In this meeting the tribes were presented the information in the proposal. The tribes asked general clarifying questions but did not provide specific comments. Comments on the proposal were received from an affiliate of the Southern Ute Indian Tribe. The commenter expressed concern about the impacts of the rule on natural gas and oil production operations on the Southern Ute Indian reservation and requested additional time to evaluate the impacts. In response to this and other requests, the comment period was extended. More specific comments can be found in the docket.
Executive Order 13045:  Protection of Children from Environmental Health Risks and Safety Risks
      This action is not subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because the Agency does not believe the environmental health risks 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 final 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.
Executive Order 13211:  Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use
	This action is not a "significant energy action" as defined in Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. These final 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 final NESHAP amendments are unlikely to have a significant adverse effect on the supply, distribution, or use of energy. As such, the final NESHAP amendments are not "significant energy actions" as defined in Executive Order 13211, (66 FR 28355, May 22, 2001). The final NSPS is also unlikely to have a significant adverse effect on the supply, distribution, or use of energy. As such, the final NSPS is not a "significant energy action" as defined in Executive Order 13211 (66 FR 28355, May 22, 2001).
	The basis for these determinations is as follows. 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 final NSPS also captures saleable condensates. The revenues from additional natural gas and condensate recovery are expected to offset the costs of implementing the final rules.
	We use the National Energy Modeling System (NEMS) to estimate the impacts of the combined final rules 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 DOE and is used to produce the Annual Energy Outlook, a reference publication that provides detailed forecasts of the United States energy economy.
	Based on public comments and reports to EPA's Natural Gas STAR program, EPA recognizes that some producers conduct well completions using REC techniques, which are required by the final NSPS for certain completions of hydraulically fractured and refractured natural gas wells, voluntarily based upon economic and environmental objectives. The baseline used for the energy system impacts analysis takes into account RECs conducted pursuant to state regulations covering these operations and estimates of RECs performed voluntarily.  To account for RECs performed in regulated states, EPA subsumed emissions reductions and compliance costs in states where these completion-related emissions are already controlled into the baseline.  Additionally, based on public comments and reports to EPA's Natural Gas STAR program, EPA recognizes that some producers conduct well completions using REC techniques voluntarily for economic and/or environmental objectives as a normal part of business. To account for emissions reductions and costs arising from voluntary implementation of pollution controls EPA used information on total emission reductions reported to the EPA by partners of the EPA Natural Gas STAR.  This estimate of this voluntary REC activity in the absence of regulation is also included in the baseline. More detailed discussion on the derivation of the baseline is presented in a technical memorandum in the docket.
	 The analysis of energy system impacts for the final NSPS under the primary baseline shows that domestic natural gas production is not likely to change in 2015, the year used in the RIA to analyze impacts. Average natural gas prices are also not estimated to change in response to the final rules.  Domestic crude oil production is not expected to change, while average crude oil prices are estimated to decrease slightly (about $0.01/barrel or about 0.01 percent at the wellhead for onshore production in the lower 48 states).  All prices are in 2008 dollars.  The NEMS-based analysis estimates in the year of analysis, 2015, that net imports of natural gas and crude oil will not change.
	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.
	For more information on the estimated energy effects of this final rule, please see Section 7 of this RIA.
National Technology Transfer and Advancement Act
	Section 12(d) of the NTTAA of 1995, Public Law 104 - 113, 12(d) (15 U.S.C. 272 note) directs the EPA to use VCS in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by VCS bodies. The NTTAA directs the EPA to provide Congress, through OMB, explanations when the EPA decides not to use available and
applicable VCS.
	This final action does not involve technical standards. Therefore, the EPA is not considering the use of any VCS.
Executive Order 12898:  Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations
	Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive policy on environmental justice. Its main provision directs Federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies and activities on minority populations and low income populations in the United States.
	The EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority, low-income, or indigenous populations.
	To examine the potential for any environmental justice issues that might be associated with each source category, we evaluated the percentages of various social, demographic, and economic groups within the at-risk population living near the facilities where these source categories are located and compared them to national averages. The development of demographic analyses to inform the consideration of environmental justice issues in the EPA rulemakings is an evolving science.
	The EPA conducted a demographic analysis, focusing on populations within 50 km of any facility in each of the source categories that are estimated to have HAP exposures which result in cancer risks of 1-in-1 million or greater or non-cancer hazard indices of 1 or greater based on estimates of current HAP emissions.  The results of this analysis are documented in the technical report: Risk and Technology Review  -  Analysis of Socio-economic Factors for Populations Living Near Oil & Natural Gas Production Facilities located in the docket for this rulemaking.
	As described in the preamble, our risk assessments demonstrate that the regulations for the oil and natural gas production and natural gas transmission and storage source categories, are associated with an acceptable level of risk and that the proposed additional requirements will provide an ample margin of safety to protect public health. Our analyses also show that, for these source categories, there is no potential for an adverse environmental effect or human health multi-pathway effects, and that acute and chronic non-cancer health impacts are unlikely. The EPA has determined that, although there may be an existing disparity in HAP risks from these sources between some demographic groups, no demographic group is exposed to an unacceptable level of risk.
	To promote meaningful involvement, the EPA conducted three public hearings on the proposal. The hearings were held in Pittsburgh, Pennsylvania, on September 27, 2011, Denver, Colorado, on September 28, 2011, and Arlington, Texas, on September 29, 2011. A total of 261 people spoke at the three hearings and 735 people attended the hearings. The attendees at the hearings included private citizens, community-based and environmental organizations, industry representatives, associations representing industry and local and state government officials.
Congressional Review Act

