EPA Releases Additional Proposed Greenhouse Gas Emissions Reporting Rules for Three Industry Sectors

On March 22, 2010, the U.S. Environmental Protection Agency (“EPA”) released proposed regulations for mandatory monitoring and reporting of greenhouse gas (“GHG”) emissions in three sectors: oil and natural gas production, transmission, and storage facilities; carbon dioxide (“CO2”) injection and sequestration facilities; and facilities that emit fluorinated gases. The proposed regulations supplement EPA’s final GHG monitoring and reporting regulations issued in October 2009 and require most facilities in these three sectors to begin monitoring on January 1, 2011, and filing annual emissions reports on March 31, 2012.

Background

In October 2009, EPA released final GHG emissions monitoring and reporting regulations for 31 industry sectors (the “2009 GHG Reporting Rule”). 40 C.F.R. Part 98; see also Svend Brandt-Erichsen, EPA Issues Mandatory Greenhouse Gas Reporting Rule; Monitoring To Begin January 1, 2010, Marten Law Environmental News (Sept. 23, 2009). EPA’s 2009 GHG Reporting Rule identified three groups of GHG sources that fall within the rule’s requirements: “downstream,” “upstream,” and mobile sources.

Downstream sources are commercial and industrial plants and other types of facilities that have the potential to directly emit significant amounts of GHGs. Sources in 15 categories must report regardless of the volume of their GHG emissions, while most other downstream sources are required to report if their emissions exceed 25,000 tons of GHG per year. Upstream sources include fuel suppliers and suppliers of industrial GHGs. Instead of reporting emissions, these sources report the GHG content of the fuels and gases they supply as a surrogate for the GHG emissions that occur from the end use of their products.

For mobile sources, the 2009 GHG Reporting Rule requires manufacturers and importers of heavy-duty trucks, motorcycles, and off-road engines to report CO2 beginning with model year 2011, and other GHGs starting in later model years. Cars and light-duty trucks are excluded under the rule (EPA has addressed GHG emissions from cars and light-duty trucks under a separate, recently issued rulemaking).[1] The 2009 GHG Reporting Rule required covered facilities to begin GHG emissions monitoring January 1, 2010, and requires that the facilities file their first annual reports to EPA by March 31, 2011. When EPA promulgated the 2009 GHG Reporting Rule, it decided not to finalize all of the rule’s proposed subparts. EPA has now re-issued monitoring and reporting proposals for industry sectors that were excluded from the 2009 rulemaking.

Subpart W – Petroleum and Natural Gas Systems Sector

EPA’s current proposal, Subpart W to 40 C.F.R. Part 98, relates to GHG emissions from petroleum and natural gas systems, a “downstream” GHG source. The sector includes onshore petroleum and natural gas production, offshore petroleum and natural gas production, onshore natural gas processing, natural gas transmission, underground natural gas storage, liquefied natural gas (“LNG”) storage, LNG import and export, and natural gas distribution.[2] The petroleum and natural gas systems sector is generally made up of oil and natural gas extraction wells, storage and processing facilities, and transmission and distribution pipelines. GHG emissions from the sector include fugitive and vented emissions of methane and CO2, as well as flare combustion emissions of methane, CO2, and nitrous oxide. The sector represents a major source of GHG emissions, as illustrated by EPA’s estimate that fugitive and vented GHG emissions from this sector is the second largest source of human-made methane emissions in the United States.[3]

This is the Agency’s second attempt at GHG reporting regulations for the oil and natural gas systems sector. EPA first proposed regulations in March 2009; however, in light of the more than 1,200 pages of comments, EPA decided to redraft the regulations to respond to the numerous issues that were raised. EPA has changed the proposal in three ways. First, the rules add two new reporting segments within the sector—onshore petroleum and natural gas production and natural gas distribution facilities. Second, the rule seeks to reduce the burden on the regulated community by taking a new approach to emissions monitoring in the sector. EPA’s previous proposal relied heavily on comprehensive leak detection and direct measurements for capturing emissions data. Because emissions sources in this sector are relatively diffuse, i.e., thousands of miles of pipelines and valves, EPA recognized that direct emissions monitoring would impose a significant cost on the industry. As a result, EPA’s current proposal allows most facilities to measure emissions through engineering estimates, emission modeling software, and emission factors.[4] Third, EPA seeks to alleviate confusion caused by the previous proposal by providing separate definitions for “vented” and “fugitive” emissions instead of collectively defining both sources as “fugitive.”

