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”) on November 8, 2010.   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”).¹  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; ² 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.

For more information on this topic, please contact:
M. Katherine Crockett
304.340.3832

[email protected] This e-mail address is being protected from spambots. You need JavaScript enabled to view it