     The Congressional Review Act, 5 U.S.C. 801, et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. The EPA will submit a report containing this final rule and other required information to the United States Senate, the United States House of Representatives, and the Comptroller General of the United States prior to publication of the final rule in the Federal Register. A major rule cannot take effect until 60 days after it is published in the Federal Register. This action is a "major rule" as defined by 5 U.S.C. 804(2).
Comparison of Benefits and Costs
      Because we are unable to estimate the monetary value of the emissions reductions from the rule, we have chosen to rely upon a break-even analysis to estimate what the monetary value benefits would need to attain in order to equal the costs estimated to be imposed by the rule.  A break-even analysis answers the question, "What would the benefits need to be for the benefits to exceed the costs."  While a break-even approach is not equivalent to a benefits analysis or even a net benefits analysis, we feel the results are illustrative, particularly in the context of previously modeled benefits.
      The total annualized engineering cost of the final NSPS in the analysis year of 2015 when the additional natural gas and condensate recovery is included in the analysis is estimated at -$15 million.  EPA anticipates that this rule would prevent 190,000 tons of VOC, 1.0 million tons of methane, and 11,000 tons of HAP in 2015 from new sources.  In 2015, EPA estimates the annualized costs for the NESHAP Amendments to be 3.5 million.  EPA anticipates that this rule would reduce 1,200 tons of VOC, 420 tons of methane, and 670 tons of HAP in 2015 from existing sources.  For the NESHAP Amendments, a break-even analysis suggests that HAP emissions would need to be valued at $5,200 per ton for the benefits to exceed the costs if the health benefits, and ecosystem and climate co-benefits from the reductions in VOC and methane emissions are assumed to be zero.  If we assume the health benefits from HAP emission reductions are zero, the VOC emissions would need to be valued at $2,900 per ton or the methane emissions would need to be valued at $8,300 per ton for the benefits to exceed the costs.  All estimates are in 2008 dollars.
For the final NSPS, the revenue from additional natural gas recovery already exceeds the costs, which renders a break-even analysis unnecessary.  However, as discussed in Section 3.2.2., estimates of the annualized engineering costs that include revenues from natural gas product recovery depend heavily upon assumptions about the price of natural gas and hydrocarbon condensates in analysis year 2015. Therefore, we have also conducted a break-even analysis for the price of natural gas.  For the NSPS, a break-even analysis suggests that the price of natural gas would need to be at least $3.66 per Mcf in 2015 for the revenue from product recovery to exceed the annualized costs.  EIA forecasts that the price of natural gas would be $4.22 per Mcf in 2015.  In addition to the revenue from product recovery, the NSPS would avert emissions of VOC, HAP, and methane, which all have value that could be incorporated into the break-even analysis.  Figure 6-1 illustrates one method of analyzing the break-even point with alternate natural gas prices and VOC benefits.  If, as an illustrative example, the price of natural gas was only $3.00 per Mcf, VOC would need to be valued at about $150 per ton for the benefits to exceed the costs. All estimates are in 2008 dollars.

