monitoring, recordkeeping, and reporting from the facilities covered by
proposed subpart W. On the other hand, several commenters asserted that
the proposal was within EPA's authority under the CAA.
    Response: As explained in Section I.C. of this preamble, Section
I.C and Q of the 2009 final Part 98 preamble (74 FR 56260), and the
document Mandatory Greenhouse Gas Reporting Rule: EPA's Response to
Public Comments, Volume 9, Legal Issues (EPA-HQ-OAR-2008-0508), EPA is
promulgating subpart W under its existing CAA authority provided in CAA
section 114. EPA disagrees with the commenters that it does not have
statutory authority to require monitoring, reporting and recordkeeping
from facilities in the petroleum and natural gas systems source
category. The Administrator may gather information under CAA section
114, as long as that information is for purposes of carrying out any
provision of the CAA. For example, CAA section 103 authorizes EPA to
establish a national research and development program, including non-
regulatory approaches and technologies, for the prevention and control
of air pollution, including GHGs. The data collected under this rule
will also inform EPA's implementation of CAA section 103(g) regarding
improvement in sector based non-regulatory strategies and technologies
for preventing or reducing air pollutants. For more information about
EPA's legal authority please see the related sections and documents in
the preamble for subpart W.
6. Designated Representative
    Comment: Several commenters stated that EPA lacked the authority to
require facilities to collect data on equipment and activities that may
be operated or provided by a third party service provider and then
require a designated representative to certify those emissions data.
Other commenters supported the inclusion of emissions data from
equipment operated by third party service providers by stating that
these emissions are critical to ensuring that facilities with different
operational structures have equitable coverage in a reporting program
and that a complete profile of emissions from the production sector is
obtained.
    Response: As explained in Section V of the preamble of the 2009
final part 98 (74 FR 56355), all reporters must select a designated
representative (DR) who is responsible for certifying, signing, and
submitting all submissions to EPA. This provision provides flexibility
to the owners and operators to choose any individual, employee or non-
employee, to represent them, while ensuring EPA has one accountable
point of contact. As explained in the preamble to the final part 98,
the high level of public interest in the data collected, as well as its
importance to future policy, warrants establishment of a high standard
for data quality and consistency and high level of accountability for
reported data. The DR provisions and certification requirements help
ensure the standard for high quality data and consistency is met. The
DR provisions are crafted similarly to the provisions of the Acid Rain
Program (ARP), 40 CFR part 72 and EPA has found that this approach
provides a high degree of both data quality and consistency and
accountability.
    Similar comments were made about the data coming from multiple
owners and operators and the concerns about the certification of those
data upon promulgation of the ARP and the 2009 final GHG reporting rule
to which we responded, and for which responses are summarized. We have
attempted to provide maximum flexibility while ensuring accountability.
For integrity of the program, one representative of the owners and
operators must report for important reasons. Doing so ensures the
accountability of owners or operators by, inter alia, reducing the
likelihood of inconsistent submissions by a facility. Interposing
another person or party between the facility and the Agency would
dilute the DR's responsibility and in effect create multiple DRs for
the facility. Additionally, leaving the ultimate responsibility of
submission with the designated representative has the salutary effect
of clarifying that the DR should be aware of all submissions and should
inquire of the persons with personal knowledge of the information in
those submissions. The DR has the flexibility to delegate duties, such
as the preparation of submissions, but retains the ultimate
responsibility to sign and certify all submissions. (See, 58 FR 3590,
3598, January 11, 1993.)
    Furthermore, while the DR or his delegatee may need to acquire
necessary reporting information from a third party, the DR must make
the appropriate inquiries and certification when reporting; ultimate
responsibility rests and must necessarily rest on him or her. The DR
may provide in contracts, leases, or other agreements with third
parties that true, accurate, and correct reporting information must be
provided to the DR in a timely fashion. If the third party fails to
provide timely, true, accurate, or correct information to the DR, then
the DR has recourse contractually, or otherwise, on the third party.
Finally, in recognition of their potential need to adjust contracts,
leases, or agreements accordingly, additional flexibility has been
provided in the rule to allow facilities to utilize best available
monitoring methods for a limited period. For more information, see
Section V of the preamble to the 2009 final Part 98 (74 FR 56260) and
the document Mandatory Greenhouse Gas Reporting Rule: EPA's Response to
Public Comments, Volume 11, Designated Representative and Data
Collection, Reporting, Management and Dissemination (EPA-HQ-OAR-2008-
0508).
7. Applicability
    Comment: Multiple commenters requested that EPA develop a set of

screening tools to assist in the determination of which entities would
be required to report under subpart W of 40 CFR part 98.
    Response: Similar to what EPA has already provided for other
subparts of the Greenhouse Gas Reporting Program to help reporters
assess the applicability of the Greenhouse Gas Reporting Program \5\ to
their facilities, EPA plans to develop voluntary screening tools for
the petroleum and natural gas source category. EPA anticipates that
such tools would be based on easily determined inputs such as major
equipment or operational counts. While the tools would be designed to
provide help to potential reporters for complying with the rule,
compliance with all Federal, State, and local laws and regulations
remain the sole responsibility of each facility owner or operator
subject to those laws and regulations. The tools would be a guide to
determine those facilities that are clearly well below the reporting
threshold, those clearly above, and those close to the threshold who
will need to collect further data to make a proper determination.
---------------------------------------------------------------------------

    \5\ http://www.epa.gov/climatechange/emissions/GHG-calculator/
index.html.
---------------------------------------------------------------------------

III. Economic Impacts of the Rule

    This section of the preamble summarizes the costs and economic
impacts of the final subpart W rulemaking, including the estimated
costs and benefits of subpart W, and the estimated economic impacts on
affected facilities, including estimated impacts on small entities.
Complete details of the economic impacts of the final subpart W rule
can be found in the Economic Impact Analysis (EIA) in the rulemaking
docket (EPA-HQ-OAR-2009-0923).
    This section also contains a brief summary of major comments and
responses on the economic impacts of the rule. EPA received a number of
comments on the estimated compliance costs as well as other comments
covering a variety of topics. Responses to significant comments can be
found in Mandatory Greenhouse Gas Reporting Program: EPA's Response to
Public Comments, Cost and Economic Impacts of the Rule, Docket EPA-HQ-
OAR-2008-0508.

A. How were compliance costs estimated?

1. Summary of Method Used To Estimate Compliance Costs of the Final
Rule
    EPA estimated costs for each affected petroleum and natural gas
industry facility to comply with subpart W. These estimates capture the
costs associated with monitoring and reporting both equipment leaks and
vented emissions and incremental combustion-related emissions.\6\ EPA
based the estimates on the number of labor hours to perform specific
activities, the cost of labor, and the cost of monitoring equipment.
---------------------------------------------------------------------------

    \6\ Reporting entities that equal or exceed the subpart W
threshold for equipment leak and vented emissions must report
combustion emissions under subpart C, except for onshore production
and LDCs, which must report combustion emissions under subpart W.
Incremental combustion emissions refer to those from entities that
did not trigger the subpart C threshold in the absence of subpart W.
---------------------------------------------------------------------------

    The costs of complying with the rule will vary from one petroleum
and gas industry segment and facility to another, depending on factors
such as the types of emissions, the number of affected sources at the
facility and existing maintenance practices, monitoring, recordkeeping,
and reporting activities at the facility. The costs include
expenditures related to monitoring, recording, and reporting process
emissions and, as relevant, emissions from stationary combustion.
    Staff activities and associated labor costs may also vary over
time. In particular, start-up activities, such as the installation of
ports for compressors to allow for spot measurements, result in notably
higher costs in the first year. Costs would also vary over time when
site-specific emissions factors are developed every 2 or 3 years. Thus,
EPA developed cost estimates for year one, which include start-up and
first-time reporting, and for subsequent year reporting.
    EPA estimated annual costs in 2006 dollars using the 2006
population of emitting sources. In addition, the agency estimated costs
on a per entity basis and weighted them by the number of entities
affected at the 25,000 metric tons CO2e threshold.
    To develop compliance cost estimates, EPA gathered existing data
from EPA studies and publications, industry trade associations and
publicly available data sources (e.g., labor rates from the Bureau of
Labor Statistics) to characterize the processes, sources, segments,
facilities, and companies/entities affected. EPA also considered cost
data submitted in public comments on the proposed rule.
    Next, EPA estimated the number of affected facilities in each
source category, the number and types of process equipment at each
facility, the number and types of processes that emit GHGs, process
inputs and outputs (especially for monitoring procedures that involve a
carbon mass balance), and data that are already being collected for
reasons not associated with the rule (to allow only the incremental
costs to be estimated).
    Labor Costs. The costs of complying with and administering this
rule include time of managers, and of technical, operational and
administrative staff in the private sector. Staff hours were estimated
for activities, including:

     Developing a plan: Reporting entity management, legal,
and technical staff hours to determine applicability of the rule,
organize training on rule requirements, identify staffing
assignments, train staff, and schedule activities as required below.
     Setting up records: Technical and field staff hours to
develop data collection sheets and analytical model equations or
linkages to input data into software programs.
     Collecting field data: Technical and field staff hours
to collect necessary site-specific data and input that data into the
analytical input tables.
     Monitoring: Staff hours to procure, install, operate
and maintain emissions monitoring equipment, instruments and
engineering analysis systems.
     Engineering models: Technical staff hours to link and
execute engineering emissions estimation models and analytical
procedures and to organize output data as required for reporting
emissions.
     Recordkeeping: Staff hours required to organize, file
and secure critical data and emissions quantification results as
required for reporting and for documenting determinations of
facilities exceeding and not exceeding reporting thresholds.
     Reporting: Management and staff hours to organize data,
perform quality assurance/quality control, inform key management
personnel, and report it to EPA through electronic systems.

    Estimates of labor hours were based on economic analyses of
monitoring, reporting, and recordkeeping for other rules; information
from the industry characterization on the number of units or process
inputs and outputs to be monitored; and engineering judgment by
industry and EPA industry experts and engineers. See the Economic
Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions
Under Subpart W Final Rule (EPA-HQ-OAR-2009-0923) for a detailed
discussion about the engineering analysis used to develop these
estimates. In addition, the Greenhouse Gas Emissions from the Petroleum
and Natural Gas Industry: Background TSD (EPA-HQ-OAR-2009-0923)
provides a discussion of the applicable engineering estimating and
measurement technologies and any existing programs and practices.
    EPA monetized the labor hours using wage rates from the Bureau of
Labor Statistics (BLS). The agency also adjusted the wage rates to
account for overhead.