EPA’s proposal requires facilities that emit greater than 25,000 metric tons or more per year of CO2 equivalent to report their GHG emissions. Due to the diffuse nature of the storage facilities, wells, and associated pipelines in the industry sector, the proposal contains three different “facility” definitions for three different industry segments, all of which differ from the definition provided in the 2009 GHG Reporting Rule. For example, a facility in the onshore petroleum and natural gas production segment is defined to include all petroleum or natural gas equipment associated with production wells that are under common ownership or control and within one hydrocarbon basin.[5] Therefore, unlike the 2009 GHG Reporting Rule, an onshore production “facility” need not be connected or even located on adjacent properties; rather, the total fugitive and vented emissions from an unconnected network of wells, pipelines, and processing facilities would count towards the 25,000 metric ton reporting limit. Unique facility definitions are also provided for the offshore petroleum and natural gas production and natural gas distribution industry segments. 

Importantly, EPA rejected industry requests for the use of the “best available monitoring method” for all or part of the first year of emissions monitoring. In contrast, the 2009 GHG Reporting Rule provided that covered sources could use the “best available monitoring methods” for the first quarter of 2010, a concession that was intended to give facilities additional time to install equipment or develop more detailed methods for emissions monitoring. The oil and gas industry requested a similar approach under Subpart W, ostensibly to allow for the installation of emissions monitoring equipment during normally scheduled facility maintenance.[6] Subpart W rejects such an approach, concluding that the proposal’s reduced reliance on direct measurements alleviates the need for time consuming equipment installation.

Data collection under the proposal will begin in 2011, and covered sources are required to submit their reports to EPA by March 31, 2012. Similar to the 2009 GHG Reporting Rule, third-party verification is not required, although the reporting entity is required to self-certify the data submitted to EPA. EPA estimates that a total of 3,000 facilities will be required to report under the proposed rule, approximately 1,800 of which are not currently reporting under the 2009 GHG Reporting Rule. The rule’s estimated cost is $60 million for the first year and $25 million per year in subsequent years. EPA has scheduled a public hearing on the proposed rule for April 19, 2010, in Arlington, Virginia, and is accepting public comment on the proposed rule until June 11, 2010.[7]

Subpart RR – Carbon Dioxide Injection and Geologic Sequestration

CO2 is frequently pumped underground to enhance the amount of oil and gas recovered from a deposit. In addition, the underground sequestration of CO2 is being heralded as a potential solution to increasing CO2 concentrations in the atmosphere. Subpart RR to 40 C.F.R. Part 98 would collect emissions information from facilities that inject CO2 underground for the purpose of long-term geologic sequestration (“GS”) or to enhance oil recovery (“EOR”).[8] The rule proposes an all-in requirement, meaning that EOR and GS facilities will be required to report regardless of the amount of CO2 they inject underground. This approach is similar to the 2009 GHG Reporting Rule’s reporting requirements for “upstream” sources, including suppliers of petroleum, natural gas, coal-to liquid products, and CO2.

The rule proposes a two-tiered reporting system. The system reflects EPA’s decision to differentiate between facilities that inject CO2 only to enhance oil recovery and those whose intent is to store the CO2 underground for the long term (EPA’s use of the term “geologic storage” (“GS”) includes storage through EOR as well as storage in deep brines or other geologic formations). In light of this differentiation, the first tier will apply to both EOR and GS facilities, while the second tier will apply only to GS facilities. The first tier has three requirements. First, EOR and GS sources must report the amount of CO2 injected underground. This data will be collected by measuring the flow of CO2, using either mass or volumetric flow meters. Second, facilities are required to report the mass of CO2 transferred on-site from offsite sources. EPA will use this data to estimate the amount of CO2 that is recycled in EOR operations. The first two requirements must be reported quarterly to EPA. Third, facilities are required to report their CO2 supply source, if known. EPA seeks this information to differentiate between natural and man-made sources of CO2 used in EOR and GS activities. The first-tier deadline to begin monitoring is January 1, 2011, while reporting would begin March 31, 2012.

The four second-tier requirements only apply to GS facilities. Under this second tier, GS facilities must report: (1) the amount of CO2 leaked to the surface after injection; (2) the amount of CO2 produced in oil or gas (for GS facilities conducting active EOR operations); (3) the amount of fugitive and vented CO2 emissions from surface equipment (unless these emissions are reported under Subpart W discussed above); and (4) the calculated total amount of sequestered CO2.