Figure 6-1	Illustrative Break-Even Diagram for Alternate Natural Gas Prices for the NSPS
      With the data available, we are not able to provide a credible benefit-per-ton estimate for any of the pollutant reductions for these rules to compare to the break-even estimates.  Based on the methodology from Fann, Fulcher, and Hubbell (2009), average PM2.5 health-related benefits of VOC emissions are valued at $280 to $7,000 per ton across a range of eight urban areas.  In addition, ozone benefits have been previously valued at $240 to $1,000 per ton of VOC reduced.  Using the GWP approach, the climate co-benefits range from approximately $110 to $1,400 per short ton of methane reduced depending upon the discount rate assumed with a per ton estimate of $760 at the 3 percent discount rate.
      These break-even benefit-per-ton estimates assume that all other pollutants have zero value.  Of course, it is inappropriate to assume that the value of reducing any of these pollutants is zero.  Thus, the real break-even estimate is actually lower than the estimates provided above because the other pollutants each have non-zero benefits that should be considered.  Furthermore, a single pollutant can have multiple effects (e.g., VOC contribute to both ozone and PM2.5 formation that each have health and welfare effects) that would need to be summed in order to develop a comprehensive estimate of the monetized benefits associated with reducing that pollutant.
      As previously described, the revenue from additional natural gas recovery already exceeds the costs of the NSPS, but even if the price of natural gas was only $3.00 per Mcf, it is likely that the VOC benefits would exceed the costs.  As a result, even if VOC emissions from oil and natural gas operations result in monetized benefits that are substantially below the average modeled benefits, there is a reasonable chance that the benefits of these rules would exceed the costs, especially if we were able to monetize all of the benefits associated with ozone formation, visibility, HAP, and methane.
      Table 6-1 and Table 6-2 present the summary of the benefits, costs, and net benefits for the NSPS and NESHAP Amendments, respectively.  The NSPS analysis assumes that RECs performed voluntarily or in States where these emissions are already regulated would continue in absence of Federal regulation.  Table 6-3 provides a summary of the direct and secondary emissions changes for each rule.

Table 6-1	Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas NSPS in 2015[1]

                                   Final[4]
Total Monetized Benefits[2]
                                      N/A
Total Costs[3]
                                 -$15 million
Net Benefits
                                      N/A
Non-monetized Benefits
                             11,000 tons of HAP[5]

                              190,000 tons of VOC

                          1.0 million tons of methane

                       Health effects of HAP exposure[5]

                  Health effects of PM2.5 and ozone exposure

                             Visibility impairment

                              Vegetation effects

                              Climate effects[5]

1 All estimates are for the implementation year (2015) and include estimated revenue from additional natural gas recovery as a result of the NSPS.

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 particulate matter (PM) as well as climate effects associated with methane, we have determined that quantification of those benefits and co-benefits cannot be accomplished for this rule in a defensible way.  This is not to imply that there are no benefits or co-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.  The specific control technologies for the final NSPS are anticipated to have minor secondary disbenefits, including an increase of 1.1 million tons of carbon dioxide (CO2), 550 tons of nitrogen oxides (NOx), 19 tons of PM, 3,000 tons of CO, and 1,100 tons of total hydrocarbons (THC) as well as emission reductions associated with the energy system impacts.  The net CO2-equivalent (CO2-e) emission reductions are 18 million metric tons.

3 The engineering compliance costs are annualized using a 7 percent discount rate.

4 The negative cost for the NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate recovery that are estimated as a result of the final NSPS.  Possible explanations for why there appear to be negative cost control technologies are discussed in the engineering costs analysis section in the RIA.

