Cancer URE values used in our risk assessments are those that have been developed to generally provide an upper bound estimate of risk. That is, they represent a "plausible upper limit to the true value of a quantity" (although this is usually not a true statistical confidence limit). In some circumstances, the true risk could be as low as zero; however, in other circumstances the risk could also be greater. When developing an upper bound estimate of risk and to provide risk values that do not underestimate risk, health-protective default approaches are generally used. To err on the side of ensuring adequate health-protection, the EPA typically uses the upper bound estimates rather than lower bound or central tendency estimates in our risk assessments, an approach that may have limitations for other uses (e.g., priority-setting or expected benefits analysis).
      Chronic noncancer reference (RfC and RfD) values represent chronic exposure levels that are intended to be health-protective levels. Specifically, these values provide an estimate (with uncertainty spanning perhaps an order of magnitude) of daily oral exposure (RfD) or of a continuous inhalation exposure (RfC) to the human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a lifetime. To derive values that are intended to be "without appreciable risk," the methodology relies upon an UF approach (U.S. EPA, 1993, 1994) which includes consideration of both uncertainty and variability. When there are gaps in the available information, UF are applied to derive reference values that are intended to protect against appreciable risk of deleterious effects. The UF are commonly default values, e.g., factors of 10 or 3, used in the absence of compound-specific data; where data are available, UF may also be developed using compound-specific information. When data are limited, more assumptions are needed and more UF are used. Thus, there may be a greater tendency to overestimate risk in the sense that further study might support development of reference values that are higher (i.e., less potent) because fewer default assumptions are needed. However, for some pollutants, it is possible that risks may be underestimated. While collectively termed "UF," these factors account for a number of different quantitative considerations when using observed animal (usually rodent) or human toxicity data in the development of the RfC. The UF are intended to account for: (1) Variation in susceptibility among the members of the human population (i.e., inter-individual variability); (2) uncertainty in extrapolating from experimental animal data to humans (i.e., interspecies differences); (3) uncertainty in extrapolating from data obtained in a study with less-than-lifetime exposure (i.e., extrapolating from sub-chronic to chronic exposure); (4) uncertainty in extrapolating the observed data to obtain an estimate of the exposure associated with no adverse effects; and (5) uncertainty when the database is incomplete or there are problems with the applicability of available studies. Many of the UF used to account for variability and uncertainty in the development of acute reference values are quite similar to those developed for chronic durations, but they more often use individual UF values that may be less than 10. Uncertainty factors are applied based on chemical-specific or health effect-specific information (e.g., simple irritation effects do not vary appreciably between human individuals, hence a value of 3 is typically used), or based on the purpose for the reference value (see the following paragraph). The UF applied in acute reference value derivation include: (1) Heterogeneity among humans; (2) uncertainty in extrapolating from animals to humans; (3) uncertainty in lowest observed adverse effect (exposure) level to no observed adverse effect (exposure) level adjustments; and (4) uncertainty in accounting for an incomplete database on toxic effects of potential concern. Additional adjustments are often applied to account for uncertainty in extrapolation from observations at one exposure duration (e.g., 4 hours) to derive an acute reference value at another exposure duration (e.g., 1 hour).
      Not all acute reference values are developed for the same purpose, and care must be taken when interpreting the results of an acute assessment of human health effects relative to the reference value or values being exceeded. Where relevant to the estimated exposures, the lack of short-term dose-response values at different levels of severity should be factored into the risk characterization as potential uncertainties.
      Although every effort is made to identify peer-reviewed reference values for cancer and noncancer effects for all pollutants emitted by the sources included in this assessment, some HAP continue to have no reference values for cancer or chronic noncancer or acute effects. Since exposures to these pollutants cannot be included in a quantitative risk estimate, an understatement of risk for these pollutants at environmental exposure levels is possible. For a group of compounds that are either unspeciated or do not have reference values for every individual compound (e.g., glycol ethers), we conservatively use the most protective reference value to estimate risk from individual compounds in the group of compounds.
      Additionally, chronic reference values for several of the compounds included in this assessment are currently under the EPA IRIS review, and revised assessments may determine that these pollutants are more or less potent than the current value. We may re-evaluate residual risks for the final rulemaking if these reviews are completed prior to our taking final action for these source categories and a dose-response metric changes enough to indicate that the risk assessment supporting this notice may significantly understate human health risk.
v. Uncertainties in the Multi-Pathway and Environmental Effects Assessment
	We generally assume that when exposure levels are not anticipated to adversely affect human health, they also are not anticipated to adversely affect the environment. For each source category, we generally rely on the site-specific levels of PB-HAP emissions to determine whether a full assessment of the multi-pathway and environmental effects is necessary. As discussed above, we conclude that the potential for these types of impacts is low for these source categories.
vi. Uncertainties in the Facility-Wide Risk Assessment 	Given that the same general analytical approach and the same models were used to generate facility-wide risk results as were used to generate the source category risk results, the same types of uncertainties discussed above for our source category risk assessments apply to the facility-wide risk assessments. Additionally, the degree of uncertainty associated with facility-wide emissions and risks is likely greater because we generally have not conducted a thorough engineering review of emissions data for source categories not currently undergoing an RTR review.
vii.	Uncertainties in the Demographic Analysis
	Our analysis of the distribution of risks across various demographic groups is subject to the typical uncertainties associated with census data (e.g., errors in filling out and transcribing census forms), as well as the additional uncertainties associated with the extrapolation of census-block group data (e.g., income level and education level) down to the census block level.
2. What are the results and proposed decisions from the risk review for the Oil and Natural Gas Production source category?
a. Results of the Risk Assessments and Analyses
	We conducted an inhalation risk assessment for the Oil and Natural Gas Production source category. We also conducted an assessment of facility-wide risk. Details of the risk assessments and analyses can be found in the residual risk documentation, which is available in the docket for this action. For informational purposes and to examine the potential for any EJ issues that might be associated with each source category, we performed a demographic analysis of population risks.
i. Inhalation Risk Assessment Results
	Table 2 provides an overall summary of the results of the inhalation risk assessment.
  TABLE 2. OIL AND NATURAL GAS PRODUCTION INHALATION RISK ASSESSMENT RESULTS
                             Number of Facilities1
                                    Maximum
                                  Individual
                                  Cancer Risk
                                (in 1 million)2
                             Estimated Population
                          at Risk >= 1-in-1 Million
                               Estimated Annual
                                    Cancer
                          Incidence (cases per year)
                                    Maximum
                               Chronic Noncancer
                                    TOSHI3
                     Maximum Off-site Acute Noncancer HQ4

                            Actual Emissions Level
                           Allowable Emissions Level

                            Actual Emissions Level
                           Allowable Emissions Level

                                      990
                                      40
                                      400
                                    160,000
                                     0.02
                                      0.1
                                      0.7
                                       9
1 Number of facilities evaluated in the risk analysis.
2 Estimated maximum individual excess lifetime cancer risk.
3 Maximum TOSHI. The target organ with the highest TOSHI for the Oil and Natural Gas Production source category is the respiratory system.
4 The maximum estimated acute exposure concentration was divided by available short-term dose-response values to develop an array of HQ values. HQ values shown use the lowest available acute dose-response value, which, in most cases, is the REL.

	As shown in Table 2, the results of the inhalation risk assessment performed using actual emissions data indicate the maximum lifetime individual cancer risk could be as high as 40-in-1 million, due to benzene emissions; the maximum chronic noncancer TOSHI value could be as high as 0.1, due to naphthalene emissions; and the maximum off-site acute HQ value could be as high as 9, based on the REL value for benzene. The total estimated cancer incidence from these facilities based on actual emission levels is 0.02 excess cancer cases per year, or 1 in every 50 years.
	As explained above, our analysis of potential differences between actual emission levels and emissions allowable under the oil and natural gas production MACT standard indicate that MACT-allowable emission levels may be up to 50 times greater than actual emission levels. Considering this difference, the risk results from the inhalation risk assessment indicate the maximum lifetime individual cancer risk could be as high as 400-in-1 million, and the maximum chronic noncancer TOSHI value could be as high as 0.7 at the MACT-allowable emissions level.
ii. Facility-Wide Risk Assessment Results
	A facility-wide risk analysis was also conducted based on actual emissions levels. Table 3 displays the results of the facility-wide risk assessment. For detailed facility-specific results, see Table 2 of Appendix 6 of the risk document in the docket for this rulemaking.
 TABLE 3. OIL AND NATURAL GAS PRODUCTION FACILITY-WIDE RISK ASSESSMENT RESULTS
Number of facilities analyzed
                                      990
Cancer Risk
Estimated maximum facility-wide individual cancer risk (in 1 million)
                                      100

Number of facilities with estimated facility-wide individual cancer risk of 100-in-1 million or more
                                       1

Number of facilities at which the Oil and Natural Gas Production source category contributes 50 percent or more to the facility-wide individual cancer risks of 100-in-1 million or more
                                       0

Number of facilities with facility-wide individual cancer risk of 1-in-1 million or more
                                      140

Number of facilities at which the Oil and Natural Gas Production source category contributes 50 percent or more to the facility-wide individual cancer risk of 1-in-1 million or more
                                      85
Chronic Noncancer Risk
Maximum facility-wide chronic noncancer TOSHI
                                       9

Number of facilities with facility-wide maximum noncancer TOSHI greater than 1
                                      10

Number of facilities at which the Oil and Natural Gas Production source category contributes 50 percent or more to the facility-wide maximum noncancer TOSHI of 1 or more
                                       0

	The facility-wide MIR from all HAP emissions at a facility that contains sources subject to the oil and natural gas production MACT standards is estimated to be 100-in-1 million based on actual emissions. Of the 990 facilities included in this analysis, only one has a facility-wide MIR of 100-in-1 million. At this facility, oil and natural gas production accounts for less than 2 percent of the total facility-wide risk. Nickel emissions from oil-fired boilers, and formaldehyde emissions from RICE contribute essentially all the facility-wide risks at this facility. There are 140 facilities with facility-wide MIRs of 1-in-1 million or greater. Of these facilities, 85 have oil and natural gas production operations that contribute greater than 50 percent to the facility-wide risks. In general, the facility-wide cancer risks at these facilities are driven by benzene emissions from oil and natural gas production and formaldehyde emissions from RICE. We are proposing to reduce benzene emissions from small glycol dehydrators in today's action.  Formaldehyde emissions will be assessed under future RTR for RICE.
	The facility-wide maximum individual chronic noncancer TOSHI is estimated to be 9 based on actual emissions. Of the 990 facilities included in this analysis, 10 have facility-wide maximum chronic noncancer TOSHI values greater than 1. Of these facilities, none had oil and natural gas production operations that contributed greater than 50 percent to these facility-wide risks. The chronic noncancer risks at these 10 facilities are primarily driven by acrolein emissions from RICE.
iii.	Demographic Risk Analysis Results
	The results of the demographic analyses performed to investigate the distribution of cancer risks at or above 1-in-1 million among the surrounding population are summarized in Table 4 below. These results, for various demographic groups, are based on actual emissions levels for the population living within 50 km of the facilities.
   TABLE 4. OIL AND NATURAL GAS PRODUCTION DEMOGRAPHIC RISK ANALYSIS RESULTS

                                  Nationwide
      Population with cancer risk at or above 1 in a million due to....