A major component of the rule will be quantifying the amount of CO2 that returns to the surface. To meet that challenge, EPA’s proposal requires GS facilities to implement a site-specific monitoring, reporting, and verification (“MRV”) plan. The MRV plan lays out the process by which the GS facility will monitor the amount of CO2 leaked to the surface. According to the proposal, monitoring devices employed under the plans may include seismic monitoring, soil-gas monitoring, or other technologies. Other monitoring technologies that have been proposed by researchers include groundwater monitoring and the use of tracer gases or isotopes. GS facilities are required to submit their MRV plans to EPA for approval, and tier-two monitoring and reporting will not begin until EPA has approved the plan. Once approved, GS facilities have thirty days to begin implementation of the MRV plan. Once implemented, the facility would begin tier-two monitoring and would submit the tier-two data in the next annual report following EPA’s approval of the MRV. GS research and development projects, as defined in 40 C.F.R. § 98.6, would not be required to submit an MRV plan for approval or comply with tier-two requirements; however, these projects would be subject to the proposal’s tier-one monitoring requirements.

Although the 2009 GHG Reporting Rule provides several off ramps that allow a facility to stop monitoring and reporting when GHG emissions drop below the threshold for a specified number of consecutive years, because GS and EOR facilities are required to report regardless of the amount of CO2 injected, Subpart RR takes a different approach. Facilities will not be allowed to stop reporting under tier one unless the facility’s injection wells are plugged. In addition, GS facilities will be required to report tier-two data until the CO2 plume and pressure front have stabilized.

Under the 2009 GHG Reporting Rule, upstream suppliers of CO2 for GS and EOR are currently required to report under Subpart PP. EPA believes that the addition of downstream emissions monitoring under Subparts W and RR will provide sufficient data to track the “growth and efficacy of geologic sequestration over time and to evaluate relevant policy options related to this climate change mitigation strategy.”[9] EPA estimates that the proposed rule will cost EOR facilities $4,000 per year and GS facilities $300,000 per year. EPA has scheduled a public hearing on the proposed rule for April 19, 2010, in Arlington, Virginia, and is accepting public comment on the proposed rule until June 11, 2010.[10]

Fluorinated GHGs

EPA’s third proposed rule released on March 22, 2010, concerns the mandatory monitoring and reporting of fluorinated GHGs from facilities that emit 25,000 metric tons or more of CO2 equivalent per year. The proposed rule covers a variety of fluorinated gases, including hydrofluorocarbons (HFCs), nitrogen trifluoride (NF3), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6), among others. The proposal affects the following sources: electronics manufacturers,[11] fluorinated gas producers,[12] sources that use electric transmission and distribution equipment, [13] entities that import or export equipment pre-charged with fluorinated GHGs or containing fluorinated GHGs in closed-cell foams,[14] and sources that manufacture electric transmission and distribution equipment.[15]

EPA estimates that fluorinated GHGs comprise two percent of GHG emissions in the United States; however, small amounts of fluorinated GHGs can be extremely harmful because they are generally thousands of times more effective than CO2 at trapping heat within the atmosphere.[16] In addition, these gases are incredibly persistent, with some fluorinated GHG emissions remaining in the atmosphere for millennia.[17] EPA originally proposed GHG rules for three of the five source categories in its 2009 GHG Reporting Rule proposal; however, due to the comments received, it chose not to finalize the rules. With this new proposal, EPA has added two additional sources—electrical transmission and distribution equipment manufacture (Subpart SS) and imports and exports of pre-charged equipment and closed cell foams (Subpart OOa). EPA’s proposal requires covered sources to begin monitoring on January 1, 2011, and reporting to EPA on March 31, 2012.

EPA calculates the current proposal’s cost at $6.1 million for the first year and $3.9 million per year in subsequent years. EPA has scheduled a public hearing on the proposed rule for April 20, 2010, in Washington, D.C., and is accepting public comment on the proposed rule until June 11, 2010.[18]

Conclusion

EPA’s current proposals build on the framework established by the 2009 GHG Reporting Rule. Like the 2009 GHG Reporting Rule, the proposed rules do not limit or control GHG emissions; rather they seek to collect data regarding GHG emissions across a variety of industry sectors. EPA’s proposals address industry sectors that were not covered by the original rule because emissions monitoring in those sectors was difficult or exceedingly complex. In the future, EPA will likely continue to propose new GHG monitoring rules for other industry sectors that were excluded from 2009 GHG Reporting Rule.

For more information on EPA’s proposed GHG monitoring and reporting rules, contact Russell Prugh or any member of Marten Law’s Climate Change practice.