[5] Reduced exposure to HAP and climate effects are co-benefits.

Table 6-2	Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas NESHAP Amendments in 2015[1]

                                     Final
Total Monetized Benefits[2]
                                      N/A
Total Costs[3]
                                     $3.5
Net Benefits
                                      N/A
Non-monetized Benefits[5]
                                670 tons of HAP

                             1,200  tons of VOC[4]

                            420  tons of methane[4]

                        Health effects of HAP exposure

                 Health effects of PM2.5 and ozone exposure[4]

                           Visibility impairment[4]

                             Vegetation effects[4]

                              Climate effects[4]

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 and co-benefits cannot be accomplished for this rule in a defensible way.  This is not to imply that there are no benefits or co-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 cost estimates are assumed to be equivalent to the engineering cost estimates.  The engineering compliance costs are annualized using a 7 percent discount rate.

4 Reduced exposure to VOC emissions, PM2.5 and ozone exposure, visibility and vegetation effects, and climate effects are co-benefits.

[5]The specific control technologies for the NESHAP are anticipated to have minor secondary disbenefits, but EPA was unable to estimate these secondary disbenefits.  The net CO2-equivalent emission reductions are 8,000 metric tons.

Table 6-3	Summary of Emissions Changes for the Final Oil and Gas NSPS and NESHAP in 2015 (short tons per year)

                                   Pollutant
                                     NSPS
                                    NESHAP
Change in Direct Emissions
                                      VOC
                                   -190,000
                                     -670

                                    Methane
                                  -1,000,000
                                    -1,200

                                     HAP
                                    -11,000
                                     -420
Change in Secondary Emissions (Producer-Side) [1]
                                      CO2
                                   1,100,000
                                      N/A

                                      NOx
                                      550
                                     N/A

                                      PM
                                      19
                                     N/A

                                      CO
                                     3,000
                                     N/A

                                      THC
                                     1,100
                                     N/A
Change in Secondary Emissions (Consumer-Side)
                                     CO2-e
                                    720,000
                                      N/A
Net Change in CO2-equivalent Emissions
                              CO2-e (short tons)
                                  -19,000,000
                                    -8,800

                              CO2-e (metric tons)
                                  -18,000,000
                                    -8,000