                         Source Category HAP emissions
                          Facility-wide HAP emissions
Total population
                                  285,000,000
                                    160,000
                                    597,000
                                Race by percent
White
                                      75
                                      62
                                      61
All Other Races
                                      25
                                      38
                                      39
                                Race by percent
White
                                      75
                                      62
                                      61
African American
                                      12
                                      12
                                       8
Native American
                                      0.9
                                      0.7
                                      1.3
Other and Multiracial
                                      12
                                      25
                                      30
                             Ethnicity by percent
Hispanic
                                      14
                                      22
                                      34
Non-Hispanic
                                      86
                                      78
                                      66
                               Income by percent
Below poverty level
                                      13
                                      14
                                      19
Above poverty level
                                      87
                                      86
                                      81
                             Education by percent
Over 25 and without high school diploma
                                      13
                                      10
                                      16
Over 25 and with a high school diploma
                                      87
                                      90
                                      84

	The results of the Oil and Natural Gas Production source category demographic analysis indicate that there are approximately 160,000 people exposed to a cancer risk at or above 1-in-1 million due to emissions from the source category, including an estimated 38 percent that are classified as minority (listed as "All Other Races" in the table above). Of the 160,000 people with estimated cancer risks at or above 1-in-1-million from the source category, 25 percent are in the "Other and Multiracial" demographic group, 22 percent are in the "Hispanic or Latino" demographic group, and 14 percent are in the "Below poverty level" demographic group, results which are 13, 8 and 1 percentage points higher, respectively, than the respective percentages for these demographic groups across the United States. The percentages for the other demographic groups are lower than their respective nationwide percentages. The table also shows that there are approximately 597,000 people exposed to an estimated cancer risk at or above 1-in-1 million due to facility-wide emissions, including 30 percent in the "Other and Multiracial" demographic group, 34 percent in the "Hispanic or Latino" demographic group, 1.3 percent in the "Native American" demographic group, and 16 percent in the "Over 25 and without high school diploma" demographic group, results which are 18, 2, 0.4 and 3 percentage points higher than the percentages for these demographic groups across the United States, respectively. The percentages for the other demographic groups are lower than their respective nationwide percentages.
b. What are the proposed risk decisions for the Oil and Natural Gas Production source category?
i. Risk Acceptability
	The Agency considered the available health information -- the MIR; the numbers of persons in various risk ranges; cancer incidence; the maximum non-cancer hazard index (HI); the maximum acute non-cancer hazard; the extent of non-cancer risks; the potential for adverse environmental effects; and distribution of risks in the exposed population; and risk estimation uncertainty (54 FR 38044, September 14, 1989)  -  in developing the proposed CAA section 112(f)(2) standards for this source category.
      For the Oil and Natural Gas Production source category, the risk analysis we performed indicates that the cancer risks to the individual most exposed could be as high as 40-in-1 million due to actual emissions and as high as 400-in-1 million due to MACT-allowable emissions. While the 40-in-1-million risk due to actual emissions is considerably less than 100-in-1 million, which is the presumptive limit of acceptability, the 400-in-1-million risk due to allowable emissions is considerably higher and is considered unacceptable. We do note however, that the risk analysis shows low cancer incidence (1 case in every 50 years), low potential for adverse environmental effects or human health multi-pathway effects, and that chronic noncancer health impacts are unlikely.
      We also conclude that acute noncancer health impacts are unlikely. As discussed above, screening estimates of acute exposures and risks were evaluated for each of the HAP at the point of highest off-site exposure for each facility (i.e., not just the census block centroids) assuming that a person is located at this spot at a time when both the peak emission rate and worst-case dispersion conditions occur. Under these worst-case conditions, we estimate benzene acute HQ values (based on the REL) could be as high as 9. Although the REL (which indicates the level below which adverse effects are not anticipated) is exceeded in this case, we believe the potential for acute effects is low for several reasons. First, the acute modeling scenario is worst-case because of the confluence of peak emission rates and worst-case dispersion conditions. Second, the benzene REL is based on a 6-hour exposure duration because a 1-hour exposure duration value was unavailable. An REL based on a 6-hour exposure duration is generally lower than an REL based on a 1-hour exposure duration and, consequently, easier to exceed. Also, although there are exceedances of the REL, the highest estimated 1-hour exposure is less than 10 percent of the AEGL-1 value, which is a level at which effects could be experienced. Finally, the generally sparse populations near these facilities make it less likely that a person would be near the plant to be exposed. For example, in the two cases where the acute HQ value is as high as 9, there are only 30 people associated with the census blocks within 2 miles of the two facilities.
      While our additional analysis of facility-wide risks showed that there is one facility with maximum facility-wide cancer risk of 100-in-1 million or greater and 10 facilities with a maximum chronic noncancer TOSHI greater than 1, it also showed that oil and natural gas production operations did not drive these risks.
      In determining whether risk is acceptable, we focus on the results of all aspects of the risk assessment. In this case, although a number of factors we considered indicate little risk concern, we are proposing to determine that the risks are unacceptable in large part because the MIR is 400-in-1 million due to MACT-allowable emissions, which greatly exceeds the "presumptive limit on maximum individual lifetime risk of approximately 1-in-10 thousand [100-in-1million] recognized in the Benzene NESHAP (54 FR 38045)." The MIR based on MACT-allowable emissions is driven by the allowable emissions of 1 tpy benzene under the MACT as a compliance option. We are therefore proposing to eliminate the alternative compliance option of 1 tpy benzene from the existing glycol dehydrator MACT requirements. With this change, the source category MIR based on MACT-allowable emissions would be reduced to 40-in-1 million, which we find acceptable in light of all the other factors considered. Thus, we are proposing that the risks from the Oil and Natural Gas Production source category are acceptable, with the removal of the alternative compliance option of 0.9 Mg/yr benzene limit from the current glycol dehydrator MACT requirements.
ii. Ample Margin of Safety
	We next considered whether this revised standard (existing MACT plus removal of 0.9 Mg/yr benzene compliance option) provides an ample margin of safety. In this analysis, we investigated available emissions control options that might reduce the risk associated with emissions from the source category and considered this information along with all of the health risks and other health information considered in the risk acceptability determination.
      One option we considered was requiring additional controls on glycol dehydrators. This would require adding a second control device in the same manner that was discussed in the above the floor evaluation in section VII.B.1. The cost effectiveness associated with that option would be $167,200/Mg which we believe is too high to require additional controls on glycol dehydrators.
      Another option we considered was requiring additional controls on storage vessels. This would mean sources would have to add a second control device to the required MACT floor control device (cost effectiveness of $18,300/Mg). Similar to our discussion of beyond the MACT floor controls for glycol dehydrators in section VII.B.1., the incremental cost to add a second control device for storage vessels would be approximately 20 times higher than the MACT floor cost effectiveness, or $366,000/Mg. We do not believe this cost effectiveness is reasonable.
      A third option we considered was the implementation of a LDAR program. An assessment performed for various LDAR options under the NSPS in section VI.B.4.b. of today's action yielded the lowest cost effectiveness of $5,170/Mg ($4,700/ton) for control of VOC for the options evaluated. A LDAR program to control HAP would involve similar costs for equipment, labor, etc., but since there is approximately 20 times less HAP than VOC present in material handled in regulated equipment, the cost effectiveness to control HAP would be approximately $100,000/Mg of HAP which we believe is not reasonable.
      In accordance with the approach established in the Benzene NESHAP, the EPA weighed all health risk measures and information considered in the risk acceptability determination, along with the costs and economic impacts of emissions controls, technological feasibility, uncertainties, and other relevant factors, in making our ample margin of safety determination. Considering the health risk information and the high cost effectiveness of the options identified, we propose that the existing MACT standards, with the removal of the 1 tpy benzene limit compliance option from the glycol dehydrator standards, provide an ample margin of safety to protect public health.
      While we are proposing that the emissions covered by the oil and natural gas production MACT standards as described above provide an ample margin of safety to protect public health, we are concerned about the estimated facility-wide risks identified through these screening analyses. As described previously, the highest estimated facility-wide cancer risks are mostly due to emissions from oil fired boilers and RICE. Both of these sources are regulated under other source categories, and we anticipate that emission reductions from those sources will occur as standards for those source categories are implemented.
3. What are the results and proposed decisions from the risk review for the Natural Gas Transmission and Storage source category?
a. Results of the Risk Assessments and Analyses
	We conducted an inhalation risk assessment for the Natural Gas Transmission and Storage source category. We also conducted an assessment of facility-wide risk and performed a demographic analysis of population risks. Details of the risk assessments and analyses can be found in the residual risk documentation, which is available in the docket for this action.
i. Inhalation Risk Assessment Results
	Table 5 provides an overall summary of the results of the inhalation risk assessment. For informational purposes and to examine the potential for any EJ issues that might be associated with each source category, we performed a demographic analysis of population risks.
TABLE 5. NATURAL GAS TRANSMISSION AND STORAGE INHALATION RISK ASSESSMENT RESULTS
                             Number of Facilities1
                                    Maximum
                                  Individual
                                  Cancer Risk
                                (in 1 million)2
                             Estimated Population
                          at Risk >= 1-in-1 Million
                               Estimated Annual
                                    Cancer
                          Incidence (cases per year)
                                    Maximum
                               Chronic Noncancer
                                    TOSHI3
                     Maximum Off-site Acute Noncancer HQ4

                            Actual Emissions Level
                           Allowable Emissions Level

                            Actual Emissions Level
                           Allowable Emissions Level

                                      321
                                      90
                                      90
                                     2,500
                                     0.001
                                      0.4
                                      0.8
                                       5
1 Number of facilities evaluated in the risk analysis.
2 Estimated maximum individual excess lifetime cancer risk.
3 Maximum TOSHI. The target organ with the highest TOSHI for the Natural Gas Transmission and Storage source category is the immune system.
4 The maximum estimated acute exposure concentration was divided by available short-term dose-response values to develop an array of HQ values. HQ values shown use the lowest available acute dose-response value, which, in most cases, is the REL.

	As shown in Table 5, the results of the inhalation risk assessment performed using actual emissions data indicate the maximum lifetime individual cancer risk could be as high as 90-in-1 million, due to benzene emissions; the maximum chronic noncancer TOSHI value could be as high as 0.4, due to benzene emissions; and the maximum off-site acute HQ value could be as high as 5, based on the REL value for benzene. The total estimated cancer incidence from these facilities based on actual emission levels is 0.001 excess cancer cases per year, or 1 in every 1000 years.
	As explained above, our analysis of potential differences between actual emission levels and emissions allowable under the natural gas transmission and storage MACT standard indicate that MACT-allowable emission levels may be up to 50 times greater than actual emission levels at some sources. Even considering this difference, the risk results from the inhalation risk assessment indicate the maximum lifetime individual cancer risk would still be 90-in-1 million, and the maximum chronic noncancer TOSHI value could be as high as 0.8 at the MACT-allowable emissions level.
ii. Facility-wide Risk Assessment Results
	A facility-wide risk analysis was also conducted based on actual emissions levels. Table 6 displays the results of the facility-wide risk assessment. For detailed facility-specific results, see Table 2 of Appendix 6 of the risk document in the docket for this rulemaking.
TABLE 6. NATURAL GAS TRANSMISSION AND STORAGE FACILITY-WIDE RISK ASSESSMENT RESULTS
Number of facilities analyzed
                                      321
Cancer Risk
Estimated maximum facility-wide individual cancer risk (in 1 million)
                                      200

Number of facilities with estimated facility-wide individual cancer risk of 100-in-1 million or more
                                       3

Number of facilities at which the Natural Gas Transmission and Storage source category contributes 50 percent or more to the facility-wide individual cancer risks of 100-in-1 million or more
                                       1

Number of facilities with facility-wide individual cancer risk of 1-in-1 million or more
                                      74