    Equipment Costs. Equipment costs include both the initial purchase
price of monitoring equipment and installation cost. For example, the
cost estimation method for large compressor seal emissions includes
both purchase of a flow measurement instrument and installation of a
measurement port in the vent piping where the end of the vent is
inaccessible. Based on expert judgment, the engineering cost analyses
annualized capital equipment costs with appropriate lifetime and
interest rate assumptions. Cost recovery periods and interest rates
vary by industry, but typically, one-time capital costs are amortized
over a 5-year cost recovery period at a rate of seven percent. Not all
segments require monitoring equipment capital expenditures but those
that do are clearly documented in the Economic Impact Analysis.
    Incremental Combustion Costs. EPA estimated the costs to monitor
and report incremental combustion emissions, which are combustion-
related emissions from entities that did not trigger the subpart C
threshold in the absence of subpart W. As discussed earlier in this
section, reporting entities that equal or exceed the subpart W
threshold must report combustion emissions following the methods under
subpart C, except for onshore production entities that consume field
gas or process vent gas and LDCs, which must report combustion
emissions following the methods under subpart W.
    For purposes of cost estimation, EPA determined that under the
final rule, entities that need to report incremental combustion-related
emissions, as previously defined, would likely use either the Tier 1
calculation methodology as set forth in subpart C or the calculation
methodology as set forth in subpart W (40 CFR 98.233(z)). EPA
determined that the entities reporting incremental emissions under
subpart C would likely not meet the requirements for Tier 2 or higher
methods. However, as these entities will be reporting combustion
emissions under subpart C (except onshore production and LDCs), if a
facility did meet the requirements for a tier other than Tier 1, the
facility would have to use the required method, as specified in subpart
C.
    Given that the combustion methodology in 40 CFR 98.233(z) is
similar to the Tier 1 calculation methodology, EPA estimated the costs
to monitor and report incremental combustion-related emissions based on
the approach used under 40 CFR part 98, subpart C.\7\ Specifically, EPA
applied the Tier 1 calculation methodology to estimate the costs to
monitor combustion emissions that became subject to reporting as a
result of this final action. The Tier 1 approach bases estimates on a
fuel-specific default CO2 emission factor, a default high
heating value of the fuel, and the annual fuel consumption from company
records.
---------------------------------------------------------------------------

    \7\ 40 CFR part 98 uses the IPCC Tier concept to estimate
combustions emissions (74 FR 56260, October 30, 2009). See EPA-HQ-
OAR-2008-0508-0004, U.S. EPA, Technical Support Document for
Stationary Fuel Combustion Emissions: Proposed Rule for Mandatory
Reporting of Greenhouse Gases, January 30, 2009, for more
information about the IPCC Tier methodology (pgs 10-15).
---------------------------------------------------------------------------

    EPA based its conclusion that entities would likely report
incremental combustion emissions using the Tier 1 method on three
considerations for applicability of the Tier 2 calculation methodology
and higher, as specified in subpart C, to the petroleum and natural gas
industry: (1) Availability of high heating values (HHVs) for the fuels
combusted at the frequency required by the Tier 2 calculation
methodology, (2) the maximum rated heat capacity of the equipment, and
(3) the type of fuel being combusted. First, in order to be allowed to
use a Tier 2 analysis, units must have a rated heat capacity less than
or equal to 250 mmBtu/hr, combust a fuel found in Table C-1 of subpart
C, and sample the HHV of the fuel consumed at the required frequency in
40 CFR 98.34(a). It was determined that this minimum required sampling
frequency is not currently carried out at these smaller units and
therefore these units would not be required to use Tier 2 methodology.
These units will generally follow Tier 1 methodology.
    Second, Tier 3 and Tier 4 calculation methodologies generally apply
to equipment with a maximum rated heat capacity greater than 250 mmBtu/
hr. A 250 mmBtu/hr rating means that the emissions from that individual
unit alone will be greater than 25,000 metric tons CO2e;
these emissions would be subject to reporting under subpart C even in
the absence of subpart W and therefore would not fall in the category
of incremental combustion emissions considered in this analysis.
    Third, the predominant fuels used in the petroleum and natural gas
industry are produced natural gas, pipeline quality natural gas,
distillate fuel, and any products recovered from equipment leaks and
vents. The use of produced natural gas is predominant in onshore
petroleum and natural gas production. Under the final rule for subpart
W, reporters in this segment are allowed to use methods similar to Tier
1 for all combustion emissions sources that use produced natural gas.
    In the remaining segments, equipment using produced natural gas or
products recovered from equipment leaks and vents are normally required
to use Tier 2 methodology or higher. However, as described previously,
if the unit has a rated heat capacity less than or equal to 250 mmBtu/
hr, then the unit probably does not currently receive HHV at the
required frequency for a Tier 2 analysis and could use a Tier 1
analysis instead. If the unit has a maximum rated heat capacity greater
than 250 mmBtu/hr, then as just noted, emissions from a unit of this
size would already be subject to reporting under subpart C and would
not be included in the incremental combustion emissions category
considered in this analysis. In sum, the use of Tier 1 methodology for
incremental combustion is a reasonable assumption for costing the
subpart W rule.
    Reporting Determination Costs. Facilities will have to estimate
their emissions to determine whether they exceed the reporting
threshold. The costs for making a reporting determination includes
primarily the use of screening tools, which EPA plans to develop. The
costs also account for cases in which preliminary monitoring is also
required to make a reporting determination.
2. Summary of Comments and Responses
    EPA received many comments on the method used to estimate the
rule's compliance costs. Nearly all of these comments focused on both
the methodology and the resulting cost estimates. Therefore, a summary
of these comments and EPA's response is presented in the next section
of this preamble, Section III.B.2, What are the costs of the rule? For
the detailed responses to all comments received, see Mandatory
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments,
Subpart W: Petroleum and Natural Gas Systems (EPA-HQ-OAR-2009-0923).

B. What are the costs of the rule?

1. Summary of Costs
    Table 6 of this preamble presents for each segment the total costs
and costs per ton in the first year and subsequent years as well as the
annualized costs. EPA estimates that the total private sector cost in
the first year is about $62 million and about $19 million for
subsequent years; the annualized cost over a 20-year time period is
about $21 million (3 percent discount rate) and $22 million (7 percent
discount rate) (2006$). Of these costs, EPA estimates

roughly $40 million to report process emissions in the first year and
about $15 million in subsequent years. In addition, EPA estimates
approximately $3 million to report incremental combustion related
emissions in both the first year and in the subsequent years.
    The reporting threshold determines the number of entities required
to report GHG emissions and hence the costs of the rule. The number of
entities excluded increases with higher thresholds. Table 7a and Table
7b of this preamble provide the cost-effectiveness analysis for various
thresholds examined. Two metrics are used to evaluate the cost-
effectiveness of the emissions threshold. The first is the average cost
per metric ton of emissions reported ($/metric ton CO2e).
The second metric for evaluating the threshold option is the
incremental cost per metric ton of emissions reported. The incremental
cost is calculated as the additional (incremental) cost per metric ton
using 25,000 metric tons CO2 equivalent as the baseline. For
more information about the first year capital costs (unamortized),
project lifetime and the amortized (annualized) costs for each
petroleum and gas industry segment please refer to Section 4 of the
Economic Impact Analysis for the final subpart W.

                                         Table 6--National Cost Estimates for Petroleum and Natural Gas Systems
                                                                       [2006$] \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                     First year                          Subsequent year
                                       ----------------------------------------------------------------------------  Annualized  cost   Annualized  cost
                Segment                   National  cost    Cost  ($/metric     National  cost    Cost  ($/metric        (3%) \2\           (7%) \3\
                                            ($million)            ton)            ($million)            ton)            ($million)         ($million)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Processing............................               8.13               0.26               2.10               0.07               2.43               2.57
Transmission..........................              16.87               0.40               6.49               0.15               7.02               7.26
Underground Storage...................               2.73               0.35               1.02               0.13               1.10               1.14
LNG Storage...........................               0.70               0.41               0.26               0.15               0.28               0.29
LNG import/export.....................               0.14               0.44               0.03               0.09               0.04               0.04
LDC...................................               3.31               0.15               1.35               0.06               1.47               1.52
Onshore Production....................              26.58               0.12               7.54               0.03               8.61               9.05
Offshore Production...................               3.33               0.65               0.24               0.05               0.42               0.49
                                       -----------------------------------------------------------------------------------------------------------------
    Total (8 Segments)................              61.78               0.18              19.01               0.06              21.36              22.34
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Includes determination costs for non-reporters. These estimates are conservative and should be viewed as an upper-bound because the determination
  costs were applied at the facility-level rather than the company-level. For example, for offshore production, determination costs were applied to each
  of the approximately 3,000 platforms in the Gulf of Mexico rather than the 86 operators in that region. See the memo, ``Estimates of Determination
  Costs,'' in the docket for complete details and additional determination cost estimates (EPA-HQ-OAR-2009-0923).
\2\ The cost to report annualized over 20 years at 3 percent (see additional details in section 5 of the EIA for the final rule).
\3\ The cost to report annualized over 20 years at 7 percent (see additional details in section 5 of the EIA for the final rule).

                                                     Table 7A--Threshold Cost-Effectiveness Analysis
                                                                   [First Year, 2006$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Percentage  of
                                                        Facilities                         Downstream          total          Average       Incremental
            Threshold (metric tons CO2e)                required to    Total costs \1\      emissions       downstream       reporting     cost  ($/Mt)
                                                          report      (million  2006$)      reported         emissions     cost  ($/Mt)        \1,2\
                                                                                (MtCO2e/year)      reported           \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...............................................          12,622           $148.67               391             99%           $0.38           $1.62
10,000..............................................           4,400             79.01               362             91%            0.22            0.69
25,000..............................................           2,786             61.78               337             85%            0.18            0.00
100,000.............................................           1,062             44.32               273             69%            0.16          (0.27)
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Includes determination costs for non-reporters. The upper-bound first-year determination cost estimates for each threshold are as follows: 1,000
  metric tons CO2e = $12.3 million; 10,000 metric tons CO2e = $17.4 million; 25,000 metric tons CO2e = $18.4 million; and 100,000 metric tons CO2e =
  $19.3 million. As noted in previous table, these estimates are conservative. See the memo, ``Estimates of Determination Costs,'' in the docket for
  complete details and additional determination cost estimates (EPA-HQ-OAR-2009-0923).
\2\ Cost per metric ton relative to the selected option (25,000 MT threshold).

                                                     Table 7B--Threshold Cost-Effectiveness Analysis
                                                                [Subsequent Year, 2006$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Percentage  of
                                                        Facilities                         Downstream          total          Average       Incremental
           Threshold  (metric  tons  CO2e)             required  to   Total  costs \1\      emissions       downstream       reporting       cost  ($/
                                                          report       (million $2006)      reported         emissions     cost  ($/Mt)      Mt)\1, 2\
                                                                                (MtCO2e/year)      reported           \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...............................................          12,622            $73.44               391             99%           $0.19           $1.02
10,000..............................................           4,400             30.51               362             91%            0.08            0.46
25,000..............................................           2,786             19.01               337             85%            0.06            0.00

100,000.............................................           1,062              9.77               273             69%            0.04          (0.14)
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Includes determination costs for non-reporters. The upper-bound determination costs in subsequent years for each threshold are as follows: 1,000
  metric tons CO2e = $1.8 million; 10,000 metric tons CO2e = $1.0 million; 25,000 metric tons CO2e = $0.6 million; and 100,000 metric tons CO2e = $0.2
  million. As noted in previous table, these estimates are conservative. See the memo, ``Estimates of Determination Costs,'' in the docket for complete
  details and additional determination cost estimates (EPA-HQ-OAR-2009-0923).
\2\ Cost per metric ton relative to the selected option (25,000 MT threshold).