Economic Impact Analysis and Distributional Assessments

Introduction
This section includes three sets of analyses for both the NSPS and NESHAP Amendments:
   * Energy System Impacts
   * Employment Impacts
   * Small Business Impacts Analysis
Energy System Impacts Analysis of Final NSPS and NESHAP Amendments
We use the National Energy Modeling System (NEMS) to estimate the impacts of the final NSPS and NESHAP Amendments on the U.S. energy system.  The impacts we estimate include 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 evaluate whether and to what extent the increased production costs imposed by the final rules might alter the mix of fuels consumed at a national level.  With this information we estimate how the changed fuel mix affects national level CO2-equivalent greenhouse gas emissions from energy sources.  We additionally combine these estimates of changes in CO2-equivalent greenhouse gas emissions from energy sources and emissions co-reductions of methane from the engineering analysis with the NEMS analysis to estimate the net change in CO2-equivalent greenhouse gas emissions from energy-related sources, but this analysis is reserved for the secondary environmental impacts analysis within Section 4.
A brief conceptual discussion about our energy system impacts modeling approach is necessary before going into detail on NEMS, how we implemented the regulatory impacts, and results.  Economically, it is possible to view the recovered natural gas as an explicit output or as contributing to an efficiency gain at the producer level.  For example, the analysis for the final rules shows that about 92 percent of the natural gas captured by emissions controls suggested by the rule is captured by performing REC on new and existing wells that are completed after being hydraulically fractured.  The assumed $4/Mcf price for natural gas is the price paid to producers at the wellhead.  In the natural gas industry, production is metered at or very near to the wellhead, and producers are paid based upon this metered production.  Depending on the situation, the gas captured by REC is sent through a temporary or permanent meter.  Payments for the gas are typically made within 30 days.
      To preview the energy systems modeling using NEMS, results show that after economic adjustments to the new regulations are made by producers, the captured natural gas represents both increased output (a slight increment in aggregate production) and increased efficiency (producing slightly more for less).  However, because of differing objectives for the regulatory analysis we treat the associated savings differently in the engineering cost analysis (as an explicit output) and in NEMS (as an efficiency gain).
      In the engineering cost analysis, it is necessary to estimate the expected costs and revenues from implementing emissions controls at the unit level.  Because of this, we estimate the net costs as expected costs minus expected revenues for representative units.  On the other hand, NEMS models the profit maximizing behavior of representative project developers at a drilling project level. The net costs of the regulation alter the expected discounted cash flow of drilling and implementing oil and gas projects, and the behavior of the representative drillers adjusts accordingly.  While in the regulatory case natural gas drilling has become more efficient because of the gas recovery, project developers still interact with markets for which supply and demand are simultaneously adjusting.  Consequently, project development adjusts to a new equilibrium.  While we believe the cost savings as measured by revenues from selling recovered gas (engineering costs) and measured by cost savings from averted production through efficiency gains (energy economic modeling)  are approximately the same, it is important to note that the engineering cost analysis and the national-level cost estimates do not incorporate economic feedbacks such as supply and demand adjustments.
Description of the Department of Energy National Energy Modeling System
NEMS is a model of U.S. energy economy developed and maintained by the Energy Information Administration of the U.S. Department of Energy (DOE).  NEMS 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.  DOE first developed NEMS in the 1980s, and the model has undergone frequent updates and expansion since.  DOE uses the modeling system extensively to produce issue reports, legislative analyses, and respond to Congressional inquiries.
EIA is legally required to make the NEMS system source code available and fully documented for the public.  The source code and accompanying documentation is released annually when a new Annual Energy Outlook is produced.  Because of the availability of the NEMS model, numerous agencies, national laboratories, research institutes, and academic and private-sector researchers have used NEMS to analyze a variety of issues.
NEMS models the dynamics of energy markets and their interactions with the broader U.S. economy.  The system projects the production of energy resources such as oil, natural gas, coal, and renewable fuels, the conversion of resources through processes such as refining and electricity generation, and the quantity and prices for final consumption across sectors and regions.  The dynamics of the energy system are governed by assumptions about energy and environmental policies, technological developments, resource supplies, demography, and macroeconomic conditions.  An overview of the model and complete documentation of NEMS can be found at <http://www.eia.doe.gov/oiaf/aeo/overview/index.html>.