Number of facilities at which the Natural Gas Transmission and Storage source category contributes 50 percent or more to the facility-wide individual cancer risk of 1-in-1 million or more
                                      10
Chronic Noncancer Risk
Maximum facility-wide chronic noncancer TOSHI
                                      80

Number of facilities with facility-wide maximum noncancer TOSHI greater than 1
                                      30

Number of facilities at which the Natural Gas Transmission and Storage source category contributes 50 percent or more to the facility-wide maximum noncancer TOSHI of 1 or more
                                       0

	The MIR from all HAP emissions at any facility that contains sources subject to the natural gas transmission and storage MACT standards is estimated to be 200-in-1 million based on actual emissions. Of the 321 facilities included in this analysis, three have facility-wide MIRs of 100-in-1 million or greater. The facility-wide MIRs are 200-in-1 million at two of these facilities, driven by formaldehyde from RICE. Another facility has a facility-wide risk of 100-in-1-million, with 90 percent of the risk attributed to natural gas transmission and storage. There are 74 facilities with facility-wide MIRs of 1-in-1 million or greater. Of these facilities, 10 have natural gas transmission and storage operations that contribute greater than 50 percent to the facility-wide risks. The facility-wide cancer risks at the facilities with risks of 1-in-a million or more are primarily driven by formaldehyde emissions from RICE which will be assessed in a future RTR for that category.
	The facility-wide maximum individual chronic noncancer TOSHI is estimated to be 80 based on actual emissions. Of the 321 facilities included in this analysis, 30 have facility-wide maximum chronic noncancer TOSHI values greater than 1. Of these facilities, none had natural gas transmission and storage operations that contributed greater than 50 percent to these facility-wide risks. The chronic noncancer risks at these facilities are primarily driven by acrolein emissions from RICE.
iii.	Demographic Risk Analysis Results
	The results of the demographic analyses performed to investigate the distribution of cancer risks at or above 1-in-1 million among the surrounding population are summarized in Table 7 below. These results, for various demographic groups, are based on actual emissions levels for the population living within 50 km of the facilities.
TABLE 7. NATURAL GAS TRANSMISSION AND STORAGE DEMOGRAPHIC RISK ANALYSIS RESULTS

                                  Nationwide
      Population with cancer risk at or above 1 in a million due to....

                         Source Category HAP emissions
                          Facility-wide HAP emissions
Total population
                                  285,000,000
                                     2,500
                                    99,000
                                Race by percent
White
                                      75
                                      92
                                      58
All Other Races
                                      25
                                       8
                                      42
                                Race by percent
White
                                      75
                                      92
                                      58
African American
                                      12
                                       6
                                      40
Native American
                                      0.9
                                      0.1
                                      0.2
Other and Multiracial
                                      12
                                       1
                                       2
                             Ethnicity by percent
Hispanic
                                      14
                                       1
                                       2
Non-Hispanic
                                      86
                                      99
                                      98
                               Income by percent
Below poverty level
                                      13
                                      17
                                      20
Above poverty level
                                      87
                                      83
                                      80
                             Education by percent
Over 25 and without high school diploma
                                      13
                                      20
                                      15
Over 25 and with a high school diploma
                                      87
                                      80
                                      85