2. Summary of Comments and Responses
    Overview. EPA received extensive comments on the methodology and
cost data presented in the Economic Impact Analysis for the proposed
subpart W (EPA-HQ-OAR-2009-0923-0020). The comments can be sorted into
two major categories: (1) Comments on the costs for facilities to make
a reporting determination, and (2) comments on cost estimates of labor
and equipment for certain industry segments to monitor and report
emissions.
    Reporting Determination. Commenters stated that EPA's analysis
underestimated the true compliance burden by omitting the costs for
facilities to make a reporting determination--i.e., estimate annual
emissions to determine whether they meet the reporting threshold. These
commenters recommended that EPA account for reporting determination
costs incurred by both facilities that report as well as non-reporters,
i.e., those that monitor emissions but do not meet the reporting
threshold. As discussed in Section II.F.6 of this preamble, the
commenters also recommended that EPA develop screening tools to reduce
the burden for facilities to make a reporting determination.
    EPA agrees with commenters that the EIA would better reflect the
rule's total economic burden by including all reporting determination
costs. While EPA's compliance cost estimates accounted for the
reporting determination burden in the proposal, it did not include the
determination burden for non-reporters. Therefore, EPA has estimated
the burden for reporting determinations made by non-reporters and
included it in the EIA for the final rule. EPA based this estimate on
the assumption that non-reporters will use a screening tool, which EPA
intends to provide to facilitate reporting determinations. The
estimated total cost for all non-reporters to make a reporting
determination is about $18.4 million, which accounts for use of the
screening tool and, if required, the cost to conduct further screening;
Section 4 of the EIA provides a complete discussion of the basis for
this estimate.\8\ EPA expects use of the screening tool to minimize
burden by allowing facilities to enter basic activity data, such as
well count and drilling activity, into the tool to roughly assess
whether they meet the threshold. Facilities for which the tool
estimates emissions well below the threshold will generally not need to
conduct further screening. Facilities for which the tool estimates
emissions near the threshold will generally conduct additional
screening, and this is reflected in the cost estimates.
---------------------------------------------------------------------------

    \8\ These estimates are conservative and should be viewed as an
upper-bound because the determination costs were applied at the
facility-level rather than the company-level. For example, for
offshore production, determination costs were applied to each of the
approximately 3,000 platforms in the Gulf of Mexico rather than the
86 operators in that region. See the memo, ``Estimates of
Determination Costs,'' in the docket for complete details and
additional determination cost estimates (EPA-HQ-OAR-2009-0923).
---------------------------------------------------------------------------

    Labor and Equipment Costs. Many commenters disagreed with EPA's
cost estimates in particular segments and presented alternative
estimates that in some cases differed from the agency's estimates by
orders of magnitude. Many of the comments suggested that EPA's
estimates of labor costs (e.g., number of labor hours required to
collect field data, to use equipment and engineering analysis systems
to measure emissions, and to manage the emissions data) and equipment
costs (e.g., purchase of flow meters) were too low.
    In development of this rule and in response to comments, EPA
collected and evaluated cost data from multiple sources, closely
reviewed the input received through public comments, and weighed the
analysis prepared against this input. EPA also carefully weighed the
burden of incrementally more comprehensive methods of measuring and
calculating emissions against the increase in coverage and accuracy,
and in some cases revised or clarified the measurement and calculation
requirements. EPA has thus adjusted both the rule requirements and its
cost estimates in response to comments, and concludes that its
methodology and final cost estimates appropriately account for the
compliance burden under this final rule. EPA determined that the
commenters' alternative estimates are much higher than the agency's
because of assumptions and interpretations that were either
inconsistent with EPA's original intent (and which EPA has now
clarified) or requirements that have been revised; in some cases, the
alternative estimates were also based on higher-cost, optional
monitoring methods.
    EPA summarizes below the key assumptions, revisions,
misinterpretations, and use of higher-cost, optional methods and the
resulting costs estimates that differed most from EPA's estimates.
These comments were concentrated in three industry segments: (1)
Onshore production, (2) natural gas processing, and (3) natural gas
distribution segments.
3. Onshore Production
    Comment: Commenters stated that EPA's estimated compliance costs
for the onshore petroleum and natural gas production segment were too
low. Overall, the commenters concluded that EPA should reassess the
analysis of entities covered by the rule, the assumptions underlying
the cost estimates, and reduce the monitoring and reporting burden.
    One commenter provided detailed, alternative cost estimates and
concluded that costs could be as high as $1.8 billion for the onshore
production segment in the first year, which is notably higher than
EPA's proposal estimate of $30.4 million for this segment. The
commenter made various assumptions that differed from EPA's analysis
and accounted for the difference in the cost estimates. One

source of the difference stemmed from the estimate of the number of
sources in the onshore production segment subject to monitoring.
Specifically, the commenter assumed that because the proposed rule
would cover about 80 percent of emissions from the petroleum and gas
industry, approximately 80 percent of the sites and equipment at each
onshore production facility would be subject to the rule. The commenter
therefore concluded that the rule would cover 80 percent of the 823,000
wells in the nation, or about 667,000 wells, which exceeds EPA's
estimated coverage of about 467,000 wells, plus sources at non-well
sites.\9\ In particular, the commenter said that counting components to
estimate emissions from equipment leaks would be onerous.
---------------------------------------------------------------------------

    \9\ Commenter estimated 823,000 wells based on a ``US Energy
Information Administration's 2008 report,'' but did not provide any
other citation information.
---------------------------------------------------------------------------

    Additional differences in the commenter's and EPA's estimates
resulted from differences in the assumptions about labor wages and time
spent sampling. For example, the commenter presented a breakdown of the
labor and equipment costs, such as labor wages and time spent on
sampling activities. Sampling activities accounted for a notable
fraction of the commenter's estimates. For example, the commenter
estimated costs for sampling activity to determine the composition of
produced natural gas and low pressure separator oil and to analyze all
tanks for hydrocarbon liquids and produced water.
    In addition, data management software constituted a substantial
fraction of the commenter's total cost estimate. The commenter stated
that individual reporters would spend between $100,000 and $850,000 for
data management software, which totals to approximately $123 million to
$1 billion for the entire segment.
    EPA has carefully reviewed these comments and disagrees that the
true costs will be substantially higher than those estimated by the
agency.
    First, EPA disagrees with the commenter's estimate of the number of
sources subject to reporting because it incorrectly assumed that the
proposed rule covered 80 percent of all wells in the United States. The
commenter's assumption that each reporter would need to monitor 80
percent of its wells in order to report about 80 percent of its
emissions implies that the type and quantity of emissions from each
well are identical. This assumption, which resulted in much more labor
and complex monitoring than required under the proposal, is incorrect.
The quantity and type of emissions from wells are variable; in fact, it
is not necessary to monitor 80 percent of wells to account for 80
percent of emissions and neither the proposed nor final rules would
require such a large percentage of wells to be covered. Because the
final rule tends to target those wells that have the higher emissions,
based on its threshold analysis, EPA estimates that approximately 60
percent of the wells are subject to the monitoring requirements, and
that these wells will account for about 85 percent of total GHG
emissions from this segment.
    EPA conducted the threshold analysis using actual data available
through the commercial database from HPDI LLC, which collects these
data primarily from individual petroleum and natural gas producing
States that require petroleum and natural gas producing companies to
report field data. The HPDI database includes operator well count. In
most cases, HPDI provides data for each well on the production of
petroleum and natural gas by operator and basin; some data are listed
by property, which is a collection of wells. EPA developed a reasonable
estimate of the emissions per well by apportioning the national
emissions from each emissions source type to each of the wells based on
the contribution of petroleum and natural gas production from each well
to the national total. This analysis suggests that approximately 60
percent of the wells are owned or operated by entities that would
trigger the reporting threshold, not 80 percent.
    The commenter's analysis of the onshore production burden also
incorrectly assumed that the rule required all onshore production
reporters to spend up to $1 billion on data management software. EPA
disagrees with this assumption. EPA notes that the rule does not
require reporters to purchase data collection software. It is at the
reporters' discretion to do so.
    Although the commenter did not provide any information about the
software represented in its analysis (except for cost), a system in the
price range assumed by the commenter is usually customized to
accommodate data needs that extend far beyond the scope of this rule.
For example, such systems are typically tailored to an individual
facility and used to simultaneously manage, among other things,
criteria pollutants under the CAA, water discharge and permit data
under the Clean Water Act, employee accident and injury reporting under
Occupational Safety and Health Administration requirements, and onsite
hazardous and non-hazardous solid waste information for the Resource
Conservation and Recovery Act. In contrast, even the largest of
reporters under this final action will be able to use standard
spreadsheets or databases to collect the emissions data and perform
calculations at a facility level. Spreadsheet software can store and
manipulate tens of thousands of data points, and database software can
store hundreds of thousands of data points. In short, spreadsheet and
database software systems are capable of managing far more data than
will be necessary for even the largest onshore production reporter
under subpart W. Accordingly, EPA accounted for data management costs
by factoring in estimates of labor to set up spreadsheets and other
archiving and recordkeeping activities, as well as equipment costs like
file cabinets and external hard drives; see the EIA for a complete
discussion.
    Another assumption contributing to the commenters' high cost
estimates concerned the extent of sampling required. For example,
commenters assumed that reporters would need to sample produced natural
gas. EPA disagrees in part because it expects reporters to already have
this information and would therefore not need to sample. In particular,
producers conduct composition analysis of produced natural gas in order
to pay royalties and taxes; they could use these data to estimate the
percentage of GHGs instead of analyzing additional samples.
    The commenters also assumed that sampling would be required for
tanks and dehydrators, which resulted in cost estimates significantly
higher than EPA's. Although not explicitly stated in the proposed
subpart W, EPA did not intend for reporters to sample either the low
pressure separator oil associated with tanks or natural gas going to
dehydrators. Therefore, EPA has clarified the final rule to allow
reporters that use the engineering modeling software to rely on the
software's default values.
    In addition, commenters also assumed that produced water and
hydrocarbon liquids produced from all reporting wells in the country
would have to be sampled to determine and report CO2
content; this assumption resulted in a large sampling cost. However,
EPA never intended for reporters to sample produced water and
hydrocarbon liquids from all wells but instead targeted EOR operations.
Therefore, EPA clarified in this final action that the sampling
requirement for hydrocarbon liquids applies only to EOR operations; EPA
also clarified in the final rule that

reporting from produced water emissions sources is not required.
    Finally, in response to comments about the costs to count all
components to determine equipment leaks, EPA has revised the rule to
require reporters to count only major equipment (see Section II.E of
this preamble). EPA expects this revision to reduce the reporters'
burden because in many cases they already have an inventory of the
major equipment at each well site.
    For the detailed responses to all of the comments received about
the costs for onshore production, see Mandatory Greenhouse Gas
Reporting Rule: EPA's Response to Public Comments, Subpart W: Petroleum
and Natural Gas Systems (EPA-HQ-OAR-2009-0923).
4. Natural Gas Processing
    Comment: Commenters stated that EPA's estimated compliance costs
for the natural gas processing segment were too low. They recommended
that EPA reassess the costs for the processing segment and simplify the
reporting requirements. In particular, one commenter estimated
compliance costs at $4.5 billion for the processing segment. Of the
$4.5 billion, the commenter attributed $3.9 billion to monitoring
activities at gathering lines and boosting stations. The commenter
attributed the remainder of its estimate to processing facilities.
    Response: Based on its thorough review of the comments, EPA
determined that the commenter's estimates for processing facilities
were higher in part because it made assumptions that were inconsistent
with EPA's intent. Specifically, it assumed higher-cost, optional
monitoring methods for processing facilities in its analysis. However,
EPA agrees with the commenter that the agency's analysis partly
underestimated the costs at processing facilities to place meters on
acid gas removal units. Likewise, EPA agrees that the agency's analysis
did not accurately account for the compliance costs for gathering lines
and boosting stations in the processing segment.
    In the case of processing facilities, the commenter assumed that
the rule would require reporters to install permanent flow meters, at
an assumed cost of $100,000 per meter, to measure emissions from
compressor venting. However, the rule does not require this and allows
installation of a port for using a temporary insertion flow meter for
an annual one-time estimate of vented emissions. Temporary flow meters
are a significantly cheaper option than permanent meters. Based on
current market data, EPA estimated approximately $1,000 for each
installation of a temporary meter port for reciprocating compressors;
about $5,000 for centrifugal compressors; and about $800 in capital
costs for a reporter's hotwire anemometer.\10\ Reporters will only need
to purchase one hotwire anemometer per facility; the hotwire anemometer
can be used to measure the flow rate at multiple compressors at the
facility.
---------------------------------------------------------------------------

    \10\ For example, see Global Water Instrumentation Inc., at
http://www.globalw.com/products/407119.html.
---------------------------------------------------------------------------

