On November 8, 2010, the United States Environmental Protection Agency ("EPA") finalized reporting requirements for the petroleum and natural gas industry sector under its Mandatory Greenhouse Gas ("GHG") Reporting Rule, which are located in Subpart W of 40 C.F.R. Part 98 ("Subpart W"). Subpart W imposes substantial new obligations relating to the monitoring, calculation and reporting of GHG emissions by covered members of the industry, often from emissions sources that historically never have been subject to federal air regulations. The applicability threshold, specialized definitions and lack of a de minimis exemption in Subpart W ensure far-ranging practical and financial impacts for the industry, including small onshore producers and operators of marginal wells.

    The final rule applies to onshore petroleum natural gas production facilities, onshore natural gas processing plants and onshore natural gas transmission compression facilities, as well as to the following industry segments: offshore petroleum and natural gas production, underground natural gas storage, liquefied natural gas ("LNG") storage, LNG import and export, and natural gas distribution. Under the rule, facilities emitting 25,000 or more metric tons per year of carbon dioxide equivalent ("CO2e") must calculate and report their GHG emissions from specified emissions sources. Because the GHG of primary concern for the oil and gas industry is methane, however, this applicability threshold will be considerably lower than 25,000 tons because methane has a global warming potential 21x greater than carbon dioxide (i.e., one ton of methane is equivalent to 21 CO2e).

    Perhaps most significantly, the final rule retains the basin-wide definition of "facility" for the onshore production segment that was contained in the proposed rule, which many industry sources challenged as fundamentally unworkable. Specifically, a single onshore production "facility" is defined to include all petroleum or natural gas equipment on a well pad or associated with a well pad and CO2 enhanced oil recovery operations that are under common ownership or control and that are located in a single hydrocarbon basin as defined by the American Association of Petroleum Geologists ("AAPG").*  Because the reporting entity for purposes of onshore production is the entity holding the state drilling permit, where a permit holder operates more than one well in a particular basin, all wells and their associated equipment would be considered a single "facility," and the GHG emissions associated with those wells must be aggregated to determine the applicability of the rule. Taken together, these definitions mean that a particular company will only have one onshore production "facility" per basin, regardless of the number, interconnectedness or proximity of the wells involved. Compounding this issue, many of these AAPG basins are very large and cover several states-- West Virginia, for example, is divided into two basins that extend beyond the State's borders to encompass much of the Appalachian region. Obviously, the likelihood of surpassing the 25,000 CO2e applicability threshold will increase with the size of the relevant basin. Due to the varied number of specific emissions sources at individual well pads, GHG emissions from well pads will be highly variable and difficult to generalize;**  however, operators of numerous wells within a single basin, particularly wells with large production volumes and significant associated equipment, should evaluate carefully the potential applicability of the rule.

    With regard to specific requirements, Subpart W requires covered facilities to report carbon dioxide (CO2) and methane (CH4) from equipment leaks and venting, and CO2, CH4 and nitrous oxide (N2O) emissions from gas flares and combustion sources. Calculation methodologies generally include the use of engineering estimates, emissions modeling software and emissions factors, though direct measurement is still required for certain emissions sources when other methods are not feasible. Consistent with previously finalized GHG reporting rules for other industry sectors, reporters meeting specific criteria may use best available monitoring methods for certain emissions sources for a limited period during the 2011 reporting year, rather than the methodologies specified in the final rule. Approved "best available" methods include monitoring methods currently in use by the facility that do not meet Subpart W's specifications, supplier data, engineering calculations or other company records. 

    EPA has estimated that implementation of Subpart W by the industry will cost an average of $16,000 per facility in the first year and $7,000 per facility annually thereafter. Various members of the industry, however, have rejected EPA's cost estimate as drastically understating-according to some analyses, by at least two orders of magnitude-the financial burden that compliance with the rule will place on individual oil and gas companies, and particularly smaller businesses. The result, according to industry organizations, is a significantly disparate impact on the oil and gas industry vis-à-vis other industry sectors subject to reporting obligations under other sections of EPA's mandatory GHG reporting program.

    EPA's issuance of Subpart W so late in 2010 has left very little time for facilities subject to the rule to make their initial applicability determinations and undertake whatever preparatory steps are necessary before it becomes effective. Covered sources are required to begin data collection on January 1, 2011, with the first annual report to be submitted on March 31, 2012, for calendar year 2011 emissions. Companies potentially affected by the final rule are encouraged to take quick action to make a formal determination regarding Subpart W's applicability before the rule's requirements take effect. EPA plans to develop voluntary screening tools for the industry to assist potential reporters in determining the applicability of Subpart W, which the agency anticipates will be based on easily determined inputs such as major equipment or operational counts. Generally, these applicability tools would only serve as a guide to identify those facilities that are clearly well below or well above the reporting threshold, while those facilities that are close to the threshold and will need to collect further information to confirm whether they fall within the scope of Subpart W.

    Additional information regarding Subpart W is available at EPA's website. We will be happy to assist in interpreting the requirements of this important new rule.

*In an important clarification actively sought by industry, EPA has emphasized that this definition of "facility" for onshore production facilities is limited to Subpart W and does not impact other EPA air regulations. Nevertheless, this definition may set a troubling precedent regarding the legitimacy and viability of aggregating emissions from multiple wells in future air-related regulatory efforts.

**In EPA's analysis of average emissions associated with individual well pads, emissions ranged from 370 metric tpy CO2e (so that approximately 68 wells equals 25,000 metric tpy CO2e) to approximately 4927 metric tpy CO2e (so that approximately five wells equals 25,000 metric tpy CO2e). EPA, Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry: Background Technical Support Document, p. 31. Some very low-producing wells may have annual emissions that fall below EPA's low-end estimate.

A version of this article was printed in the December 2010 edition of IOGA News, a publication of The Independent Oil and Gas Association of West Virginia, Inc.