	The results of the Natural Gas Transmission and Storage source category demographic analysis indicate that there are approximately 2,500 people exposed to a cancer risk at or above 1-in-1 million due to emissions from the source category, including an estimated 8 percent that are classified as minority (listed as "All Other Races" in the table above). Of the 2,500 people with estimated cancer risks at or above 1-in-1-million from the source category, 17 percent are in the "Below poverty level" demographic group, and 20 percent are in the "Over 25 and without high school diploma" demographic group, results which are 4 and 7 percentage points higher, respectively, than the percentages for these demographic groups across the United States. The percentages for the other demographic groups are lower than their respective nationwide percentages. The table also shows that there are approximately 99,000 people exposed to an estimated cancer risk at or above 1-in-1 million due to facility-wide emissions, including an estimated 42 percent that are classified as minority ("All Other Races" in the table above). Of the 99,000 people with estimated cancer risk at or above 1-in-1 million from facility-wide emissions, 40 percent are in the "African American" demographic group, 20 percent are in the "Below poverty level" demographic group, and 15 percent are in the "Over 25 and without high school diploma" demographic group, results which are 28, 7 and 2 percentage points higher, respectively, than the percentages for these demographic groups across the United States. The percentages for the other demographic groups are equal to or lower than their respective nationwide percentages.
b. What are the proposed risk decisions for the Natural Gas Transmission and Storage source category?
i. Risk Acceptability
	The Agency considered the available health information -- the MIR; the numbers of persons in various risk ranges; cancer incidence; the maximum non-cancer hazard index (HI); the maximum acute non-cancer hazard; the extent of non-cancer risks; the potential for adverse environmental effects; and distribution of risks in the exposed population; and risk estimation uncertainty (54 FR 38044, September 14, 1989)  -  in developing the proposed CAA section 112(f)(2) standards for this source category.
      For the Natural Gas Transmission and Storage source category, the risk analysis we performed indicates that the cancer risks to the individual most exposed could be as high as 90-in-1 million due to actual and allowable emissions. These risks are near 100-in-1 million, which is the presumptive limit of acceptability. The risk analysis shows low cancer incidence (1 case in every 1000 years), low potential for adverse environmental effects or human health multi-pathway effects, and that chronic and acute noncancer health impacts are unlikely. We conclude that acute noncancer health impacts are unlikely for reasons similar to those described in section VII.C.2.b.i of this preamble.
      While our additional analysis of facility-wide risks showed that there are three facilities with maximum facility-wide cancer risk of 100-in-1 million or greater and 30 facilities with a maximum chronic noncancer TOSHI greater than 1, it also showed that natural gas transmission and storage operations did not drive these risks except in one case where the facility-wide cancer risk was 100-in-1 million.
      In determining whether risk is acceptable, we focus on the results of all aspects of the risk assessment. In this case, although a number of factors we considered indicate little risk concern, we are proposing to determine that the risks are unacceptable in large part because the MIR based on both actual and MACT allowable emissions are near 100-in-1 million, which is the "presumptive limit on maximum individual lifetime risk of approximately 1-in-10 thousand [100-in-1-million] recognized in the Benzene NESHAP (54 FR 38045)." The MIR is driven by the allowable emissions of 1 tpy benzene under the MACT as a compliance option. To lower this risk to the acceptable level, we are proposing to eliminate the alternative compliance option of 0.9 Mg benzene from the existing glycol dehydrator MACT requirements. We are therefore proposing to eliminate the alternative compliance option of 1 tpy benzene from the existing glycol dehydrator MACT requirements. With this change, the MIR would be 20-in-1 million, which we find acceptable in light of all the other factors considered. Thus, we are proposing that the risks from the Natural Gas Transmission and Storage source category are acceptable, with the removal of the alternative compliance option of 0.9 Mg/yr benzene limit from the current glycol dehydrator MACT requirements.
ii. Ample Margin of Safety
	We next considered whether this revised standard (existing MACT plus removal of 0.9 Mg/yr benzene compliance option) provides an ample margin of safety. In this analysis, we investigated available emissions control options that might reduce the risk associated with emissions from the source category and considered this information along with all of the health risks and other health information considered in the risk acceptability determination. One option we considered was requiring additional controls on glycol dehydrators. This would require adding a second control device as discussed in the above the floor evaluation in section VII.B.1 of this preamble. The cost effectiveness associated with that option would be $33,000/Mg which we believe is too high to require additional controls on glycol dehydrators.
      In accordance with the approach established in the Benzene NESHAP, the EPA weighed all health risk measures and information considered in the risk acceptability determination, along with the costs and economic impacts of emissions controls, technological feasibility, uncertainties, and other relevant factors, in making our ample margin of safety determination. Considering the health risk information and the high cost effectiveness of the option identified, we propose that the existing MACT standards, with the removal of the 0.9 Mg benzene limit compliance option from the glycol dehydrator standards, provide an ample margin of safety to protect public health.
While we are proposing, as described above, that the emissions covered by the natural gas transmission and storage MACT standards provide an ample margin of safety to protect public health, we are concerned about the estimated facility-wide risks identified through these screening analyses. As described previously, the estimated cancer risks are due to emissions of benzene from glycol dehydrators and formaldehyde from RICE. As stated above, we are proposing to require controls on small dehydrators that we believe will reduce risk to exposed populations from benzene. Emissions from RICE are regulated under another source category and will be assessed under a future RTR for that category.
D. How did we perform the technology review and what are the results and proposed decisions?
1. What was the methodology for the technology review?
	Our technology review is focused on the identification and evaluation of "developments in practices, processes, and control technologies" since the promulgation of the MACT standards for the two oil and gas source categories. If a review of available information identifies such developments, then we conduct an analysis of the technical feasibility of requiring the implementation of these developments, along with the impacts (costs, emission reductions, risk reductions, etc.). We then make a decision on whether it is necessary to amend the regulation to require these developments.
      Based on specific knowledge of each source category, we began by identifying known developments in practices, processes, and control technologies. For the purpose of this exercise, we considered any of the following to be a "development":
::	Any add-on control technology or other equipment that was not identified and considered during MACT development;
::	Any improvements in add-on control technology or other equipment (that was identified and considered during MACT development) that could result in significant additional emission reduction;
::	Any work practice or operational procedure that was not identified and considered during MACT development; and
::	Any process change or pollution prevention alternative that could be broadly applied that was not identified and considered during MACT development.
      In addition to looking back at practices, processes, or control technologies reviewed at the time we developed the MACT standards, we reviewed a variety of sources of data to aid in our evaluation of whether there were additional practices, processes, or controls to consider. One of these sources of data was subsequent air toxics rules. Since the promulgation of the MACT standards for the source categories addressed in this proposal, the EPA has developed air toxics regulations for a number of additional source categories. We reviewed the regulatory requirements and/or technical analyses associated with these subsequent regulatory actions to identify any practices, processes, and control technologies considered in these efforts that could possibly be applied to emission sources in the source categories under this current RTR review.
      We also consulted the EPA's RBLC. The terms "RACT," "BACT," and "LAER" are acronyms for different program requirements under the CAA provisions addressing the NAAQS. Control technologies classified as RACT, BACT, or LAER apply to stationary sources depending on whether the source exists or is new, and on the size, age, and location of the facility. The BACT and LAER (and sometimes RACT) are determined on a case-by-case basis, usually by state or local permitting agencies. The EPA established the RBLC to provide a central database of air pollution technology information (including technologies required in source-specific permits) to promote the sharing of information among permitting agencies and to aid in identifying future possible control technology options that might apply broadly to numerous sources within a category or apply only on a source-by-source basis. The RBLC contains over 5,000 air pollution control permit determinations that can help identify appropriate technologies to mitigate many air pollutant emission streams. We searched this database to determine whether any practices, processes, or control technologies are included for the types of processes used for emission sources (e.g., spray booths) in the source categories under consideration in this proposal.
	We also consulted information from the Natural Gas STAR program. The Natural Gas STAR Program is a flexible, voluntary partnership that encourages oil and natural gas companies to adopt cost effective technologies and practices that improve operational efficiency and reduce pollutant emissions. The program provides the oil and gas industry with information on new techniques and developments to reduce pollutant emissions from the various processes.
2. What are the results and proposed decisions from the technology review?
	There are three types of emission sources covered by the two oil and gas NESHAP. These sources, and the control technologies (including add-on control devices and process modifications) considered during the development of the MACT standards, are: Glycol dehydrators (combustion devices, recovery devices, process modifications), storage vessels with the potential for flash emissions (combustion devices, recovery devices) and equipment leaks (LDAR programs, specific equipment modifications). Dehydrators are addressed by both subparts HH and HHH, while equipment leaks and storage vessels with the potential for flash emissions are only covered by subpart HH.
	Since the promulgation of subpart HH, the EPA has developed LDAR programs that are more stringent than what is required in subpart HH. The most prevalent differences between these more recent rules and subpart HH are related to the frequency of monitoring and the concentration which constitutes a "leak." We do consider this situation to represent a development in practices, and evaluated whether this more stringent program should be proposed for HAP equipment leaks at natural gas processing plants.
	An analysis was performed above in VI.B.1. to assess the impacts associated with different LDAR program options at natural gas processing plants. One option considered is to require compliance with 40 CFR part 60 subpart VVa instead of VV, which changes the leak definition from 10,000 ppm VOHAP to 500 ppm. The estimated incremental cost for that option was determined to be $3,340 per ton of VOC. At gas processing plants, the ratio of VOC to HAP is approximately 20-to-1. This means the incremental cost to control HAP would be approximately $66,800 per ton ($73,480/Mg) of HAP. A second option considered in VI.B.1. was requiring compliance with subpart VVa with the optical imaging camera. The cost effectiveness for that option was determined to be $4,330 per ton of VOC which translates to $86,600 per ton ($95,260/Mg) of HAP. We believe that the additional costs for the more stringent programs are not justified. Therefore, we are not proposing any revisions to the equipment leak requirements in subpart HH as a result of our technology review.
	Some of the practices, processes, or control technologies listed by the Natural Gas STAR program applicable to the emission sources in these categories were not identified and evaluated during the original MACT development. While the Natural Gas STAR program does contain information regarding new innovative techniques that are available to reduce HAP emissions, they are not considered to have emission reductions higher than what is set by the original MACT. One control technology identified in the Natural Gas STAR program that would result in no HAP emissions from glycol dehydration units would be the replacement of a glycol dehydration unit with a desiccant dehydrator. This technology cannot be used for natural gas operations with gas streams having high temperature, high volume, and low pressure. Due to the limitations posed by these conditions we do not consider dessicant dehydrators as MACT.
      For storage vessels and ancillary equipment, the applicable technologies identified by the Gas STAR program would not result in any further emissions reductions than what is achieved by the original MACT.
      Our review of the RBLC did not identify any practices, processes, and control technologies applicable to the emission sources in these categories that were not identified and evaluated during the original MACT development. In light of the above, we are not proposing any revisions to the existing MACT standards pursuant to section 112(d)(6) of the CAA.
E. What other actions are we proposing?
1. Combustion Control Device Testing
	As explained below in VII.E.2, under our proposal, performance testing would be required initially and every 5 years and for a non-flare combustion control device.  As an alternative to on-site performance testing for combustion control devices, we are proposing to accept a performance test conducted by the control device manufacturer, accordance with the procedures provided in this proposal, to demonstrate that a model of control device can meet the proposed performance criteria.  Following a successful test, a control device matching the tested model could be installed at a facility with no further testing requirements for five years. For the NESHAP, we would allow a unit whose model passes the test conducted by the manufacturer to claim a BTEX or HAP destruction efficiency of 98 percent at the facility. This value is lower than the 99.9 percent destruction efficiency required in the manufacturers' test due to variations between the test fuel specified and the gas streams combusted at the actual  facility.
	We are proposing this alternative to reduce the cost burden associated with performance testing of combustion devices at each site and also eliminate our concerns with conducting valid tests in remote locations. This proposed alternative does not apply to flares, which must demonstrate compliance by meeting the design and operation requirements in 40 CFR 63.11(b) and in 40 CFR 63.772(e)(2)(i).
and certain thermal oxidizers (i.e., those having a combustion chamber/firebox where combustion temperature and residence time can be measured during an on-site performance test and are valid indicators of performance).
	In addition, we are proposing a definition for flare to clarify our intent that flares, as referenced in the NESHAP, means oxidation with an open flame (i.e., without enclosure). In conjunction with this change, we are clarifying that combustion control device includes enclosed flares. Our experience with thermal oxidizers with combustion chambers/fireboxes has shown that the required combustion zone temperature and residence time can be sufficiently established during on-site performance testing, negating the need for a manufacturers' test, and having existing performance test provisions apply instead.
	We estimate that there are many existing facilities currently using combustion control devices that will be required to either conduct an on-site performance test or install and operate a control device tested by the manufacturer. Given the estimated number of non-flare, combustion control devices in use, the time required for manufacturers to test and manufacture such units, we are proposing that existing sources have up to 3 years from the date of the final rules' publication date to comply with the testing requirements.
2. Monitoring, Recordkeeping and Reporting
	We are proposing to make changes to the monitoring requirements described below to address issues we have identified through a monitoring sufficiency review performed during the RTR process. First, we are including calibration procedures associated with parametric monitoring requirements in the existing NESHAP. The NESHAP require parametric monitoring of control device parameters (e.g., temperatures or flowrate monitoring) but did not include information on calibration or included inadequate information on calibration of monitoring devices. Therefore, we are specifying the calibration requirements for temperature and flow monitors that the NESHAP currently lacks.
	In addition, under the current NESHAP, a design analysis can be used in lieu of performance testing to demonstrate compliance and establish operating parameter limits. We are proposing to allow the use of design evaluation alternative only when the control device being used is a condenser. The design evaluation option is appropriate for condensers because their emissions are accurately predicted using readily available physical property information (e.g., vapor pressure data and condensation calculations). In most cases, one may not even need to conduct emissions testing to determine actual emissions using such data for the compounds of interest. For example, a requirement that "the temperature at the outlet of the condenser shall be maintained a 50[o]F below the condensation temperature calculated for the compound of interest using the reference equation" (e.g., NIST Chemistry WebBook at http://webbook.nist.gov/chemistry/) is adequate to assure proper operation of the condenser and therefore compliance with the required emission standard.
	For other types of control technologies such as carbon adsorption systems and combustion devices, the ability to predict emissions depends on data developed by the vendor and such data may not reliably result in an accurate prediction of emissions from a specific facility. There are variables (e.g., A/F ratios and waste constituents for combustion; varying organic concentrations, constituents, and capacity issues including break-through for carbon adsorption) that make theoretical predictions less reliable. The effects of these site-specific variables on emissions are not easily predictable and establishing monitoring conditions (e.g., combustion temperature, vacuum regeneration) based on vendor data will likely not account for those variables. Therefore, the proposed amendments eliminate the design evaluation alternative for non-condenser controls.
	For non-condenser controls (and condensers not using the design analysis option), in addition to the initial compliance testing, we are proposing that performance tests be conducted at least once every 5 years and whenever sources desire to establish new operating limits. Under the current NESHAP, a performance test is only conducted in two instances: (1) As an alternative to a design analysis for their compliance demonstration and identification of operating parameter ranges and (2) as a requirement to resolve a disagreement between the EPA and the owner or operator regarding the design analysis. The NESHAP do not require additional performance testing beyond these two cases (i.e., there is no periodic testing requirement). As mentioned above, we are proposing to remove the design evaluation option for non-condenser controls. For non-condenser controls (and condensers not using the design analysis option), the proposed periodic testing would ensure compliance with the emission standards by verifying that the control device is meeting the necessary HAP destruction efficiency determined in the initial performance test.
	The current NESHAP (40 CFR 63.771(d) and 40 CFR 63.1281(d)) require operating an enclosed combustion device at a minimum residence time of 0.5 seconds at a minimum temperature of 760 degrees C. We are proposing to remove the residence time requirement. The residence time requirement is not needed, because the compliance demonstration made during the performance test is sufficient to ensure that the combustion device has adequate residence time to ensure the needed destruction efficiency. Therefore, we are proposing to remove the residence time requirement.
	We are also clarifying at 40 CFR 63.773(d)(3)(i) and 40 CFR 63.1283(d)(3)(i) for thermal vapor incinerators, boilers and process heaters, that the temperature sensor shall be installed at a location representative of the combustion zone temperature. Currently, the regulation requires that the temperature sensor be installed at a location "downstream of the combustion zone" because we had thought that the temperature downstream would be representative of combustion zone temperature. We have now learned that may or may not be the case. We are therefore proposing to amend this provision to more accurately reflect the intended requirement.
	Next, consistent with revisions for SSM, we've revised 40 CFR 63.771(d)(4)(i) and 40 CFR 63.1281(d)(4)(i), except when maintenance or repair on a unit cannot be completed without a shutdown of the control device.
	Also, we've updated the criteria for prior performance test results that can be used to demonstrate compliance in lieu of conducting a performance test. These updates ensure that data for determining compliance are accurate, up-to-date, and truly representative of actual operating conditions.
	In addition, we are proposing to revise the temperature monitoring device minimum accuracy criteria in 40 CFR 63.773(d)(3)(i) to better reflect the level of performance that is required of the temperature monitoring devices. We believe that temperature monitoring devices currently used to meet the requirements of the NESHAP can meet the proposed revised criteria without modification.
	Also, we are proposing to revise the calibration gas concentration for the no detectable emissions procedure applicable to closed vent systems in 40 CFR 63.772(c)(4)(ii) from 10,000 ppmv to 500 ppmv methane to be consistent with the leak threshold of 500 ppmv in 40 CFR part 63, subpart HH. The current calibration level is inconsistent with achieving accurate readings at the level necessary to demonstrate there are no detectable emissions.
	Also, we are proposing recordkeeping and reporting requirements for carbon adsorption systems. The current NESHAP require the replacement of all carbon in the carbon adsorption system with fresh carbon on a regular, predetermined time interval that is no longer than the carbon service life established for the carbon system but provide no recordkeeping or reporting requirement to document and assure compliance with this standard. We believe that maintaining some sort of log book is a reasonable alternative combined with a requirement to report instances when specified practices are not followed. Therefore, the proposed rule adds reporting and recordkeeping requirements for establishing a schedule and maintaining logs of carbon replacement.
	Finally, as noted above in section VII.B.1., we are proposing a BTEX emissions limit for small glycol dehydration unit process vents. For the compliance demonstration, we propose that parametric monitoring of the control device be performed. We believe that parametric monitoring is adequate for glycol dehydrators in these two source categories because temperature monitoring, whether it be to verify proper condenser or combustion device operation, is a reliable indicator of performance for reducing organic HAP emissions. We also considered the use of a CEMS to monitor compliance. However, for glycol dehydrators in the oil and natural gas sector the necessary electricity, weather-protective enclosures and daily staffing are not usually available. We therefore question the technical feasibility of operating a CEMS correctly in this sector. We request comment on the practicality of including provisions in the final rule for a CEMS to monitor BTEX emissions for small glycol dehydration units.
3. Startup, Shutdown Malfunction
	The United States Court of Appeals for the District of Columbia Circuit vacated portions of two provisions in the EPA's CAA section 112 regulations governing the emissions of HAP during periods of SSM. Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), cert. denied, 130 S. Ct. 1735 (U.S. 2010). Specifically, the Court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), that is part of a regulation, commonly referred to as the General Provisions Rule, that the EPA promulgated under section 112 of the CAA. When incorporated into CAA section 112(d) regulations for specific source categories, these two provisions exempt sources from the requirement to comply with the otherwise applicable CAA section 112(d) emission standard during periods of SSM.
      We are proposing the elimination of the SSM exemption in the two oil and gas NESHAP. Consistent with Sierra Club v. EPA, the EPA is proposing to apply the standards in these NESHAP at all times. We are also proposing several revisions to the General Provisions Applicability table for the MACT standard. For example, we are proposing to eliminate the incorporation of the General Provisions' requirement that the source develop a SSM plan. We are also proposing to eliminate or revise certain recordkeeping and reporting requirements related to the SSM exemption. The EPA has attempted to ensure that we have not included in the proposed regulatory language any provisions that are inappropriate, unnecessary, or redundant in the absence of the SSM exemption. We are specifically seeking comment on whether there are any such provisions that we have inadvertently incorporated or overlooked.
      In proposing the standards in these rules, the EPA has taken into account startup and shutdown periods. We believe that, operations and emissions do not differ from normal operations during these periods such that it warrants a separate standard.  Therefore we have not proposed different standards for these periods.
      Periods of startup, normal operations and shutdown are all predictable and routine aspects of a source's operations. However, by contrast, malfunction is defined as a "sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner * * * " (40 CFR 63.2). The EPA has determined that malfunctions should not be viewed as a distinct operating mode and, therefore, any emissions that occur at such times do not need to be factored into development of CAA section 112(d) standards, which, once promulgated, apply at all times. In Mossville Environmental Action Now v. EPA, 370 F.3d 1232, 1242 (D.C. Cir. 2004), the Court upheld as reasonable standards that had factored in variability of emissions under all operating conditions. However, nothing in CAA section 112(d) or in case law requires that the EPA anticipate and account for the innumerable types of potential malfunction events in setting emission standards. See Weyerhaeuser v. Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978), ("In the nature of things, no general limit, individual permit, or even any upset provision can anticipate all upset situations. After a certain point, the transgression of regulatory limits caused by "uncontrollable acts of third parties," such as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter for the administrative exercise of case-by-case enforcement discretion, not for specification in advance by regulation.").
      Further, it is reasonable to interpret CAA section 112(d) as not requiring the EPA to account for malfunctions in setting emissions standards. For example, we note that CAA section 112 uses the concept of "best performing" sources in defining MACT, the level of stringency that major source standards must meet. Applying the concept of "best performing" to a source that is malfunctioning presents significant difficulties. The goal of best performing sources is to operate in such a way as to avoid malfunctions of their units.
      Moreover, even if malfunctions were considered a distinct operating mode, we believe it would be impracticable to take malfunctions into account in setting CAA section 112(d) standards for oil and natural gas production facility and natural gas transmission and storage operations. As noted above, by definition, malfunctions are sudden and unexpected events, and it would be difficult to set a standard that takes into account the myriad different types of malfunctions that can occur across all sources in each source category. Moreover, malfunctions can also vary in frequency, degree, and duration, further complicating standard setting.
      In the event that a source fails to comply with the applicable CAA section 112(d) standards as a result of a malfunction event, the EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. The EPA would also consider whether the source's failure to comply with the CAA section 112(d) standard was, in fact, "sudden, infrequent, not reasonably preventable" and was not instead "caused in part by poor maintenance or careless operation." 40 CFR 63.2 (definition of malfunction).
      Finally, the EPA recognizes that even equipment that is properly designed and maintained can sometimes fail and that such failure can sometimes cause or contribute to an exceedance of the relevant emission standard. (See, e.g., State Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, Startup, and Shutdown (September 20, 1999); Policy on Excess Emissions During Startup, Shutdown, Maintenance, and Malfunctions (February 15, 1983)). The EPA is, therefore, proposing to add to the final rule an affirmative defense to civil penalties for exceedances of emission limits that are caused by malfunctions in both of the MACT standards addressed in this proposal. See 40 CFR 63.761 for sources subject to the oil and natural gas production MACT standards, or 40 CFR 63.1271 for sources subject to the natural gas transmission and storage MACT standards (defining "affirmative defense" to mean, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding). We also are proposing other regulatory provisions to specify the elements that are necessary to establish this affirmative defense; a source subject to the oil and natural gas production facilities or natural gas transmission MACT standards must prove by a preponderance of the evidence that it has met all of the elements set forth in 40 CFR 63.762, and a source subject to the natural gas transmission and storage facilities MACT standards must prove by a preponderance of the evidence that it has met all of the elements set forth in 40 CFR 63.1272. (See 40 CFR 22.24.)  The criteria ensure that the affirmative defense is available only where the event that causes an exceedance of the emission limit meets the narrow definition of malfunction in 40 CFR 63.2 (sudden, infrequent, not reasonably preventable and not caused by poor maintenance and or careless operation). For example to successfully assert the affirmative defense, the source must prove by a preponderance of evidence that excess emissions "[w]ere caused by a sudden, infrequent, and unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual manner ...." The criteria also are designed to ensure that steps are taken to correct the malfunction, to minimize emissions in accordance with 40 CFR 63.762 for sources subject to the oil and natural gas production facilities MACT standards, or 40 CFR 63.1272 for sources subject to the natural gas transmission and storage facilities MACT standards, and to prevent future malfunctions. For example the source must prove by a preponderance of evidence that "[r]epairs were made as expeditiously as possible when the applicable emission limitations were being exceeded..." and that "[a]ll possible steps were taken to minimize the impact of the excess emissions on ambient air quality, the environment and human health...." In any judicial or administrative proceeding, the Administrator may challenge the assertion of the affirmative defense and, if the respondent has not met its burden of proving all of the requirements in the affirmative defense, appropriate penalties may be assessed in accordance with section 113 of the CAA (see also 40 CFR 22.77).
4. Applicability and Compliance
a. Calculating PTE
	We are proposing to amend section 40 CFR 63.760(a)(1)(iii) to clarify that sources must use a glycol circulation rate consistent with the definition of PTE in 40 CFR 63.2. Affected parties have misinterpreted the current language concerning measured values or annual average to apply to a broader range of parameters than was intended.  Those qualifiers were meant to apply to gas characterics that are measured such as inlet gas composition, pressure and temperature rather than process equipment settings. That means that the circulation rate used in PTE determinations shall be the maximum under its physical and operational design.
	In addition to the proposed changes described above, we are seeking comment on several PTE related issues. According to the data available to the Administrator when subpart HH was promulgated, the level of HAP emissions was predominantly driven by natural gas throughput (i.e., HAP emissions went up or down in concert with natural gas throughput). Since promulgation, we have learned that there is not always a direct correlation between HAP emissions and natural gas throughput. We have received information suggesting that in some cases HAP emissions can increase despite decreasing natural gas throughput due to changes in gas composition. We are asking for comment regarding the likelihood of this occurrence and data demonstrating the circumstances where it occurs. We are asking for comment regarding the addition of provisions in the NESHAP to require area sources to recalculate their PTE to confirm that they are indeed area sources, and whether that calculation should be performed on an annual or biannual basis, to verify that changes in gas composition have not increased their emissions.
b. Definition of Facility
      Subpart HH (section 63.760(a)(2)) currently defines facilities as those where hydrocarbon liquids are processed, upgraded or stored prior to the point of custody transfer, or prior to entering the Natural Gas Transmission and Storage source category. We are proposing to remove the reference to "point of custody transfer" and "transmission and storage source categories." Further, since hydrocarbon liquids can pass through several custody transfer points between the well and its final destination, it is not clear which custody transfer point applies in this definition. We are therefore proposing to replace the reference to "point of custody transfer" and "transmission and storage source categories" with a more specific description of the point up to which the subpart applies (i.e., the point where hydrocarbon liquids enter either the organic liquids distribution or petroleum refineries source categories) and excluding custody transfer from that criteria. We believe this language eliminates ambiguity and is consistent with the oil and natural gas production-specific provisions in the organic liquids distribution MACT.
5. Other Proposed Changes to Clarify These Rules
      The following lists additional changes to the NESHAP we are proposing. This list includes proposed rule changes that address editorial corrections and plain language revisions:
   * Revise §63.769(b) to clarify that the equipment leak provisions in subpart HH do not apply to a source if that source is required to control equipment leaks under either 40 CFR part 63, subpart H or part 60 Subpart KKK. The current 63.769(b), which states that subpart HH does not apply if a source meets the requirements in either of the subparts mentioned above, does not clearly express our intent that such source must be implementing the LDAR provisions in the other part 60 or 63 subparts to qualify for the exemption.
   * Revise §63.760(a)(1) to clarify cases where an existing area source increases its emissions to major source levels (i.e., that it has up to the first substantive compliance date to either reduce its emissions below major source levels by obtaining a practically enforceable permit or comply with the applicable major source provisions of subpart HH). We have revised the second to last sentence in 63.760(a)(1) by removing the parenthetical statement because it is redundant with the last sentence of this section, and therefore unnecessary.
   * Revise §63.771(d)(1)(ii) and §63.1281(d)(1)(ii) to clarify that the intent of this section, specific to vapor recovery devices, refers to non-destructive control devices only.
   * Revise the last sentence of §63.764(i) and §63.1274(g) to clarify the requirements following an unsuccessful attempt to repair a leak.
   * Updated the email and physical address for area source reporting in §63.775(c)(1).