    In addition, EPA considered and responded to the commenter's
assumption about the burden to install permanent outflow meters at acid
gas removal (AGR) vents. EPA incorrectly assumed that outlet meters
were already installed at most sites. Specifically, EPA determined upon
further analysis that the flow rates at the inlet and outlet streams
for an acid gas removal unit are roughly similar. EPA therefore
adjusted the calculation method in the final rule to allow the use of
flow rate at the inlet or outlet, where available, based on its
assumption that the outlet flow is the same as the inlet flow. In
addition, if equipment to measure the flow rate, such as CEMS or a
meter on the vent stack of the acid gas removal unit, is not available,
the final rule allows reporters to use engineering estimates of flow
rate of natural gas into the AGR. These revised requirements are
reflected in the cost analysis in the final EIA.
    Finally, EPA used data about the number of gathering lines and
boosting stations presented by the commenter as a basis to modify the
rule requirements. EPA agrees that its EIA for the proposed rule did
not accurately reflect the number of gathering lines and boosting
stations that would have been subject to the rule. EPA has dropped the
requirement for reporting on gathering lines and boosting stations from
the final rule, so these costs are not included in the analysis.
Instead, EPA will continue to evaluate options for obtaining emissions
data from gathering lines and boosting stations in a way that maximizes
data quality while balancing industry burden; see Section II.F.1 of
this preamble for further discussion.
5. Natural Gas Distribution
    Comment: Commenters stated that EPA's estimated compliance costs
for the natural gas distribution segment were too low by orders of
magnitude. For example, one commenter estimated approximately $11.3
billion for all reporters in the natural gas distribution segment to
comply with the rule. A large fraction of this estimate was based on
the commenter's assumption that the leak detection requirements applied
to customer meters, i.e., industrial, commercial, and residential
meters. The commenter did not, however, provide adequate information
about the basis for the remainder of its cost estimate. In particular,
the commenter stated that in addition to the costs of using an optical
gas imaging instrument, each LDC would spend on average about $41
million annually to comply with the rule, but did not specify any
compliance activities that accounted for the $41 million.
    Response: EPA has carefully reviewed these comments and disagrees
that the agency's cost estimates should be orders of magnitude higher.
EPA has determined that commenters' interpretations of the proposed
rule were inconsistent with the Agency's intent and this likely
accounted for the discrepancies between the estimates.
    EPA disagrees with the commenter's cost estimate because it is
based on the assumption that customer meters are subject to leak
detection requirements. The commenter assumed that the proposed rule
required leak detection and emissions estimates for all customer
meters, i.e., industrial, commercial, and residential meters; the
commenter estimated reporters would spend approximately $5.4 billion to
monitor these meters. EPA never intended to require reporting for
customer meters, which would involve a major cost and have minimal
effect on the quality of emissions estimates. EPA has therefore
clarified the final rule to note that sources subject to reporting in
the natural gas distribution segment do not include customer meters for
natural gas.
    In addition, EPA has responded to the commenter's recommendation to
reduce the compliance costs by simplifying the requirements for optical
gas imaging instrument equipment, e.g., allowing alternatives to
infrared cameras in some situations. As discussed previously in Section
II.E of this preamble, this final action provides more flexibility and
further reduces the compliance cost by allowing facilities to use
alternative leak detection equipment.
    The commenter did not identify the monitoring activities and
assumptions underlying its estimate of $5.9 billion to comply with leak
detection requirements. The commenter noted that it obtained the
estimate from an informal survey of its members but did not provide
sufficient information or documentation substantiating what was
included in this estimate. Because EPA has accounted for the two
primary issues raised by the commenter (monitoring of customer meters
and allowable leak detection equipment),

EPA did not change its cost estimate to reflect the much higher costs
estimated by the commenter.

C. What are the economic impacts of the rule?

1. Summary of Economic Impacts
    EPA prepared an economic impact analysis to evaluate the impacts of
the rule on affected small and large reporting entities.
    To estimate the economic impacts of the rule, EPA first conducted a
screening assessment, comparing the estimated total annualized
compliance costs for the petroleum and gas industry, where industry is
defined in terms of North American Industry Classification System
(NAICS) code, with industry average revenues.\11\ The national costs of
the rule are notable because there are a large number of affected
entities, but per-entity costs are low. Average cost-to-sales ratios
for establishments in the affected NAICS codes for all segments is less
than 1 percent, except in the 1-20 employee range for the onshore
petroleum and natural gas segment.
---------------------------------------------------------------------------

    \11\ Note: Before totaling the industry compliance costs, EPA
estimated costs for each of the industry segments. EPA then summed
the costs for each segment at the NAICS level for this screening
assessment.
---------------------------------------------------------------------------

    These low average cost-to-sales ratios indicate that the final rule
is unlikely to result in significant changes in firms' production
decisions or other behavioral changes that would result in significant
changes in prices or quantities in affected markets. Given that prices
and quantities are unlikely to change significantly, and consistent
with the agency's guidelines for economic analyses, EPA used the
engineering cost estimates to measure the social cost of the rule,
rather than modeling market responses and using the resulting measures
of social cost.\12\ Table 8 of this preamble summarizes cost-to-sales
ratios for affected industries.
---------------------------------------------------------------------------

    \12\ Guidelines for Preparing Economic Analyses (EPA, 2002, p.
124-125).

                          Table 8--Estimated Cost-to-sales Ratios for Affected Entities
                                                    (Year 1)
----------------------------------------------------------------------------------------------------------------
                                                                                Average entity
                                                                                Average cost      cost-to-sales
            NAICS                NAICS Description     MRR Segments included     per entity         ratio \a\
                                                                               ($1,000/entity)      (percent)
----------------------------------------------------------------------------------------------------------------
211.........................  Crude Petroleum and     Onshore Production,                $17.1              0.08
                               Natural Gas             Offshore Production,
                               Extraction.             Processing.
486210......................  Pipeline                Transmission,                       15.7              0.08
                               Transportation of       Underground Storage,
                               Natural Gas.            LNG Storage, and LNG
                                                       Import Terminals.
221210......................  Natural Gas             Distribution..........              13.9              0.06
                               Distribution.
----------------------------------------------------------------------------------------------------------------
\a\ This ratio reflects first year costs. Subsequent year costs will be lower because they do not include
  initial start-up activities.

2. Summary of Comments and Responses
    While EPA received a substantial number of comments on the
estimated costs for reporters to comply with the rule, there were
minimal additional comments on the economic impacts, such as changes in
production or effects on small entities in particular. As discussed in
the previous section of this preamble, commenters said that EPA
underestimated the compliance costs and recommended that EPA carefully
review the economic impact analysis. See the previous section of this
preamble for a summary; the response to comments document, Mandatory
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments,
Subpart W: Petroleum and Natural Gas Systems, provides detailed
comments.
    As discussed in Section III.B.2 of this preamble, EPA collected and
evaluated cost data from multiple sources, thoroughly reviewed the
input received through public comments, and weighed the analysis
prepared for the proposal against this input. EPA has determined that
this analysis provides a reasonable characterization of costs and
economic impacts and that the documentation provides adequate
explanation of how the costs and impacts were estimated.

D. What are the impacts of the rule on small businesses?

1. Summary of Impacts on Small Businesses
    As required by the RFA and Small Business Regulatory Enforcement
and Fairness ACT (SBREFA), EPA assessed the potential impacts of the
rule on small entities (small businesses, governments, and non-profit
organizations). (See Section IV.C of this preamble for definitions of
small entities.)
    EPA has determined the selected threshold maximizes the rule
coverage with 85 percent of U.S. GHG emissions from the industry
segments reported by approximately 2,786 reporters, while keeping
reporting burden to a minimum. Furthermore, many industry stakeholders
that EPA met with expressed support for a 25,000 metric ton
CO2e threshold because it sufficiently captures the majority
of GHG emissions in the United States, while excluding many of the
smaller facilities and sources. In response to the comments EPA
received about the monitoring and reporting requirements in specific
source categories, EPA incorporated changes that reduce burden on
reporters while maintaining a high level of emissions coverage. For
information on these issues, refer to the discussion of each segment in
this preamble.
    EPA conducted a screening assessment comparing compliance costs to
onshore petroleum and natural gas industry specific receipts data for
establishments owned by small businesses. This ratio constitutes a
``sales'' test that computes the annualized compliance costs of this
rule as a percentage of sales and determines whether the ratio exceeds
one percent.\13\ The cost-to-sales ratios were constructed at the
establishment level (average reporting program costs per establishment/
average establishment receipts) for several business size ranges. This
allowed EPA to account for receipt differences between establishments
owned by large and small businesses and differences in small business
definitions across affected industries. The results of the screening
assessment are shown in Table 9 of this preamble.
---------------------------------------------------------------------------

    \13\ EPA's RFA guidance for rule writers suggests the ``sales''
test continues to be the preferred quantitative metric for economic
impact screening analysis.

                    Table 9--Estimated Cost-to-Sales Ratios, Sales Receipts ($Million), and Number of Establishments for First Year Costs by Industry and Enterprise Size\a\
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              SBA Size standard                                                           Owned by enterprises with:
                                                                  in num of       Average cost               -----------------------------------------------------------------------------------
            Industry              NAICS   NAICS Description       employees        per entity        All                                                                               1,000 to
                                                              (effective March      ($1,000/     enterprises    1 to 20    20 to 99   100 to 499     <500     500 to 749  750 to 999     1,499
                                                                  11, 2008)          entity)                   Employees   Employees   Employees   Employees   Employees   Employees   Employees
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Onshore petroleum and natural        211  Crude Petroleum                  500            $17.1        0.08%       1.32%       0.11%       0.05%       0.47%       0.47%       0.03%       0.02%
 gas production; offshore                  and Natural Gas                                       \d\$160,879      $7,573      $6,790      $9,609     $23,972      $4,609      $3,991      $2,805
 petroleum and natural gas                 Extraction.                                              \e\7,629       5,836         456         292       6,584          60          64          31
 production; LNG storage; LNG
 import and export.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Onshore natural gas processing;   486210  Pipeline                       \(b)\            $15.7        0.08%       0.12%       0.40%       0.24%       0.10%       \(c)\       \(c)\       \(c)\
 onshore natural gas                       Transportation                                         \d\$35,897      $1,035     \c\$106     \c\$394      $2,566       \(c)\       \(c)\       \(c)\
 transmission; underground                 of Natural Gas.                                          \e\1,936          81          27          61          36         169           2          20
 natural gas storage.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Natural gas distribution.......   221210  Natural Gas                      500            $13.9        0.06%       0.27%       0.03%       0.06%       0.11%       0.07%       0.02%       0.03%
                                           Distribution.                                          \d\$67,275      $2,524      $4,642      $2,878     $13,127        $865      $2,116      $3,757
                                                                                \e\2,897         483          86         131         700          68          33          73
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise
  and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise--the enterprise employment and annual payroll are summed from the
  associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments.
Since the SBA's business size definitions (http://www.sba.gov/size) apply to an establishment's ultimate parent company, EPA assumes in this analysis that the enterprise definition above is
  consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses.
\b\ The SBA size standard for NAICS 486210 is $7 million in average annual receipts.
\c\ The U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receipts for these categories underestimate true value.
\d\ This row presents total annual sales receipts ($Million)for establishments in each enterprise category. Source: U.S. Census Bureau.
\e\ This row presents total number of establishments in each enterprise category. Source: U.S. Census Bureau.