Figure 7-1	Organization of NEMS Modules (source: U.S. Energy Information Administration)
NEMS is a large-scale, deterministic mathematical programming model.  NEMS iteratively solves multiple models, linear and non-linear, using nonlinear Gauss-Seidel methods (Gabriel et al. 2001).  What this means is that NEMS solves a single module, holding all else constant at provisional solutions, then moves to the next model after establishing an updated provisional solution.
NEMS provides what EIA refers to as "mid-term" projections to the year 2035.  However, as this RIA is concerned with estimating regulatory impacts in the first year of full implementation, our analysis focuses upon estimated impacts in the year 2015, with regulatory costs first imposed in 2011.  For this RIA, we draw upon the same assumptions and model used in the Annual Energy Outlook 2011.   The RIA baseline is consistent with that of the Annual Energy Outlook 2011 which is used extensively in Section 2 in the Industry Profile.
Inputs to National Energy Modeling System
To model potential impacts associated with the final rules, we modified oil and gas production costs within the Oil and Gas Supply Module (OGSM) of NEMS and domestic and Canadian natural gas production within the Natural Gas Transmission and Distribution Module (NGTDM).  The OGSM projects domestic oil and gas production from onshore, offshore, Alaskan wells, as well as having a smaller-scale treatment of Canadian oil and gas production (U.S. EIA, 2010).  The treatment of oil and gas resources is detailed in that oil, shale oil, conventional gas, shale gas, tight sands gas, and coalbed methane (CBM) are explicitly modeled.  New exploration and development is pursued in the OGSM if the expected net present value of extracted resources exceeds expected costs, including costs associated with capital, exploration, development, production, and taxes.  Detailed technology and reservoir-level production economics govern finding and success rates and costs.
The structure of the OGSM is amenable to analyzing potential impacts of the final rules.  We are able to target additional expenditures for environmental controls required by the NSPS and NESHAP Amendments on new exploratory and developmental oil and gas production activities, as well as add additional costs to existing projects.  We model the impacts of additional environmental costs, as well as the impacts of additional product recovery.  We explicitly model the additional natural gas recovered when implementing the final rules.  However, we are unable to explicitly model the additional production of condensates expected to be recovered by reduced emissions completions, although we incorporate expected revenues from the condensate recovery in the economic evaluation of new drilling projects.
While the oil production simulated by the OGSM is sent to the refining module (the Petroleum Market Module), simulated natural gas production is sent to a transmission and distribution network captured in the NGTDM.  The NGTDM balances gas supplies and prices and "negotiates" supply and consumption to determine a regional equilibrium between supply, demand and prices, including imports and exports via pipeline or LNG.  Natural gas is transported through a simplified arc-node representation of pipeline infrastructure based upon pipeline economics.
Compliance Costs for Oil and Gas Exploration and Production
	As the NSPS affects new emissions sources, we chose to estimate impacts on new exploration and development projects by adding costs of environmental regulation to the algorithm that evaluates the profitability of new projects.  Additional NSPS costs associated with reduced emission completions and future recompletions for new wells are added to drilling, completion, and stimulation costs, as these are, in effect, associated with activities that occur within a single time period, although they may be repeated periodically, as in the case of recompletions.  Costs required for reduced emissions recompletions on existing wells are added to stimulation expenses for existing wells exclusively.  Other costs are operations and maintenance-type costs and are added to fixed operation and maintenance (O&M) expenses associated with new projects.  The one-shot and continuing O&M expenses are estimated and entered on a per well basis, depending on whether the costs would apply to oil wells, natural gas wells, both oil and natural gas wells, or a subset of either.  We base the per well cost estimates on the engineering costs including revenues from additional product recovery.  This approach is appropriate given the structure of the NEMS algorithm that estimates the net present value of drilling projects.
One concern in basing the regulatory costs inputs into NEMS on the net cost of the compliance activity (estimated annualized cost of compliance minus estimated revenue from product recovery) is that potential barriers to obtaining capital may not be adequately incorporated in the model.  However, in general, potential barriers to obtaining additional capital should be reflected in the annualized cost via these barriers increasing the cost of capital.  With this in mind, assuming the estimates of capital costs and product recovery are valid, the NEMS results will reflect barriers to obtaining the required capital.  A caveat to this is that the estimated unit-level capital costs of controls that are newly required at a national-level as a result of the regulation -- REC, for example -- may not incorporate potential additional transitional costs as the supply of control equipment adjusts to new demand.
	Table 7-1 shows the incremental O&M expenses that accrue to new drilling projects as a result of producers having to comply with the NSPS.  We estimate those costs as a function of new wells expected to be drilled in a representative year.  To arrive at estimates of the per well costs, we first identify which emissions reductions will apply primarily to crude oil wells, to natural gas wells, or to both crude oil and natural gas wells.  Based on the baseline projections of successful completions in 2015, we used 19,097 new natural gas wells and 12,193 new oil wells as the basis of these calculations.  We then divide the estimated compliance costs for the given emissions point (from Table 3-4) by the appropriate number of expected new wells in the year of analysis.  The result yields an approximation of per well compliance costs.  We assume this approximation is representative of the incremental cost faced by a producer when evaluating a prospective drilling project.
Like the engineering analysis, we assume that hydraulically fractured well completions and recompletions will be required of wells drilled into tight sand, shale gas, and coalbed methane formations.  While costs for well recompletions reflect the cost of a single recompletion, the engineering cost analysis assumed that one in one hundred new wells drilled after the implementation the NSPS are recompleted using hydraulic fracturing in any given year using hydraulic fracturing.  Meanwhile, within NEMS, wells are assumed to be stimulated every five years.  We assume these more frequent stimulations are less intensive than stimulation using hydraulic fracturing but add costs such that the recompletions costs reflect the same assumptions as the engineering analysis.  In entering compliance costs into NEMS, we also account for reduced emissions completions, completion combustion, and recompletions performed in absence of the regulation, using the same assumptions as the engineering costs analysis (Table 7-2).