VIII. What are the cost, environmental, energy, and economic impacts of the proposed subpart OOOO and amendments to subparts HH and HHH?
	We are presenting a combined discussion of the estimates of the impacts for the proposed 40 CFR part 60 subpart OOOO and proposed amendments to 40 CFR part 63, subparts HH and HHH. The cost, environmental, and economic impacts presented in this section are expressed as incremental differences between the impacts of an oil and natural gas facility complying with the amendments to 40 CFR 63 subpart HH and HHH, and new standards under 40 CFR 60 subpart OOOO and the baseline, i.e., the standards before these amendments. The impacts are presented for the year 2015, which will be the year that all existing oil and natural gas facilities will have to be in compliance, and also the year that will represent approximately 5 years of construction of new oil and natural gas facilities subject to the NSPS emissions limits. The analyses and the documents referenced below can be found in Docket ID Numbers EPA-HQ-OAR-2007-0877 and EPA-HQ-OAR-2002-0051.
A. What are the affected sources?
	We expect that by 2015, the year when all existing sources will be required to come into compliance, in the United States, there will be 97 oil and natural gas production facilities and 15 natural gas transmission and storage facilities with one or more existing glycol dehydration units. We also estimate that there will be an additional 329 (there are 47 facilities that already have an affected glycol dehydration unit) existing oil and natural gas production facilities with existing storage vessels that we expect to be affected by these final amendments. These facilities operate approximately 134 glycol dehydration units (115 in production and 19 in transmission and storage) and 1,970 storage vessels. Approximately 10 oil and natural gas production and two transmission and storage facilities would have new glycol dehydration units, and 38 production facilities would have new dehydration units. We expect new production facilities would operate approximately 12 production glycol dehydration units and 197 storage vessels, and new transmission and storage would operate approximately two glycol dehydration units.
	Based on data provided by the U.S. Energy Information Administration, we anticipate that by 2015 there will be approximately 21,800 gas wellhead facilities, 790 reciprocating compressors, 30 centrifugal compressors, 14,000 pneumatic devices, and 300 storage vessels subject to the new NSPS for VOC. Some of these affected facilities will be built at existing facilities and some at new greenfield facilities. Based on data limitations, we assume impacts are equal regardless of location.
	There are about 21 glycol dehydration units with high enough HAP emissions that we believe cannot meet the emissions limit without using more than one control technique. In developing the cost impacts, we assume that they would require multiple controls. The controls for which we have detailed cost data are condensers and VRUs, so we developed costs for both controls to develop what we consider to be a reasonable cost estimate for these facilities. This does not imply that we believe these facilities will specifically use a combination of a condenser and vapor recovery to limit, but we do believe the combination of these control results in a reasonable estimate of cost.
B. How are the impacts for this proposal evaluated?
	For these proposed oil and natural gas production and natural gas transmission and storage NESHAP amendments and NSPS, the EPA used two models to evaluate the impacts of the regulation on the industry and the economy. Typically in a regulatory analysis, the EPA determines the regulatory options suitable to meet statutory obligations under the CAA. Based on the stringency of those options, the EPA then determines the control technologies and monitoring requirements that sources might rationally select to comply with the regulation. This analysis is documented in an engineering analysis. The selected control technologies and monitoring requirements are then evaluated in a cost model to determine the total annualized control costs. The annualized control costs serve as inputs to an Economic Impact Analysis model that evaluates the impacts of those costs on the industry and society as a whole.
	The Economic Impact Analysis used the National Energy Modeling System (NEMS) to estimate the impacts of the proposed NSPS on the United States energy system. The NEMS is a publically-available model of the United States energy economy developed and maintained by the Energy Information Administration of the U.S. DOE and is used to produce the Annual Energy Outlook, a reference publication that provides detailed forecasts of the energy economy from the current year to 2035. The impacts we estimated included changes in drilling activity, price and quantity changes in the production and consumption of crude oil and natural gas, and changes in international trade of crude oil and natural gas. We evaluated whether and to what extent the increased production costs imposed by the NSPS might alter the mix of fuels consumed at a national level. We additionally combined estimated emissions co-reductions of methane from the engineering analysis with NEMS analysis to estimate the net change in CO2-equivalent greenhouse gas emissions from energy-related sources.
C. What are the air quality impacts?
	For the oil and natural gas sector NESHAP and NSPS, we estimated the emission reductions that will occur due to the implementation of the final emission limits. The EPA estimated emission reductions based on the control technologies selected by the engineering analysis. These emission reductions associated with the proposed amendments to subparts HH and HHH are based on the estimated population in 2008. Under the proposed limits for glycol dehydration units and storage vessels, we have estimated that the HAP emissions reductions will be almost 1,300 tpy for existing units subject to the proposed emissions limits.
	For the NSPS, we estimated the emission reductions that will occur due to the implementation of the final emission limits. The EPA estimated emission reductions based on the control technologies selected by the engineering analysis. These emission reductions are based on the estimated population in 2015. Under the proposed NSPS, we have estimated that the emissions reductions will be close to 970 thousand tpy VOC for affected facilities subject to the new source performance standards.
	The control strategies likely adopted to meet the proposed NESHAP amendments and the proposed NSPS will result in concurrent control of HAP, methane, and VOC emissions. We estimate that reductions in HAP, methane, and VOC total about 38,000 tpy, close to 3.4 million tpy, and 980,000 tpy, respectively.
	Under the final standards, new monitoring requirements are being added.
D. What are the water quality and solid waste impacts?
	We estimated minimal water quality impacts for the proposed amendments and proposed NSPS. For the proposed amendments to the NESHAP, we anticipate that the water impacts associated with the installation of a condenser system for the glycol dehydration unit process vent would be minimal. This is because the condensed water collected with the hydrocarbon condensate can be directed back into the system for reprocessing with the hydrocarbon condensate or, if separated, combined with produced water for disposal usually by reinjection.
	Similarly, the water impacts associated with installation of a vapor control system either on a glycol dehydration unit or a storage vessel would be minimal. This is because the water vapor collected along with the hydrocarbon vapors in the vapor collection and redirect system can be directed back into the system for reprocessing with the hydrocarbon condensate or, if separated, combined with the produced water for disposal for reinjection.
	There would be no water impacts expected for facilities subject to the proposed NSPS. Further, we do not anticipate any adverse solid waste impacts from the implementation of the proposed NESHAP amendments and the proposed NSPS.
E. What are the secondary impacts?
	Indirect or secondary air quality impacts include impacts that will result from the increased electricity usage associated with the operation of control devices, as well as water quality and solid waste impacts (which were just discussed) that might occur as a result of these proposed actions. We estimate the proposed amendments to subparts HH and HHH will increase emissions of criteria pollutants due to the potential use of flares for the control of storage vessels. We do not estimate an increased energy demand associated with the installation of condensers, VRUs, or flares. The increases in criteria pollutant emissions associated with the use of flares to control storage vessels subject to existing source standards are estimated to be 5,500 tpy of CO2, 16 tpy of CO, 3 tpy of NOx, less than 1 tpy of PM, and 6 tpy total hydrocarbons. For storage vessels subject to new source standards, increases in secondary air pollutants are estimated to be less than 900 tpy of CO2, 3 tpy of CO, 1 tpy of NOx, 1 tpy of PM and 1 tpy total hydrocarbons.
	In addition, we estimate that the secondary impacts associated with the pneumatic controller requirements to comply with the proposed NSPS would be about 22 tpy of CO2, 1 tpy of NOx, and 3 tpy PM. For gas wellhead affected facilities, we estimate that the use of flares would result in increases in criteria pollutant emissions of about 990,000 tons of CO2, 2,800 tpy of CO, 500 tpy of NOx, 5 tpy of PM and 1,000 tpy total hydrocarbons.
F. What are the energy impacts?
	Energy impacts in this section are those energy requirements associated with the operation of emission control devices. Potential impacts on the national energy economy from the rule are discussed in the economic impacts section. There would be little national energy demand increase from the operation of any of the control options analyzed under the proposed NESHAP amendments and proposed NSPS.
	The proposed NESHAP amendments and proposed NSPS encourage the use of emission controls that recover hydrocarbon products, such as methane and condensate that can be used on-site as fuel or reprocessed, within the production process, for sale. We estimated that the proposed standards will result in a net cost savings due to the recovery of salable natural gas and condensate. Thus, the final standards have a positive impact associated with the recovery of non-renewable energy resources.
G. What are the cost impacts?
	The estimated total capital cost to comply with the proposed amendments to subpart HH for major sources in the oil and natural gas production source category is approximately $51.5 million. The total capital cost for the proposed amendments to subpart HHH for major sources in the natural gas transmission and storage source category is estimated to be approximately $370 thousand.
	The total estimated net annual cost to industry to comply with the proposed amendments to subpart HH for major sources in the oil and natural gas production source category is approximately $16 million. The total net annual cost for proposed amendments to subpart HHH for major sources in the natural gas transmission and storage source category is estimated to be approximately $361 thousand. These estimated annual costs include: (1) The cost of capital, (2) operating and maintenance costs, (3) the cost of MIRR, and (4) any associated product recovery credits.
	The estimated total capital cost to comply with the proposed NSPS is approximately $740 million in 2008 dollars. The total estimated net annual cost to industry to comply with the proposed NSPS is approximately $738 million in 2008 dollars. This annual cost estimate includes: (1) The cost of capital, (2) operating and maintenance costs and (3) the cost of MIRR. This estimated annual cost does not take into account any producer revenues associated with the recovery of salable natural gas and hydrocarbon condensates. When revenue from additional product recovery are considered, the proposed NSPS is estimated to result in a net annual cost savings overall. This savings is estimated at $45 million in 2008 dollars.
H. What are the economic impacts?
	The NEMS analysis of energy system impacts for the proposed NSPS option estimates that domestic natural gas production is likely to increase slightly (about 20 billion cubic feet or 0.1 percent) and average natural gas prices to decrease slightly ($0.04/Mcf in 2008 dollars or 0.9 percent at the wellhead for onshore producers in the lower 48 states) for 2015, the year of analysis. This increase in production and decrease in wellhead price is largely a result of the increased natural gas and condensate recovery as a result of complying with the NSPS. Domestic crude oil production is not expected to change, while average crude oil prices are estimated to decrease slightly ($0.02/barrel in 2008 dollars or less than 0.1 percent at the wellhead for onshore producers in the lower 48 states) in the year of analysis, 2015. The NEMS-based analysis estimates in the year of analysis 2015 that net imports of natural gas and crude will not change significantly.
	Total CO2-equivalent emissions from energy-related sources are expected to increase about 2.0 million metric tons CO2-equivalent or 0.04 percent under the proposed NSPS, according to the NEMS analysis. This increase is attributable largely to natural gas consumption increases. This estimate does not include CO2-equivalent reductions from the implementation of the controls; these reductions are discussed in more detail in the benefits section that follows.
	We did not estimate the energy economy impacts of the proposed NESHAP amendments using NEMS as the expected costs of the rule are not likely to have estimable impacts on the national energy economy.
I. What are the benefits?
	The proposed oil and natural gas NSPS and NESHAP amendments are expected to result in significant reductions in existing emissions and prevent new emissions from expansions of the industry. These proposed rules combined are anticipated to reduce 38,000 tons of HAP, 980,000 tons of VOCs, and 3.4 million tons of methane. These pollutants are associated with substantial health effects, welfare effects, and climate effects. With the data available, we are not able to provide credible health benefit estimates for the reduction in exposure to HAPs, ozone, and PM2.5 for these rules, due to the differences in the locations of oil and natural gas emission points relative to existing information, and the highly localized nature of air quality responses associated with HAP and VOC reductions.
This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. In addition to health improvements, there will be improvements in visibility effects, ecosystem effects, and climate effects as well as additional product recovery.
	Although we do not have sufficient information or modeling available to provide quantitative estimates for this rulemaking, we include a qualitative assessment of the health effects associated with exposure to HAPs, ozone, and PM2.5 in the RIA for this rule. These qualitative effects are briefly summarized below, but for more detailed information please refer to the RIA, which is available in the docket. Two of the HAPs of concern from the oil and gas sector are benzene, which is a known human carcinogen, and formaldehyde, which is a probable human carcinogen. Volatile organic compound emissions are precursors to both PM2.5 and ozone formation. As documented in previous analyses (U.S. EPA, 2006 and U.S. EPA, 2010), exposure to PM2.5 and ozone is associated with significant public health effects. PM2.5 is associated with health effects such as premature mortality for adults and infants, cardiovascular morbidity such as heart attacks, hospital admissions, and respiratory morbidity such as asthma attacks, acute and chronic bronchitis, hospital and emergency room visits, work loss days, restricted activity days, and respiratory symptoms, as well as visibility impairment. Ozone is associated with health effects such as respiratory morbidity such as asthma attacks, hospital and emergency department visits, school loss days, and premature mortality, as well as injury to vegetation and climate effects.
	In addition to the improvements in air quality and resulting benefits to human health and non-climate welfare effects previously discussed, this proposed rule is expected to result in significant climate co-benefits due to anticipated methane reductions. Methane is a potent GHG that, once emitted into the atmosphere, absorbs terrestrial infrared radiation, which contributes to increased global warming and continuing climate change. Methane reacts in the atmosphere to form ozone, and ozone also impacts global temperatures. According to the Intergovernmental Panel on Climate Change (IPCC) 4[th] Assessment Report (2007), methane is the second leading long-lived climate forcer after CO2 globally. Total methane emissions from the oil and gas industry represent about 43 percent of the total methane emissions from all sources and account for about 5 percent of all CO2 equivalent (CO2e) emissions in the United States, with natural gas systems being the single largest contributor to United States anthropogenic methane emissions. Methane, in addition to other GHG emissions, contributes to warming of the atmosphere which over time leads to increased air and ocean temperatures, changes in precipitation patterns, melting and thawing of global glaciers and ice, increasingly severe weather events, such as hurricanes of greater intensity, and sea level rise, among other impacts.
	This rulemaking proposes emission control technologies and regulatory alternatives that will significantly decrease methane emissions from the oil and natural gas sector in the United States. The regulatory alternatives proposed for the RTR and the NSPS are expected to reduce methane emissions annually by about 3.4 million short tons or 65 million metric tons CO2e. After considering the secondary impacts of this proposal previously discussed, such as increased CO2 emissions from well completion combustion and decreased CO2-e emissions because of fuel-switching by consumers, the methane reductions become about 62 million metric tons CO2e. These reductions represent about 21 percent of the baseline methane emissions for this sector and equate to the climate benefits of taking approximately 12 million passenger cars off the road or eliminating electricity use from about 8 million homes each year.
	The EPA recognizes that the methane reductions proposed in this rule will provide for significant economic climate benefits to society just described. However, there is no interagency accepted methodology to place monetary values on these benefits. A `GWP approach' of converting methane to CO2e using the GWP of methane provides an approximation method for estimating the monetized value of the methane reductions anticipated from this rule. This calculation uses the GWP of the non-CO2 gas to estimate CO2 equivalents and then multiplies these CO2 equivalent emission reductions by the Social Cost of Carbon (SCC) developed by the interagency SCC workgroup to generate monetized estimates of the benefits.
	The SCC is an estimate of the net present value of the flow of monetized damages from a 1 metric ton increase in CO2 emissions in a given year (or from the alternative perspective, the benefit to society of reducing CO2 emissions by 1 ton). For more information about the SCC, see the SCC TSD and RIA for the Light Duty Vehicle GHG rule. Applying this approach to the methane reductions estimated for the proposed RTR and NSPS of the oil and gas rule, the 2015 benefits vary by discount rate and range from about $370 million to approximately $4.7 billion; the mean SCC at the 3 percent discount rate results in an estimate of about $1.6 billion in 2015. These benefits equate to a range of approximately $110 to $1,400 per short ton of methane reduced depending upon the discount rate assumed with a per ton estimate of $480 at the 3 percent discount rate. Benefit estimates for additional regulatory alternatives are included in the RIA for this proposed rule. These social cost of methane benefit estimates are not the same as would be derived from direct computations (using the integrated assessment models employed to develop the interagency SCC estimates) for a variety of reasons including the shorter atmospheric lifetime of methane relative to CO2 (about 12 years compared to CO2 whose concentrations in the atmosphere decay on timescales of decades to millennia). The climate impacts also differ between the pollutants for reasons other than the radiative forcing profiles and atmospheric lifetimes of these gases.
	Methane is a precursor to ozone, and ozone is a short-lived climate forcer that contributes to global warming. The use of the IPCC Second Assessment Report GWP to approximate benefits may underestimate the direct radiative forcing benefits of reduced ozone levels and does not capture any secondary climate benefits involved with ozone-ecosystem interactions. In addition, a recent EPA National Center of Environmental Economics working paper suggests that this quick `GWP approach' to benefits estimation will likely understate the climate benefits of methane reductions in most cases.  This conclusion is reached using the 100-year GWP for methane of 25 as put forth in the IPCC Fourth Assessment Report (AR 4) as opposed to the lower value of 21 used in this analysis. Using the higher GWP estimate of 25 would increase these reported methane climate benefit estimates by about 19 percent. Although the IPCC AR4 suggested a GWP of 25 for methane, the EPA has used GWP of 21 to estimate the methane climate benefits for this oil and gas proposal in order to provide estimates more consistent with global GHG inventories, which currently use GWPs from the IPCC Second Assessment Report.
	Due to the uncertainties involved with the `GWP approach' estimates presented and methane climate benefits estimates available in the literature, the EPA chooses not to compare these benefit estimates to the costs of the rule for this proposal. Rather, the EPA presents the `GWP approach' climate benefit estimates as an interim method to produce these estimates until the interagency SCC workgroup develops values for non-CO2 GHGs. The EPA requests comments from interested parties and the public about this interim approach specifically and more broadly about appropriate methods to monetize the climate benefits of methane reductions. In particular, the EPA seeks public comments to this proposed rulemaking regarding social cost of methane estimates that may be used to value the benefits of methane emission reductions anticipated for the oil and gas industry from this rule. Comments specific to whether GWP is an acceptable method for generating a placeholder value for the social cost of methane until interagency-modeled estimates become available are welcome. Public comments may be provided in the official docket for this proposed rulemaking in accordance with the process outlined earlier in this notice. These comments will be considered in developing the final rule for this rulemaking.
	For the proposed NESHAP amendments, a break-even analysis suggests that HAP emissions would need to be valued at $12,000 per ton for the benefits to exceed the costs if the health, ecosystem, and climate benefits from the reductions in VOC and methane emissions are assumed to be zero. Even though emission reductions of VOC and methane are co-benefits for the proposed NESHAP amendments, they are legitimate components of the total benefit-cost comparison. If we assume the health benefits from HAP emission reductions are zero, the VOC emissions would need to be valued at $1,700 per ton or the methane emissions would need to be valued at $3,300 per ton for the benefits to exceed the costs. All estimates are in 2008 dollars. For the proposed NSPS, the revenue from additional product recovery exceeds the costs, which renders a break-even analysis unnecessary when these revenues are included in the analysis. Based on the methodology from Fann, Fulcher, and Hubbell (2009), ranges of benefit-per-ton estimates for emissions of VOC indicate that on average in the United States, VOC emissions are valued from $1,200 to $3,000 per ton as a PM2.5 precursor, but emission reductions in specific areas are valued from $280 to $7,000 per ton in 2008 dollars. As a result, even if VOC emissions from oil and natural gas operations result in monetized benefits that are substantially below the national average, there is a reasonable chance that the benefits of the rule would exceed the costs, especially if we were able to monetize all of the additional benefits associated with ozone formation, visibility, HAP and methane.
IX. Request for Comments
	We are soliciting comments on all aspects of this proposed action. All comments received during the comment period will be considered. In addition to general comments on the proposed actions, we are also interested in any additional data that may help to reduce the uncertainties inherent in the risk assessments. We are specifically interested in receiving corrections to the datasets used for MACT analyses and risk modeling. Such data should include supporting documentation in sufficient detail to allow characterization of the quality and representativeness of the data or information. Please see the following section for more information on submitting data.
X. Submitting Data Corrections
      The facility-specific data used in the source category risk analyses, facility-wide analyses, and demographic analyses for each source category subject to this action are available for download on the RTR Web Page at http://www.epa.gov/ttn/atw/rrisk/rtrpg.html. These data files include detailed information for each HAP emissions release point at each facility included in the source category and all other HAP emissions sources at these facilities (facility-wide emissions sources). However, it is important to note that the source category risk analysis included only those emissions tagged with the MACT code associated with the source category subject to the risk analysis.
      If you believe the data are not representative or are inaccurate, please identify the data in question, provide your reason for concern, and provide any "improved" data that you have, if available. When you submit data, we request that you provide documentation of the basis for the revised values to support your suggested changes. To submit comments on the data downloaded from the RTR Web page, complete the following steps:
      1. Within this downloaded file, enter suggested revisions to the data fields appropriate for that information. The data fields that may be revised include the following:
                                 Data Element
                                  Definition
Control Measure
Are control measures in place? (yes or no)
Control Measure Comment
Select control measure from list provided, and briefly describe the control measure
Delete
Indicate here if the facility or record should be deleted
Delete Comment
Describes the reason for deletion
Emission Calculation Method Code For Revised Emissions
Code description of the method used to derive emissions. For example, CEM, material balance, stack test, etc.
Emission Process Group
Enter the general type of emission process associated with the specified emission point
Fugitive Angle
Enter release angle (clockwise from true North); orientation of the y-dimension relative to true North, measured positive for clockwise starting at 0 degrees (maximum 89 degrees)
Fugitive Length
Enter dimension of the source in the east-west (x-) direction, commonly referred to as length (ft)
Fugitive Width
Enter dimension of the source in the north-south (y-) direction, commonly referred to as width (ft)
Malfunction Emissions
Enter total annual emissions due to malfunctions (TPY)
Malfunction Emissions Max Hourly
Enter maximum hourly malfunction emissions here (lb/hr)
North American Datum
Enter datum for latitude/longitude coordinates (NAD27 or NAD83); if left blank, NAD83 is assumed
Process Comment
Enter general comments about process sources of emissions
REVISED Address
Enter revised physical street address for MACT facility here
REVISED City
Enter revised city name here
REVISED County Name
Enter revised county name here
REVISED Emission Release Point Type
Enter revised Emission Release Point Type here
REVISED End Date
Enter revised End Date here
REVISED Exit Gas Flow Rate
Enter revised Exit Gas Flowrate here (ft3/sec)
REVISED Exit Gas Temperature
Enter revised Exit Gas Temperature here (OF)
REVISED Exit Gas Velocity
Enter revised Exit Gas Velocity here (ft/sec)
REVISED Facility Category Code
Enter revised Facility Category Code here, which indicates whether facility is a major or area source
REVISED Facility Name
Enter revised Facility Name here
REVISED Facility Registry Identifier
Enter revised Facility Registry Identifier here, which is an ID assigned by the EPA Facility Registry System
REVISED HAP Emissions Performance Level Code
Enter revised HAP Emissions Performance Level here
REVISED Latitude
Enter revised Latitude here (decimal degrees)
REVISED Longitude
Enter revised Longitude here (decimal degrees)
REVISED MACT Code
Enter revised MACT Code here
REVISED Pollutant Code
Enter revised Pollutant Code here
REVISED Routine Emissions
Enter revised routine emissions value here (TPY)
REVISED SCC Code
Enter revised SCC Code here
REVISED Stack Diameter
Enter revised Stack Diameter here (ft)
REVISED Stack Height
Enter revised Stack Height here (Ft)
REVISED Start Date
Enter revised Start Date here
REVISED State
Enter revised state here
REVISED Tribal Code
Enter revised Tribal Code here
REVISED Zip Code
Enter revised Zip Code here
Shutdown Emissions
Enter total annual emissions due to shutdown events (TPY)
Shutdown Emissions Max Hourly
Enter maximum hourly shutdown emissions here (lb/hr)
Stack Comment
Enter general comments about emission release points
Startup Emissions
Enter total annual emissions due to startup events (TPY)
Startup Emissions Max Hourly
Enter maximum hourly startup emissions here (lb/hr)
Year Closed
Enter date facility stopped operations