    As shown, the cost-to-sales ratios are less than one percent for
establishments owned by small businesses that EPA considers most likely
to be covered by the reporting program. The only exception is the ratio
for enterprises with 1-20 employees for crude petroleum and natural gas
extraction, which is greater than 1 percent but less than 2 percent. It
is important to note that this analysis does not screen out entities
that would be below the reporting threshold. Based on further analysis
of production data in HPDI, EPA estimates that in most cases, the
smaller enterprises have very small operations (such as a single family
owning a few production wells) that are unlikely to cross the 25,000
metric tons CO2e reporting threshold.
    In other cases, a small enterprise (less than 20 employees) may own
large operations but conduct nearly all of its operations through
service providers, so that it has few employees of its own. Such
enterprises, however, tend to have higher annual revenues than those
with small operations and therefore have lower cost-to-sales ratios.
The review of production data by operator in HPDI shows a ratio of less
than one percent for the operators expected to meet the reporting
threshold.
    EPA took a conservative approach with the model entity analysis.
Although the appropriate SBA size definition should be applied at the
parent company (enterprise) level, data limitations allowed us only to
compute and compare ratios for a model establishment within several
enterprise size ranges. That is, the analysis assumes that each
establishment is a unique enterprise. To the extent that a single
parent may own multiple establishments, the small entity impacts could
be lower.
    Although this rule will not have a significant economic impact on a
substantial number of small entities, the Agency nonetheless tried to
reduce the impact of this rule on small entities, including seeking
input from a wide range of private- and public-sector stakeholders.
When developing the rule, the Agency took special steps to ensure that
the burdens imposed on small entities were minimal. The Agency
conducted several meetings with industry trade associations to discuss
regulatory options and the corresponding burden on industry, such as
recordkeeping and reporting. The Agency investigated alternative
thresholds and analyzed the marginal costs associated with requiring
smaller entities with lower emissions to report. The Agency also
established a reasonable balance of direct measurement, engineering
estimation, and emission factors based monitoring methods to quantify
emissions, which provides flexibility to entities and helps minimize
reporting costs.
2. Summary of Comments and Responses
    Comment: Some commenters noted concerns about the rule's impact on
small businesses, in particular that small businesses would have to
apply the monitoring methods specified in the rule to determine whether
they have to report under the rule. One commenter recommended that EPA
redo its analysis of the rule's impacts on small businesses using
``more accurate economic impact data,'' but did not include or identify
alternative data sources for such an analysis. See the response to
comments document, Mandatory Greenhouse Gas Reporting Rule: EPA's
Response to Public Comments, Subpart W: Petroleum and Natural Gas
Systems, for the detailed comments.
    Response: EPA has assessed the economic impact of the final rule on
small entities and concluded that this action will not have a
significant economic impact on a substantial number of small entities.
While the commenter did not provide details in its recommendation that
EPA redo the small business analysis using ``more accurate economic
impact data,'' EPA acknowledges the importance of using the best
available economic data. Accordingly, EPA analyzed the economic impact
on small entities using the revised cost estimates discussed in this
section of the preamble and in the EIA. These cost estimates were the
same order of magnitude as those estimated under the proposal; the
estimates also reflected improvements made in response to comments as
well as changes to the monitoring requirements in the final rule.
    In addition, EPA's assessment of the economic impacts on small
entities continued to rely on data from the Statistics of U.S.
Businesses, a well-known database that provides national information on
the distribution of economic variables by the size of entity. As noted
in the EIA, these data were developed in cooperation with, and
partially funded by, the Office of Advocacy of the Small Business
Administration. Complete documentation of this analysis can be found in
Section 5.2 of the EIA for the final rule.
    Finally, in response to concerns about the cost to make a reporting
determination, EPA intends to provide screening tools. As discussed
above, these tools will aid small businesses and other potential
reporters in determining whether or not they have to report.
    The response to comments document, Mandatory Greenhouse Gas
Reporting Rule: EPA's Response to Public Comments, Subpart W: Petroleum
and Natural Gas Systems, presents the detailed comments and responses
related to the rule's impact on small businesses.

E. What are the benefits of the rule for society?

    EPA examined the potential benefits of the final subpart W. The
benefits of a reporting system are based on their relevance to policy
making, transparency, and market efficiency. Benefits are very
difficult to quantify and monetize. Instead of a quantitative analysis
of the benefits, EPA conducted a systematic literature review of
existing studies including government, consulting, and scholarly
reports.
    A mandatory reporting system for petroleum and natural gas systems
will benefit policymakers and the public by increased availability of
facility emissions data. Public data on emissions allows for
accountability of emitters to the public. Citizens, community groups,
and labor unions have made use of data from Pollutant Release and
Transfer Registers to negotiate directly with emitters to lower
emissions, circumventing greater government regulation. Publicly
available emissions data also will allow individuals to alter their
consumption habits based on the GHG emissions of producers. Facility-
specific emissions data will also aid local, State, and national
policymakers as they evaluate and consider future climate change policy
decisions.
    The benefits of mandatory reporting of petroleum and natural gas
systems GHG emissions to government also include enhancing existing
programs, such as the Natural Gas STAR Program, and that provide
significant benefits. Through the Natural Gas STAR Program, EPA has
identified over 120 proven, cost effective technologies and practices
to reduce emissions of methane--the primary constituent of natural
gas--from operations in all of the major industry sectors--production,
gathering and processing, transmission, and distribution. The final
subpart W will increase knowledge of the location and magnitude of
significant methane emissions sources in the petroleum and natural gas
industry, which can result in improvements in these technologies and
the identification of new emissions reducing technologies.

    Benefits to industry of GHG emissions monitoring include the value
of having verifiable data to present to the public to demonstrate
appropriate environmental stewardship, and a better understanding of
their emission levels and sources to identify opportunities to reduce
emissions. Such monitoring allows for inclusion of standardized GHG
data into environmental management systems, providing the necessary
information to achieve and disseminate their environmental
achievements.
    Standardization will also be a benefit to industry. Once facilities
invest in the institutional knowledge and systems to report emissions,
the cost of monitoring should fall and the accuracy of the accounting
should improve. A standardized reporting program will also allow for
facilities to benchmark themselves against similar facilities to
understand better their relative standing within their industry.
    The EIA for this final rule as well as the RIA for 40 CFR part 98
summarize the anticipated benefits, which include providing the
government with sound data on which to base future policies and
providing industry and the public independently verified information
documenting firms' environmental performance. While EPA has not
quantified the benefits of the mandatory reporting rule, EPA believes
that they are substantial and justify the estimated costs.

IV. Statutory and Executive Order Review

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993),
this action is a ``significant regulatory action'' because it raises
novel legal or policy issues arising out of legal mandates, the
President's priorities, or the principles set forth in the EO.
Accordingly, EPA submitted this action to the Office of Management and
Budget (OMB) for review under EO 12866.

B. Paperwork Reduction Act

    The information collection requirements in this final rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The
Information Collection Request (ICR) document prepared by EPA has been
assigned EPA ICR number 2376.02.
    EPA plans to collect complete and accurate facility-level GHG
emissions from the petroleum and natural gas industry. Accurate and
timely information on GHG emissions is essential for informing future
climate change policy decisions. Through data collected under this
rule, EPA will gain a better understanding of the relative emissions of
different segments of the petroleum and natural gas industry and the
distribution of emissions from individual facilities within those
industries. The facility-specific data will also improve our
understanding of the factors that influence GHG emission rates and
actions that facilities are already taking to reduce emissions.
Additionally, EPA will be able to track the trend of emissions from
facilities within the petroleum and natural gas industry over time,
particularly in response to policies and potential regulations. The
data collected by this rule will improve EPA's ability to formulate
climate change policy options and to assess which segments of the
petroleum and gas industry would be affected, and how these segments
would be affected by the options.
    This information collection is mandatory and will be carried out
under CAA section 114. Information identified and marked as CBI will
not be disclosed except in accordance with procedures set forth in 40
CFR part 2. However, emissions data collected under CAA section 114
cannot generally be claimed as CBI and will be made public.
    The projected cost and hour burden for non-Federal respondents is
$27.7 million and 396,474 hours per year. The estimated average burden
per response is 90.71 hours; the frequency of response is annual for
all respondents that must comply with the final rule's reporting
requirements; and the estimated average number of likely respondents
per year is 2,786. The cost burden to respondents resulting from the
collection of information includes the total capital cost annualized
over the equipment's expected useful life (averaging $0.74 million), a
total operation and maintenance component (averaging $1.7 million per
year), and a labor cost component (averaging $25.3 million per
year).\14\
---------------------------------------------------------------------------

    \14\ Burden is defined at 5 CFR 1320.3(b). These cost numbers
differ from those shown elsewhere in the Economic Analysis because
the ICR costs represent the average cost over the first three years
of the proposed rule, but costs are reported elsewhere in the
Economic Analysis for the first year of the proposed rule and for
subsequent years of the proposed rule. In addition, the ICR focuses
on respondent burden, while the Economic Analysis includes EPA
Agency costs.
---------------------------------------------------------------------------

    Burden is defined at 5 CFR 1320.3(b). These cost numbers differ
from those shown elsewhere in the EIA for these subparts because the
information collection request (ICR) costs represent the average cost
over the first three years of the rule, but costs are reported
elsewhere in the EIA for the subparts for the first year of the rule
and for subsequent years of the rule. In addition, the ICR focuses on
respondent burden, while the EIA includes both national compliance
costs and the burden for EPA to implement the rule.
    An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is
approved by OMB, the Agency will publish a technical amendment to 40
CFR part 9 in the Federal Register to display the OMB control number
for the approved information collection requirements contained in this
final rule.

C. Regulatory Flexibility Act (RFA)

    The RFA generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment
rulemaking requirements under the Administrative Procedure Act or any
other statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small entities.
Small entities include small businesses, small organizations, and small
governmental jurisdictions.
    For purposes of assessing the impacts of this final rule on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's regulations at 13 CFR 121.201;
(2) a small governmental jurisdiction that is a government of a city,
county, town, school district or special district with a population of
less than 50,000; and (3) a small organization that is any not-for-
profit enterprise that is independently owned and operated and is not
dominant in its field.
    After considering the economic impacts of this final action on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities.
    The small entities directly regulated by this final rule include
small businesses in the petroleum and gas industry, small governmental
jurisdictions and small non-profits. EPA has determined that some small
businesses will be affected because their production processes emit
GHGs exceeding the reporting threshold.
    For affected small entities, EPA conducted a screening assessment
comparing compliance costs for affected industry segments to petroleum
and gas-specific data on revenues for small

businesses. This ratio constitutes a ``sales'' test that computes the
annualized compliance costs of this final rule as a percentage of sales
and determines whether the ratio exceeds some level (e.g., 1 percent or
3 percent). The cost-to-sales ratios were constructed at the
establishment level (average compliance cost for the establishment/
average establishment revenues).
    As shown in Table 9 of this preamble, the average ratio of
annualized reporting program costs to receipts of establishments owned
by model small enterprises was less than 1 percent for industries
presumed likely to have small businesses covered by the reporting
program. It is important to note that this analysis does not screen out
entities that would be below the reporting threshold. Although the
costs to receipts for entities in onshore production with 1-20
employees is slightly over 1 percent, most of these facilities would
likely not exceed the 25,000 mtCO2e threshold, a threshold
supported by many stakeholders as one that sufficiently captures the
majority of GHG emissions while excluding small facilities.
    EPA also concluded that the final rulemaking would not affect a
small organization that is any not-for-profit enterprise that is
independently owned and operated and is not dominant in its field.
Specifically, the data listing entities in each segment of the
petroleum and natural gas industry did not include any non-profit
entities.
    In addition, EPA determined that the final rulemaking would not
have a significant impact on small governmental jurisdictions. EPA
determined that one segment of the petroleum and natural gas industry
might include small governments affected by the final rulemaking. A
comparison of the compliance costs to the revenue of potentially
affected small governmental jurisdictions revealed that the costs of
the rule are less than 1 percent of revenues.
    Although this final rule will not have a significant economic
impact on a substantial number of small entities, EPA nonetheless took
several steps to reduce the impact of this final rule on small
entities. For example, EPA determined appropriate thresholds that
reduce the number of small businesses reporting. In addition, EPA
allows different monitoring methods for different emissions sources,
requiring direct measurement only for selected sources. Also, EPA
intends to provide a screening tool that will help small businesses
make a reporting determination (see Section II.F.6 of this preamble).
Finally, EPA is establishing annual instead of more frequent reporting.
    Through comprehensive outreach activities prior to proposal of the
initial rule, EPA held approximately 100 meetings and/or conference
calls with representatives of the primary audience groups, including
numerous trade associations and industries in the petroleum and gas
industry that include small business members. EPA's outreach activities
prior to proposal of the initial rule are documented in the memorandum,
Summary of EPA Outreach Activities for Developing the Greenhouse Gas
Reporting Rule, located in Docket No. EPA-HQ-OAR-2008-0508-053. After
the initial proposal, EPA posted a guide for small businesses on the
EPA GHG reporting rule website, along with a general fact sheet for the
rule, information sheets for every source category, and an FAQ
document. EPA also operated a hotline to answer questions about the
final rule. EPA continued to meet with stakeholders and entered
documentation of all meetings into the docket.
    During rule implementation, EPA would maintain an ``open door''
policy for stakeholders to ask questions about the final rule or
provide suggestions to EPA about the types of compliance assistance
that would be useful to small businesses. EPA intends to develop a
range of compliance assistance tools and materials and conduct
extensive outreach for the final rule.
    EPA has therefore concluded that this final action will not have a
significant economic impact on a substantial number of small entities.

