required to identify leakers, providing some relief to the production sector that will struggle just to compile accurate component counts for a large number of facilities in remote locations. However, the inclusion of aggregation in both the production sector (basin wide) and the LDC sector (collection of all distribution pipelines, metering stations, and regulating stations) will require GHG reporting from oil and natural gas sectors that have likely never been considered sources of air emissions until now.  The final rule requires leak detection testing at subject facilities belonging to the onshore processing, onshore transmission compression, underground gas storage, LNG storage, LNG import and export equipment and gas distribution sectors.

Triggering the reporting threshold

A threshold of 25,000 MT of any pollutant may sound like a lot, but for oil and natural gas producers, it is a threshold that’s easy to reach - especially when considering basin-wide aggregation of production activities. Here are some examples of activities that would trigger the reporting threshold for this regulation:

To reach 25,000 MT CO2e:
Natural Gas Combustion 471.5 MMscf/yr(53.8 MMBtu/hr)
Vented Methane 63.3 MMscf/yr (173 Mscfd)
Compression Horsepower ~ 7,500 bhp @ 7,000 btu/bhp-hr

For oil and natural gas producers, any combination of the above exceeding 25,000 MT CO2e per year within a hydrocarbon basin could trigger GHG reporting under this subpart.

Coping with compliance

Trinity has been assisting oil and natural gas operators nationwide with Subpart W compliance by assisting with gap analyses, data management strategies and regulatory impact summaries.  Trinity will be offering a complimentary webinar presenting the final requirements of Subpart W on Thursday, November 18th at 10:30 AM CST and December 7th at 10:30 AM CST.