      2. Fill in the commenter information fields for each suggested revision (i.e., commenter name, commenter organization, commenter email address, commenter phone number, and revision comments).
      3. Gather documentation for any suggested emissions revisions (e.g., performance test reports, material balance calculations, etc.).
      4. Send the entire downloaded file with suggested revisions in Microsoft(R) Access format and all accompanying documentation to Docket ID Number EPA-HQ-OAR-2010-0786 (through one of the methods described in the ADDRESSES section of this preamble). To expedite review of the revisions, it would also be helpful if you submitted a copy of your revisions to the EPA directly at<EMAIL_ADDRESS>in addition to submitting them to the docket.
      5. If you are providing comments on a facility with multiple source categories, you need only submit one file for that facility, which should contain all suggested changes for all source categories at that facility. We request that all data revision comments be submitted in the form of updated Microsoft(R) Access files, which are provided on the http://www.epa.gov/ttn/atw/rrisk/rtrpg.html Web page.
XI. Statutory and Executive Order Reviews
A. Executive Order 12866, Regulatory Planning and Review and Executive Order 13563, Improving Regulation and Regulatory Review
      Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is an "economically significant regulatory action" because it is likely to have an annual effect on the economy of $100 million or more. Accordingly, the EPA submitted this action to OMB for review under Executive Order 12866 and Executive Order 13563 (76 FR 3821, January 21, 2011) and any changes made in response to OMB recommendations have been documented in the docket for this action.
      In addition, the EPA prepared a RIA of the potential costs and benefits associated with this action. The RIA available in the docket describes in detail the empirical basis for the EPA's assumptions and characterizes the various sources of uncertainties affecting the estimates below. Table 8 below shows the results of the cost and benefits analysis for this rule. For more information on the benefit and cost analysis, as well as details on the regulatory options considered, please refer to the RIA for this rulemaking, which is available in the docket.