D. Unfunded Mandates Reform Act (UMRA)

    This rule does not contain a Federal mandate that may result in
expenditures of $100 million or more for State, local, and Tribal
governments, in the aggregate, or the private sector in any one year.
EPA estimated the cost to individual facilities that may have to report
to this final rule using actual facility characteristics such as
throughput and size. EPA also determined the costs to non-reporters for
determination to report. The sum of these costs for the entire industry
has been estimated to be less than $100 million. Thus, this rule is not
subject to the requirements of sections 202 or 205 of UMRA.
    This rule is also not subject to the requirements of section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. Based on EPA's
analysis of the rule's impact on small entities, the Agency determined
that natural gas distribution is the only industry segment that would
potentially have small governments affected by the rule. In this
segment, however, the facilities owned or operated by small governments
are expected to be too small to trigger the 25,000 metric tons
CO2e reporting threshold.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government, as
specified in EO 13132. This regulation applies directly to petroleum
and natural gas facilities that emit greenhouse gases. Few, if any,
State or local government facilities would be affected. This regulation
also does not limit the power of States or localities to collect GHG
data and/or regulate GHG emissions. Thus, EO 13132 does not apply to
this action.

F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

    EPA has concluded that this action may have tribal implications.
However, it will neither impose substantial direct compliance costs on
tribal governments, nor preempt Tribal law. EPA conducted an analysis
to determine potential impact of this action on tribes that own or
operate petroleum and natural gas systems (EPA-HQ-OAR-2009-0923-XXX).
First, EPA analyzed a comprehensive listing of all operators of
petroleum and natural gas systems in the United States in conducting
the threshold analysis. In a separate analysis, EPA researched
additional available data to determine which tribal entities may own or
operate petroleum and natural gas systems that could be impacted by
this final action. As a result of those analyses, EPA found one tribe
that may potentially be impacted by this final action. Finally, during
the comment period for the April 2010 proposal, EPA received comment
from one tribe, Southern Ute, which were specific to the proposed
reporting methodologies.
    As further discussed in the 2009 final rule that established the
Greenhouse Gas reporting program, EPA believes that there are minimal
impacts to tribes. Tribes could be required to submit an annual GHG
report for any facility they own or operate that is subject to the
rule. Specifically, tribes that own or operate oil and gas operations
could be required to report emissions under this

rulemaking. It should be noted that the owner or operator of any
privately owned sources located on a reservation would be required to
report for any applicable facility. EPA sought opportunities to provide
information to tribal governments and representatives during rule
development. As stated in IV.F of this preamble, Executive Order 13175:
Consultation and Coordination with Indian Tribal Governments of 40 CFR
part 98, and in consultation with EPA's American Indian Environment
Office, EPA's outreach plan for the Greenhouse Gas Reporting Rule
included tribes. EPA conducted several conference calls with Tribal
organizations during the proposal phase of part 98. For example, EPA
staff provided information to tribes through conference calls with
multiple Indian working groups and organizations at EPA that interact
with tribes and through individual calls with two Tribal board members
of The Climate Registry (TCR).
    In addition, EPA prepared a short article on the Greenhouse Gas
Reporting Program that appeared on the front page of a Tribal
newsletter--Tribal Air News--that was distributed to EPA/OAQPS's
network of Tribal organizations. EPA gave a presentation on various
climate efforts, including the Greenhouse Gas Reporting Program, at the
National Tribal Conference on Environmental Management on June 24-26,
2008. In addition, EPA distributed copies of a short information sheet
at a meeting of the National Tribal Caucus. See the Summary of EPA
Outreach Activities for Developing the GHG reporting rule, in Docket
No. EPA-HQ-OAR-2008-0508-055 for a complete list of Tribal contacts.
EPA participated in a conference call with Tribal air coordinators in
April 2009 and prepared a guidance sheet for Tribal governments on the
final Part 98. It was posted on the Greenhouse Gas Reporting Program
Web site and published in the Tribal Air Newsletter.
    As required by section 7(a), EPA's Tribal Consultation Official has
certified that the requirements of the Executive Order have been met in
a meaningful and timely manner. A copy of the certification is included
in the docket for this action.

G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks

    This action is not subject to EO 13045 because it does not
establish an environmental standard intended to mitigate health or
safety risks. Also, this is not an economically significant rule under
EO 12866, and thus EO 13045 does not apply.

H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use

    This final rule is not a ``significant energy action'' as defined
in EO 13211 (66 FR 28355, May 22, 2001) because it is not likely to
have a significant adverse effect on the supply, distribution, or use
of energy. Further, EPA has concluded that this final rule is not
likely to have any adverse energy effects. This final rule relates to
monitoring, reporting and recordkeeping at petroleum and gas facilities
that emit over 25,000 mtCO2e and does not impact energy
supply, distribution or use. Therefore, EPA concludes that this final
rule is not likely to have any adverse effects on energy supply,
distribution, or use.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113 (15 U.S.C. 272 note) directs
EPA to use voluntary consensus standards in its regulatory activities
unless to do so would be inconsistent with applicable law or otherwise
impractical. Voluntary consensus standards are technical standards
(e.g., materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by voluntary
consensus standards bodies. NTTAA directs EPA to provide Congress,
through OMB, explanations when the Agency decides not to use available
and applicable voluntary consensus standards.
    This rulemaking involves technical standards. EPA provides the
flexibility to use any one of the voluntary consensus standards from at
least seven different voluntary consensus standards bodies, including
the following: ASTM, ASME, ISO, Gas Processors Association, and
American Gas Association. These voluntary consensus standards will help
facilities monitor, report, and keep records of greenhouse gas
emissions. No new test methods were developed for this final rule.
Instead, EPA reviewed existing rules for source categories and
voluntary greenhouse gas programs and identified existing means of
monitoring, reporting, and keeping records of greenhouse gas emissions.
The existing methods (voluntary consensus standards) include a broad
range of measurement techniques, including many for combustion sources
such as methods to analyze fuel and measure its heating value; methods
to measure gas or liquid flow; and methods to gauge and measure
petroleum and petroleum products.
    By incorporating voluntary consensus standards into this final
rule, EPA is both meeting the requirements of the NTTAA and presenting
multiple options and flexibility for measuring greenhouse gas
emissions.

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
Federal executive policy on environmental justice. Its main provision
directs Federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
    EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not
affect the level of protection provided to human health or the
environment because it is a rule addressing information collection and
reporting procedures.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA),
generally provides that before a rule may take effect, the agency
promulgating the rule must submit a rule report, which includes a copy
of the rule, to each House of the Congress and to the Comptroller
General of the United States. EPA will submit a report containing this
rule and other required information to the U.S. Senate, the U.S. House
of Representatives, and the Comptroller General of the U.S. prior to
publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective December 30, 2010.

List of Subjects in 40 CFR Part 98

    Environmental protection, Administrative practice and procedure,
Greenhouse gases, Incorporation by reference, Suppliers, Reporting and
recordkeeping requirements.

    Dated: November 8, 2010.
Lisa P. Jackson,
Administrator.

0
For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is amended as follows:

PART 98--[AMENDED]

0
1. The authority citation for part 98 continues to read as follows:

    Authority:  42 U.S.C. 7401-7671q.

Subpart A--[Amended]

0
2. Section 98.2 is amended by revising the introductory text to
paragraph (a) to read as follows:

Sec.  98.2  Who must report?

    (a) The GHG reporting requirements and related monitoring,
recordkeeping, and reporting requirements of this part apply to the
owners and operators of any facility that is located in the United
States or under or attached to the Outer Continental Shelf (as defined
in 43 U.S.C. 1331) and that meets the requirements of either paragraph
(a)(1), (a)(2), or (a)(3) of this section; and any supplier that meets
the requirements of paragraph (a)(4) of this section:
* * * * *

0
3. Section 98.6 is amended by adding the following definitions in
alphabetical order and revising the definition of ``United States'' to
read as follows:

Sec.  98.6  Definitions.

* * * * *
    Absorbent circulation pump means a pump commonly powered by natural
gas pressure that circulates the absorbent liquid between the absorbent
regenerator and natural gas contactor.
* * * * *
    Air injected flare means a flare in which air is blown into the
base of a flare stack to induce complete combustion of gas.
* * * * *
    Blowdown vent stack emissions mean natural gas and/or
CO2 released due to maintenance and/or blowdown operations
including compressor blowdown and emergency shut-down (ESD) system
testing.
* * * * *
    Calibrated bag means a flexible, non-elastic, anti-static bag of a
calibrated volume that can be affixed to an emitting source such that
the emissions inflate the bag to its calibrated volume.
* * * * *
    Centrifugal compressor means any equipment that increases the
pressure of a process natural gas or CO2 by centrifugal
action, employing rotating movement of the driven shaft.
    Centrifugal compressor dry seals mean a series of rings around the
compressor shaft where it exits the compressor case that operates
mechanically under the opposing forces to prevent natural gas or
CO2 from escaping to the atmosphere.
    Centrifugal compressor dry seal emissions mean natural gas or
CO2 released from a dry seal vent pipe and/or the seal face
around the rotating shaft where it exits one or both ends of the
compressor case.
    Centrifugal compressor wet seal degassing vent emissions means
emissions that occur when the high-pressure oil barriers for
centrifugal compressors are depressurized to release absorbed natural
gas or CO2. High-pressure oil is used as a barrier against
escaping gas in centrifugal compressor shafts. Very little gas escapes
through the oil barrier, but under high pressure, considerably more gas
is absorbed by the oil. The seal oil is purged of the absorbed gas
(using heaters, flash tanks, and degassing techniques) and
recirculated. The separated gas is commonly vented to the atmosphere.
* * * * *
    Continuous bleed means a continuous flow of pneumatic supply gas to
the process measurement device (e.g. level control, temperature
control, pressure control) where the supply gas pressure is modulated
by the process condition, and then flows to the valve controller where
the signal is compared with the process set-point to adjust gas
pressure in the valve actuator.
* * * * *
    Dehydrator means a device in which a liquid absorbent (including
desiccant, ethylene glycol, diethylene glycol, or triethylene glycol)
directly contacts a natural gas stream to absorb water vapor.
    Dehydrator vent emissions means natural gas and CO2
released from a natural gas dehydrator system absorbent (typically
glycol) reboiler or regenerator to the atmosphere or a flare, including
stripping natural gas and motive natural gas used in absorbent
circulation pumps.
* * * * *
    De-methanizer means the natural gas processing unit that separates
methane rich residue gas from the heavier hydrocarbons (e.g., ethane,
propane, butane, pentane-plus) in feed natural gas stream.
* * * * *
    Desiccant means a material used in solid-bed dehydrators to remove
water from raw natural gas by adsorption or absorption. Desiccants
include activated alumina, pelletized calcium chloride, lithium
chloride and granular silica gel material. Wet natural gas is passed
through a bed of the granular or pelletized solid adsorbent or
absorbent in these dehydrators. As the wet gas contacts the surface of
the particles of desiccant material, water is adsorbed on the surface
or absorbed and dissolves the surface of these desiccant particles.
Passing through the entire desiccant bed, almost all of the water is
adsorbed onto or absorbed into the desiccant material, leaving the dry
gas to exit the contactor.
* * * * *
    Gas conditions mean the actual temperature, volume, and pressure of
a gas sample.
* * * * *
    Gas to oil ratio (GOR) means the ratio of the volume of gas at
standard temperature and pressure that is produced from a volume of oil
when depressurized to standard temperature and pressure.
* * * * *
    High-bleed pneumatic devices are automated, continuous bleed flow
control devices powered by pressurized natural gas and used for
maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature. Part of the gas power stream that is
regulated by the process condition flows to a valve actuator controller
where it vents continuously (bleeds) to the atmosphere at a rate in
excess of 6 standard cubic feet per hour.
* * * * *
    Intermittent bleed pneumatic devices mean automated flow control
devices powered by pressurized natural gas and used for maintaining a
process condition such as liquid level, pressure, delta-pressure and
temperature. These are snap-acting or throttling devices that discharge
the full volume of the actuator intermittently when control action is
necessary, but does not bleed continuously.
* * * * *
    Low-bleed pneumatic devices mean automated flow control devices
powered by pressurized natural gas and used for maintaining a process
condition such as liquid level, pressure, delta-pressure and
temperature. Part of the gas power stream that is regulated by the
process condition flows to a valve actuator controller where it vents
continuously (bleeds) to the atmosphere at a rate equal to or less than
six standard cubic feet per hour.
* * * * *
    Natural gas driven pneumatic pump means a pump that uses
pressurized