Table 8. Summary of the Monetized Benefits, Costs and Net Benefits for the Proposed Oil and Natural Gas NSPS and NEHSAP Amendments in 2015 (millions of 2008$)[1]

                                 Proposed NSPS
                          Proposed NESHAP Amendments
                 Proposed NSPS and NESHAP Amendments Combined
Total Monetized Benefits[2]
                                      N/A
                                      N/A
                                      N/A
Total Costs[3]
                                 -$45 million
                                  $16 million
                                 -$29 million
Net Benefits
                                      N/A
                                      N/A
                                      N/A
                            Non-monetized Benefits
                              36,000 tons of HAP
                               1,300 tons of HAP
                              38,000 tons of HAP

                            970 thousand tons of VOC
                               9,200 tons of VOC
                            980 thousand tons of VOC

                          3.4 million tons of methane
                             4,900 tons of methane
                          3.4 million tons of methane

                        Health effects of HAP exposure

                  Health effects of PM2.5 and ozone exposure

                             Visibility impairment

                              Vegetation effects

                                Climate effects

1 All estimates are for the implementation year (2015)
2 While we expect that these avoided emissions will result in improvements in air quality and reductions in health effects associated with HAP, ozone and PM, as well as climate effects associated with methane, we have determined that quantification of those benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available.
3 The engineering compliance costs are annualized using a 7-percent discount rate. The negative cost for the proposed NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate recovery that are estimated as a result of the proposed NSPS.

B. Paperwork Reduction Act
	The information collection requirements in this proposed action have been submitted for approval to OMB under the PRA, 44 U.S.C. 3501, et seq. The ICR document prepared by the EPA has been assigned EPA ICR Numbers 1716.07 (40 CFR part 60, subpart OOOO), 1788.10 (40 CFR part 63, subpart HH), 1789.07 (40 CFR part 63, subpart HHH), and 1086.10 (40 CFR part 60, subparts KKK and subpart LLL).
      The information to be collected for the proposed NSPS and the proposed NESHAP amendments are based on notification, recordkeeping, and reporting requirements in the NESHAP General Provisions (40 CFR part 63, subpart A), which are mandatory for all operators subject to national emission standards. These recordkeeping and reporting requirements are specifically authorized by section 114 of the CAA (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B.
      These proposed rules would require maintenance inspections of the control devices, but would not require any notifications or reports beyond those required by the General Provisions. The recordkeeping requirements require only the specific information needed to determine compliance.
      For sources subject to the proposed NSPS, burden changes associated with these amendments result from the respondents' annual reporting and recordkeeping burden associated with this proposed rule for this collection (averaged over the first 3 years after the effective date of the standards). The burden is estimated to be 560,000 labor hours at a cost of $18 million per year. This includes the burden previously estimated for sources subject to 40 CFR part 60, subpart KKK (which is being incorporated into 40 CFR part 60, subpart OOOO). The average hours and cost per regulated entity subject to the NSPS for oil and natural gas production and natural gas transmissions and distribution facilities would be 110 hours per response and $3,693 per response based on an average of 1,459 operators responding per year and 16 responses per year.
      The estimated recordkeeping and reporting burden after the effective date of the proposed amendments is estimated for all affected major and area sources subject to the oil and natural gas production NESHAP to be approximately 63,000 labor hours per year at a cost of $2.1 million per year. For the natural gas transmission and storage NESHAP, the recordkeeping and reporting burden is estimated to be 2,500 labor hours per year at a cost of $86,800 per year. This estimate includes the cost of reporting, including reading instructions, and information gathering. Recordkeeping cost estimates include reading instructions, planning activities, and conducting compliance monitoring. The average hours and cost per regulated entity subject to the oil and natural gas production NESHAP would be 72 hours per year and $2,500 per year based on an average of 846 facilities per year and three responses per facility. For the natural gas transmission and storage NESHAP, the average hours and cost per regulated entity would be 50 hours per year and $1,600 per year based on an average of 53 facilities per year and three responses per facility. Burden is defined at 5 CFR 1320.3(b).
      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 the EPA's regulations in 40 CFR are listed in 40 CFR part 9.
      To comment on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, the EPA has established a public docket for this rule, which includes this ICR, under Docket ID Number EPA-HQ-OAR-2010-0505. Submit any comments related to the ICR to the EPA and OMB. See ADDRESSES section at the beginning of this notice for where to submit comments to the EPA. Send comments to OMB at the Office of Information and Regulatory Affairs, OMB, 725 17th Street, NW, Washington, DC 20503, Attention: Desk Office for the EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], a comment to OMB is best assured of having its full effect if OMB receives it by [INSERT DATE 30 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER]. The final rule will respond to any OMB or public comments on the information collection requirements contained in this proposal.
C. Regulatory Flexibility Act
	The RFA as amended by the Small Business Regulatory Enforcement Fairness Act (SBREFA) 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 governmental jurisdictions, and small not-for-profit enterprises. For purposes of assessing the impact of this rule on small entities, a small entity is defined as: (1) A small business whose parent company has no more than 500 employees (or revenues of less than $7 million for firms that transport natural gas via pipeline); (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 which is independently owned and operated and is not dominant in its field.
Proposed NSPS
After considering the economic impact of the Proposed NSPS on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities (SISNOSE). EPA performed a screening analysis for impacts on a sample of expected affected small entities by comparing compliance costs to entity revenues. Based upon the analysis in the RIA, which is in the Docket, EPA concludes the number of impacted small businesses is unlikely to be sufficiently large to declare a SISNOSE.  Our judgment in this determination is informed by the fact that many affected firms are expected to receive revenues from the additional natural gas and condensate recovery engendered by the implementation of the controls evaluated in this RIA. As much of the additional natural gas recovery is estimated to arise from completion-related activities, we expect the impact on well-related compliance costs to be significantly mitigated. This conclusion is enhanced because the returns to reduced emissions completion activities occur without a significant time lag between implementing the control and obtaining the recovered product unlike many control options where the emissions reductions accumulate over long periods of time; the reduced emission completions and recompletions occur over a short span of time, during which the additional product recovery is also accomplished.
Proposed NESHAP Amendments
After considering the economic impact of the Proposed NESHAP Amendments on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. Based upon the analysis in the Regulatory Impact Analysis, which is in the Docket, we estimate that 62 of the 118 firms (53%) that own potentially affected facilities are small entities. EPA performed a screening analysis for impacts on all expected affected small entities by comparing compliance costs to entity revenues. Among the small firms, 52 of the 62 (84%) are likely to have impacts of less than 1% in terms of the ratio of annualized compliance costs to revenues. Meanwhile 11 firms (18 percent) are likely to have impacts greater than 1%. Four of these 11 firms are likely to have impacts greater than 3 percent. While these 11 firms might receive significant impacts from the proposed NESHAP amendments, they represent a very small slice of the oil and gas industry in its entirety, less than 0.2 percent of the estimated 6,427 small firms in NAICS 211. Although this final rule will not impact a substantial number of small entities, EPA nonetheless has tried to reduce the impact of this rule on small entities by setting the final emissions limits at the MACT floor, the least stringent level allowed by law.
 D. Unfunded Mandates Reform Act
      This proposed 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 to the private sector in any one year. Thus, this proposed rule is not subject to the requirements of sections 202 or 205 of UMRA.
      This proposed 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 because it contains no requirements that apply to such governments nor does it impose obligations upon them.
E. Executive Order 13132: Federalism
      This proposed rule 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 Executive Order 13132. Thus, Executive Order 13132 does not apply to this proposed rule.
      In the spirit of Executive Order 13132, and consistent with the EPA policy to promote communications between the EPA and state and local governments, the EPA specifically solicits comment on this proposed rule from state and local officials.
F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments
      Subject to the Executive Order 13175 (65 FR 67249, November 9, 2000) the EPA may not issue a regulation that has tribal implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by tribal governments, or the EPA consults with tribal officials early in the process of developing the proposed regulation and develops a tribal summary impact statement. The EPA has concluded that this proposed rule will not have tribal implications, as specified in Executive Order 13175. It will not have substantial direct effect on tribal governments, on the relationship between the Federal government and Indian tribes, or on the distribution of power and responsibilities between the Federal government and Indian tribes, as specified in Executive Order 13175. Thus, Executive Order 13175 does not apply to this action.
      The EPA specifically solicits additional comment on this proposed action from tribal officials.
G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks
      This proposed rule is subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because it is economically significant as defined in Executive Order 12866. However, the EPA does not believe the environmental health or safety risks addressed by this action present a disproportionate risk to children. This action would not relax the control measures on existing regulated sources. The EPA's risk assessments (included in the docket for this proposed rule) demonstrate that the existing regulations are associated with an acceptable level of risk and provide an ample margin of safety to protect public health.
H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution or Use
	Executive Order 13211, (66 FR 28,355, May 22, 2001), provides that agencies shall prepare and submit to the Administrator of the Office of Information and Regulatory Affairs, OMB, a Statement of Energy Effects for certain actions identified as significant energy actions. Section 4(b) of Executive Order 13211 defines "significant energy actions" as "any action by an agency (normally published in the Federal Register) that promulgates or is expected to lead to the promulgation of a final rule or regulation, including notices of inquiry, advance notices of proposed rulemaking, and notices of proposed rulemaking: (1)(i) That is a significant regulatory action under Executive Order 12866 or any successor order and (ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy; or (2) that is designated by the Administrator of the Office of Information and Regulatory Affairs as a significant energy action."
	The proposed rules will result in the addition of control equipment and monitoring systems for existing and new sources within the oil and natural gas industry. The proposed NESHAP amendments are unlikely to have a significant adverse effect on the supply, distribution, or use of energy. As such, the proposed NESHAP amendments are not "significant energy actions" as defined in Executive Order 13211, (66 FR 28355, May 22, 2001).
	The proposed NSPS is also unlikely to have a significant effect on the supply, distribution, or use of energy. As such, the proposed NSPS is not a "significant energy action" as defined in Executive Order 13211 (66 FR 28355, May 22, 2001). The basis for the determination is as follows.
	As discussed in the impacts section of the Preamble, we use the NEMS to estimate the impacts of the proposed NSPS on the United States energy system. The NEMS is a publically available model of the United States energy economy developed and maintained by the Energy Information Administration of the U.S. DOE and is used to produce the Annual Energy Outlook, a reference publication that provides detailed forecasts of the United States energy economy.
	Proposed emission controls for the NSPS capture VOC emissions that otherwise would be vented to the atmosphere. Since methane is co-emitted with VOC, a large proportion of the averted methane emissions can be directed into natural gas production streams and sold. One pollution control requirement of the proposed NSPS also captures saleable condensates. The revenues from additional natural gas and condensate recovery are expected to offset the costs of implementing the proposed NSPS.
	The analysis of energy impacts for the proposed NSPS that includes the additional product recovery shows that domestic natural gas production is estimated to increase (20 billion cubic feet or 0.1 percent) and natural gas prices to decrease ($0.04/Mcf or 0.9 percent at the wellhead for producers in the lower 48 states) in 2015, the year of analysis. Domestic crude oil production is not estimated to change, while crude oil prices are estimated to decrease slightly ($0.02/barrel or less than 0.1 percent at the wellhead for producers in the lower 48 states) in 2015, the year of analysis. All prices are in 2008 dollars.
	Additionally, the NSPS establishes several performance standards that give regulated entities flexibility in determining how to best comply with the regulation. In an industry that is geographically and economically heterogeneous, this flexibility is an important factor in reducing regulatory burden.