natural gas to move a piston or diaphragm, which pumps liquids on the
opposite side of the piston or diaphragm.
* * * * *
    Outer Continental Shelf means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters as defined in 43
U.S.C. 1331, and of which the subsoil and seabed appertain to the
United States and are subject to its jurisdiction and control.
* * * * *
    Reciprocating compressor means a piece of equipment that increases
the pressure of a process natural gas or CO2 by positive
displacement, employing linear movement of a shaft driving a piston in
a cylinder.
    Reciprocating compressor rod packing means a series of flexible
rings in machined metal cups that fit around the reciprocating
compressor piston rod to create a seal limiting the amount of
compressed natural gas or CO2 that escapes to the
atmosphere.
    Re-condenser means heat exchangers that cool compressed boil-off
gas to a temperature that will condense natural gas to a liquid.
* * * * *
    Sales oil means produced crude oil or condensate measured at the
production lease automatic custody transfer (LACT) meter or custody
transfer tank gauge.
* * * * *
    Sour natural gas means natural gas that contains significant
concentrations of hydrogen sulfide (H2S)and/or carbon
dioxide (CO2) that exceed the concentrations specified for
commercially saleable natural gas delivered from transmission and
distribution pipelines.
* * * * *
    Sweet gas is natural gas with low concentrations of hydrogen
sulfide (H2S) and/or carbon dioxide (CO2) that
does not require (or has already had) acid gas treatment to meet
pipeline corrosion-prevention specifications for transmission and
distribution.
* * * * *
    United States means the 50 States, the District of Columbia, the
Commonwealth of Puerto Rico, American Samoa, the Virgin Islands, Guam,
and any other Commonwealth, territory or possession of the United
States, as well as the territorial sea as defined by Presidential
Proclamation No. 5928.
* * * * *
    Vapor recovery system means any equipment located at the source of
potential gas emissions to the atmosphere or to a flare, that is
composed of piping, connections, and, if necessary, flow-inducing
devices, and that is used for routing the gas back into the process as
a product and/or fuel.
    Vaporization unit means a process unit that performs controlled
heat input to vaporize LNG to supply transmission and distribution
pipelines or consumers with natural gas.
* * * * *
    Well completions means the process that allows for the flow of
petroleum or natural gas from newly drilled wells to expel drilling and
reservoir fluids and test the reservoir flow characteristics, steps
which may vent produced gas to the atmosphere via an open pit or tank.
Well completion also involves connecting the well bore to the
reservoir, which may include treating the formation or installing
tubing, packer(s), or lifting equipment, steps that do not
significantly vent natural gas to the atmosphere. This process may also
include high-rate flowback of injected gas, water, oil, and proppant
used to fracture or re-fracture and prop open new fractures in existing
lower permeability gas reservoirs, steps that may vent large quantities
of produced gas to the atmosphere.
    Well workover means the process(es) of performing one or more of a
variety of remedial operations on producing petroleum and natural gas
wells to try to increase production. This process also includes high-
rate flowback of injected gas, water, oil, and proppant used to re-
fracture and prop-open new fractures in existing low permeability gas
reservoirs, steps that may vent large quantities of produced gas to the
atmosphere.
    Wellhead means the piping, casing, tubing and connected valves
protruding above the earth's surface for an oil and/or natural gas
well. The wellhead ends where the flow line connects to a wellhead
valve. Wellhead equipment includes all equipment, permanent and
portable, located on the improved land area (i.e. well pad) surrounding
one or multiple wellheads.
    Wet natural gas means natural gas in which water vapor exceeds the
concentration specified for commercially saleable natural gas delivered
from transmission and distribution pipelines. This input stream to a
natural gas dehydrator is referred to as ``wet gas.''
* * * * *

0
4. Section 98.7 is amended by adding and reserving paragraphs (n) and
(o), and by adding paragraphs (p) and (q) to read as follows:

Sec.  98.7  What standardized methods are incorporated by reference
into this part?

* * * * *
    (n) [Reserved]
    (o) [Reserved]
    (p) The following material is available for purchase from the
American Association of Petroleum Geologists, 1444 South Boulder
Avenue, Tulsa, Oklahoma 74119,<PHONE_NUMBER>, http://www.aapg.org.
    (1) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG
Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J.
Wagner, Jr., Volume 75, Number 10 (October 1991), pages 1644-1651, IBR
approved for Sec.  98.238.
    (2) Alaska Geological Province Boundary Map, Compiled by the
American Association of Petroleum Geologists Committee on Statistics of
Drilling in cooperation with the USGS, 1978, IBR approved for Sec.
98.238.
    (q) The following material is available from the Energy Information
Administration (EIA), 1000 Independence Ave., SW., Washington, DC
20585,<PHONE_NUMBER>, http://www.eia.doe.gov/pub/oil_gas/natural_
gas/data_publications/field_code_master_list/current/pdf/fcml_
all.pdf.
    (1) Oil and Gas Field Code Master List 2008, DOE/EIA0370(08),
January 2009, IBR approved for Sec.  98.238.
    (2) [Reserved]

0
5. Table A-4 to subpart A is amended by adding an entry for ``Petroleum
and Natural Gas Systems (subpart W)'' at the end of the table to read
as follows:

   Table A-4 to Subpart A--Source Category List for Sec.   98.2(a)(2)
------------------------------------------------------------------------

-------------------------------------------------------------------------
Source Categories \a\ Applicable in 2010 and Future Years

                              * * * * * * *
Additional Source Categories \a\ Applicable in 2011 and Future Years

                              * * * * * * *
    Petroleum and Natural Gas Systems (subpart W)
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart.

0
6. Add Subpart W--Petroleum and Natural Gas Systems to read as follows:

Subpart W--Petroleum and Natural Gas Systems

Sec.
98.230 Definition of the source category.

98.231 Reporting threshold.
98.232 GHGs to report.
98.233 Calculating GHG emissions.
98.234 Monitoring and QA/QC requirements.
98.235 Procedures for estimating missing data.
98.236 Data reporting requirements.
98.237 Records that must be retained.
98.238 Definitions.
Table W-1A to Subpart W of Part 98--Default Whole Gas Emission
Factors for Onshore Petroleum and Natural Gas Production
Table W-1B to Subpart W of Part 98--Default Average Component Counts
for Major Onshore Natural Gas Production Equipment
Table W-1C to Subpart W of Part 98--Default Average Component Counts
For Major Crude Oil Production Equipment
Table W-1D of Subpart W of Part 98--Designation Of Eastern And
Western U.S.
Table W-2 to Subpart W of Part 98--Default Total Hydrocarbon
Emission Factors for Onshore Natural Gas Processing
Table W-3 to Subpart W of Part 98--Default Total Hydrocarbon
Emission Factors for Onshore Natural Gas Transmission Compression
Table W-4 to Subpart W of Part 98--Default Total Hydrocarbon
Emission Factors for Underground Natural Gas Storage
Table W-5 to Subpart W of Part 98--Default Methane Emission Factors
for Liquefied Natural Gas (LNG) Storage
Table W-6 to Subpart W of Part 98--Default Methane Emission Factors
for LNG Import and Export Equipment
Table W-7 to Subpart W of Part 98--Default Methane Emission Factors
for Natural Gas Distribution

Sec.  98.230  Definition of the source category.

    (a) This source category consists of the following industry
segments:
    (1) Offshore petroleum and natural gas production. Offshore
petroleum and natural gas production is any platform structure, affixed
temporarily or permanently to offshore submerged lands, that houses
equipment to extract hydrocarbons from the ocean or lake floor and that
processes and/or transfers such hydrocarbons to storage, transport
vessels, or onshore. In addition, offshore production includes
secondary platform structures connected to the platform structure via
walkways, storage tanks associated with the platform structure and
floating production and storage offloading equipment (FPSO). This
source category does not include reporting of emissions from offshore
drilling and exploration that is not conducted on production platforms.
    (2) Onshore petroleum and natural gas production. Onshore petroleum
and natural gas production means all equipment on a well pad or
associated with a well pad (including compressors, generators, or
storage facilities), and portable non-self-propelled equipment on a
well pad or associated with a well pad (including well drilling and
completion equipment, workover equipment, gravity separation equipment,
auxiliary non-transportation-related equipment, and leased, rented or
contracted equipment) used in the production, extraction, recovery,
lifting, stabilization, separation or treating of petroleum and/or
natural gas (including condensate). This equipment also includes
associated storage or measurement vessels and all enhanced oil recovery
(EOR) operations using CO2, and all petroleum and natural
gas production located on islands, artificial islands, or structures
connected by a causeway to land, an island, or artificial island.
    (3) Onshore natural gas processing. Natural gas processing
separates and recovers natural gas liquids (NGLs) and/or other non-
methane gases and liquids from a stream of produced natural gas using
equipment performing one or more of the following processes: oil and
condensate removal, water removal, separation of natural gas liquids,
sulfur and carbon dioxide removal, fractionation of NGLs, or other
processes, and also the capture of CO2 separated from
natural gas streams. This segment also includes all residue gas
compression equipment owned or operated by the natural gas processing
facility, whether inside or outside the processing facility fence. This
source category does not include reporting of emissions from gathering
lines and boosting stations. This source category includes:
    (i) All processing facilities that fractionate.
    (ii) All processing facilities that do not fractionate with
throughput of 25 MMscf per day or greater.
    (4) Onshore natural gas transmission compression. Onshore natural
gas transmission compression means any stationary combination of
compressors that move natural gas at elevated pressure from production
fields or natural gas processing facilities in transmission pipelines
to natural gas distribution pipelines or into storage. In addition,
transmission compressor station may include equipment for liquids
separation, natural gas dehydration, and tanks for the storage of water
and hydrocarbon liquids. Residue (sales) gas compression operated by
natural gas processing facilities are included in the onshore natural
gas processing segment and are excluded from this segment. This source
category also does not include reporting of emissions from gathering
lines and boosting stations--these sources are currently not covered by
subpart W.
    (5) Underground natural gas storage. Underground natural gas
storage means subsurface storage, including depleted gas or oil
reservoirs and salt dome caverns that store natural gas that has been
transferred from its original location for the primary purpose of load
balancing (the process of equalizing the receipt and delivery of
natural gas); natural gas underground storage processes and operations
(including compression, dehydration and flow measurement, and excluding
transmission pipelines); and all the wellheads connected to the
compression units located at the facility that inject and recover
natural gas into and from the underground reservoirs.
    (6) Liquefied natural gas (LNG) storage. LNG storage means onshore
LNG storage vessels located above ground, equipment for liquefying
natural gas, compressors to capture and re-liquefy boil-off-gas, re-
condensers, and vaporization units for re-gasification of the liquefied
natural gas.
    (7) LNG import and export equipment. LNG import equipment means all
onshore or offshore equipment that receives imported LNG via ocean
transport, stores LNG, re-gasifies LNG, and delivers re-gasified
natural gas to a natural gas transmission or distribution system. LNG
export equipment means all onshore or offshore equipment that receives
natural gas, liquefies natural gas, stores LNG, and transfers the LNG
via ocean transportation to any location, including locations in the
United States.
    (8) Natural gas distribution. Natural gas distribution means the
distribution pipelines (not interstate transmission pipelines or
intrastate transmission pipelines) and metering and regulating
equipment at city gate stations, and excluding customer meters, that
physically deliver natural gas to end users and is operated by a Local
Distribution Company (LDC) that is regulated as a separate operating
company by a public utility commission or that is operated as an
independent municipally-owned distribution system. This segment
excludes customer meters and infrastructure and pipelines (both
interstate and intrastate) delivering natural gas directly to major
industrial users and ``farm taps'' upstream of the local distribution
company inlet.
    (b) [Reserved]

Sec.  98.231  Reporting threshold.

    (a) You must report GHG emissions under this subpart if your
facility contains petroleum and natural gas systems and the facility
meets the requirements of Sec.  98.2(a)(2). Facilities must report
emissions from the onshore petroleum and natural gas production

industry segment only if emission sources specified in paragraph Sec.
98.232(c) emit 25,000 metric tons of CO2 equivalent or more
per year. Facilities must report emissions from the natural gas
distribution industry segment only if emission sources specified in
paragraph Sec.  98.232(i) emit 25,000 metric tons of CO2
equivalent or more per year.
    (b) For applying the threshold defined in Sec.  98.2(a)(2), natural
gas processing facilities must also include owned or operated residue
gas compression equipment.

Sec.  98.232  GHGs to report.

    (a) You must report CO2, CH4, and
N2O emissions from each industry segment specified in
paragraph (b) through (i) of this section, CO2,
CH4, and N2O emissions from each flare as
specified in paragraph (j) of this section, and stationary and portable
combustion emissions as applicable as specified in paragraph (k) of
this section.
    (b) For offshore petroleum and natural gas production, report
CO2, CH4, and N2O emissions from
equipment leaks, vented emission, and flare emission source types as
identified in the data collection and emissions estimation study
conducted by BOEMRE in compliance with 30 CFR 250.302 through 304.
Offshore platforms do not need to report portable emissions.
    (c) For an onshore petroleum and natural gas production facility,
report CO2, CH4, and N2O emissions
from only the following source types on a well pad or associated with a
well pad:
    (1) Natural gas pneumatic device venting.
    (2) [Reserved]
    (3) Natural gas driven pneumatic pump venting.
    (4) Well venting for liquids unloading.
    (5) Gas well venting during well completions without hydraulic
fracturing.
    (6) Gas well venting during well completions with hydraulic
fracturing.
    (7) Gas well venting during well workovers without hydraulic
fracturing.
    (8) Gas well venting during well workovers with hydraulic
fracturing.
    (9) Flare stack emissions.
    (10) Storage tanks vented emissions from produced hydrocarbons.
    (11) Reciprocating compressor rod packing venting.
    (12) Well testing venting and flaring.
    (13) Associated gas venting and flaring from produced hydrocarbons.
    (14) Dehydrator vents.
    (15) [Reserved]
    (16) EOR injection pump blowdown.
    (17) Acid gas removal vents.
    (18) EOR hydrocarbon liquids dissolved CO2.
    (19) Centrifugal compressor venting.
    (20) [Reserved]
    (21) Equipment leaks from valves, connectors, open ended lines,
pressure relief valves, pumps, flanges, and other equipment leak
sources (such as instruments, loading arms, stuffing boxes, compressor
seals, dump lever arms, and breather caps).
    (22) You must use the methods in Sec.  98.233(z) and report under
this subpart the emissions of CO2, CH4, and
N2O from stationary or portable fuel combustion equipment
that cannot move on roadways under its own power and drive train, and
that are located at an onshore production well pad. Stationary or
portable equipment are the following equipment which are integral to
the extraction, processing or movement of oil or natural gas: Well
drilling and completion equipment, workover equipment, natural gas
dehydrators, natural gas compressors, electrical generators, steam
boilers, and process heaters.
    (d) For onshore natural gas processing, report CO2 and
CH4 emissions from the following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor venting.
    (3) Blowdown vent stacks.
    (4) Dehydrator vents.
    (5) Acid gas removal vents.
    (6) Flare stack emissions.
    (7) Equipment leaks from valves, connectors, open ended lines,
pressure relief valves, and meters.
    (e) For onshore natural gas transmission compression, report
CO2 and CH4 emissions from the following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor venting.
    (3) Transmission storage tanks.
    (4) Blowdown vent stacks.
    (5) Natural gas pneumatic device venting.
    (6) [Reserved]
    (7) Equipment leaks from valves, connectors, open ended lines,
pressure relief valves, and meters.
    (f) For underground natural gas storage, report CO2 and
CH4 emissions from the following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor venting.
    (3) Natural gas pneumatic device venting.
    (4) [Reserved]
    (5) Equipment leaks from valves, connectors, open ended lines,
pressure relief valves, and meters.
    (g) For LNG storage, report CO2 and CH4
emissions from the following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor venting.
    (3) Equipment leaks from valves; pump seals; connectors; vapor
recovery compressors, and other equipment leak sources.
    (h) LNG import and export equipment, report CO2 and
CH4 emissions from the following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor venting.
    (3) Blowdown vent stacks.
    (4) Equipment leaks from valves, pump seals, connectors, vapor
recovery compressors, and other equipment leak sources.
    (i) For natural gas distribution, report emissions from the
following sources:
    (1) Above ground meters and regulators at custody transfer city
gate stations, including equipment leaks from connectors, block valves,
control valves, pressure relief valves, orifice meters, regulators, and
open ended lines. Customer meters are excluded.
    (2) Above ground meters and regulators at non-custody transfer city
gate stations, including station equipment leaks. Customer meters are
excluded.
    (3) Below ground meters and regulators and vault equipment leaks.
Customer meters are excluded.
    (4) Pipeline main equipment leaks.
    (5) Service line equipment leaks.
    (6) Report under subpart W of this part the emissions of
CO2, CH4, and N2O emissions from
stationary fuel combustion sources following the methods in Sec.
98.233(z).
    (j) All applicable industry segments must report the
CO2, CH4, and N2O emissions from each
flare.
    (k) Report under subpart C of this part (General Stationary Fuel
Combustion Sources) the emissions of CO2, CH4,
and N2O from each stationary fuel combustion unit by
following the requirements of subpart C. Onshore petroleum and natural
gas production facilities must report stationary and portable
combustion emissions as specified in paragraph (c) of this section.
Natural gas distribution facilities must report stationary combustion
emissions as specified in paragraph (i) of this section.
    (l) You must report under subpart PP of this part (Suppliers of
Carbon Dioxide), CO2 emissions captured and transferred off
site by following the requirements of subpart PP.

Sec.  98.233  Calculating GHG emissions.

    You must calculate and report the annual GHG emissions as
prescribed in this section. For actual conditions,

reporters must use average atmospheric conditions or typical operating
conditions as applicable to the respective monitoring methods in this
section.
    (a) Natural gas pneumatic device venting. Calculate CH4
and CO2 emissions from continuous high bleed, continuous low
bleed, and intermittent bleed natural gas pneumatic devices using
Equation W-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.173

Where:

Masss,i = Annual total mass GHG emissions in metric tons
CO2e per year at standard conditions from a natural gas
pneumatic device vent, for GHG i.
Count = Total number of continuous high bleed, continuous low bleed,
or intermittent bleed natural gas pneumatic devices of each type as
determined in paragraph (a)(1) of this section.
EF = Population emission factors for natural gas pneumatic device
venting listed in Tables W-1A, W-3, and W-4 of this subpart for
onshore petroleum and natural gas production, onshore natural gas
transmission compression, and underground natural gas storage
facilities, respectively.
GHGi = For onshore petroleum and natural gas production
facilities, concentration of GHG i, CH4 or
CO2, in produced natural gas; for facilities listed in
Sec.  98.230(a)(3) through (a)(8), GHGi equals 1.
Convi = Conversion from standard cubic feet to metric
tons CO2e; 0.000410 for CH4, and 0.00005357
for CO2.
24 * 365 = Conversion to yearly emissions estimate.

    (1) For onshore petroleum and natural gas production, provide the
total number of continuous high bleed, continuous low bleed, or
intermittent bleed natural gas pneumatic devices of each type as
follows:
    (i) In the first calendar year, for the total number of each type,
you may count the total of each type, or count any percentage number of
each type plus an engineering estimate based on best available data of
the number not counted.
    (ii) In the second consecutive year, for the total number of each
type, you may count the total of each type, or count any percentage
number of each type plus an engineering estimate based on best
available data of the number not counted.
    (iii) In the third consecutive calendar year, complete the count of
all pneumatic devices, including any changes to equipment counted in
prior years.
    (iv) For the calendar year immediately following the third
consecutive calendar year, and for calendar years thereafter,
facilities must update the total count of pneumatic devices and adjust
accordingly to reflect any modifications due to changes in equipment.
    (2) For onshore natural gas transmission compression and
underground natural gas storage, all natural gas pneumatic devices must
be counted in the first year and updated every calendar year.
    (b) [Reserved]
    (c) Natural gas driven pneumatic pump venting. Calculate
CH4 and CO2 emissions from natural gas driven
pneumatic pump venting using Equation W-2 of this section. Natural gas
driven pneumatic pumps covered in paragraph (e) of this section do not
have to report emissions under paragraph (c) of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.174

Where:

Masss,i = Annual total mass GHG emissions in metric tons
CO2e per year at standard conditions from all natural gas
pneumatic pump venting, for GHG i.
Count = Total number of natural gas pneumatic pumps.
EF = Population emission factors for natural gas pneumatic pump
venting listed in Tables W-1A of this subpart for onshore petroleum
and natural gas production.
GHGi = Concentration of GHG i, CH4 or
CO2, in produced natural gas.
Convi = Conversion from standard cubic feet to metric
tons CO2e; 0.000410 for CH4, and 0.00005357
for CO2.
24 * 365 = Conversion to yearly emissions estimate.

    (d) Acid gas removal (AGR) vents. For AGR vent (including processes
such as amine, membrane, molecular sieve or other absorbents and
adsorbents), calculate emissions for CO2 only (not
CH4) vented directly to the atmosphere or through a flare,
engine (e.g. permeate from a membrane or de-adsorbed gas from a
pressure swing adsorber used as fuel supplement), or sulfur recovery
plant using any of the calculation methodologies described in paragraph
(d) of this section.
    (1) Calculation Methodology 1. If you operate and maintain a CEMS