Table 7-1	Summary of Additional Annualized O&M Costs (on a Per New Well Basis) for Environmental Controls Entered into NEMS

                           Emissions Sources/Points
                               Emissions Control
                            Per Well Costs (2008$)
                           Wells Applied To in NEMS
Equipment Leaks

Processing Plants (NSPS)
                                  Subpart VVa
                                      $14
                                  Natural Gas
Reciprocating Compressors

Gathering and Boosting Stns. (NSPS)
                                      AMM
                                      $10
                                  Natural Gas

Processing Plants (NSPS)
                                      AMM
                                     -$27
                                  Natural Gas
Centrifugal Compressors

Processing Plants (NSPS)
                               Route to control
                                     -$35
                                  Natural Gas
Pneumatic Controllers -

Oil and Gas Production (NSPS)
                                Emission limits
                                   $11/-$698
                                Oil/Natural Gas

Processing Plants (NSPS)
                                Emission limits
                                      7.0
                                  Natural Gas
Storage Vessels

Emissions at least 6 tons per year (NSPS)
                               Emission limits
                                   $203/$197
                               Oil/Natural Gas
Small Glycol Dehydrators

Production  and Transmission Segments (NESHAP)
                                Emission limits
                                    $60/$60
                                Oil/Natural Gas
Reporting and Recordkeeping

NSPS and NESHAP
                                      N/A
                                    $87/$60
                                Oil/Natural Gas

Table 7-2	Summary of Additional Per Completion/Recompletion Costs (2008$) for Environmental Controls Entered into NEMS

                           Emissions Sources/Points
                               Emissions Control
                         Per Completion Costs (2008$)
                           Wells Applied To in NEMS
Well Completions

Hydraulically Fractured New Natural Gas Wells
                                REC/Combustion
                                     -$271
                         New Tight Sand/ Shale Gas/CBM
Well Recompletions

Hydraulically Refractured Existing Natural Gas Wells
                                REC/Combustion
                                     -$604
                Existing Tight Sand/ Shale Gas /Coalbed Methane

Adding Averted Methane Emissions into Natural Gas Production
	A significant benefit of controlling VOC emissions from oil and natural gas production is that methane that would otherwise be lost to the atmosphere can be directed into the natural gas production stream.  We chose to model methane capture in NEMS as an increase in natural gas industry productivity, ensuring that, within the model, natural gas reservoirs are not decremented by production gains from methane capture.  We add estimates of the quantities of methane captured (or otherwise not vented or combusted) to the base quantities that the OGSM model supplies to the NGTDM model.  We subdivide the estimates of commercially valuable averted emissions by region and well type in order to more accurately portray the economics of implementing the environmental technology.  Adding the averted methane emissions in this manner has the effect of moving the natural gas supply curve to the right an increment consistent with the technically achievable emissions transferred into the production stream as a result of the final NSPS.
	We enter the increased natural gas recovery into NEMS on a per-well basis for new wells, following an estimation procedure similar to that of entering compliance costs into NEMS on a per-well basis for new wells.  For the final NSPS, we estimate that natural gas recovery is 2,473 Mcf per well.  We make a simplifying assumption that natural gas recovery accruing to new wells accrues to new wells in shale gas, tight sands, and CBM fields.  We make these assumptions because new wells in these fields are more likely to satisfy criteria such that RECs are required, which contributed that large majority of potential natural gas recovery.  Note that this per-well natural gas recovery estimate is lower than the per-well estimate when RECs are implemented.  The estimate is lower because we account for emissions that are combusted, REC that are implemented absent Federal regulation, as well as the likelihood that natural gas is used during processing and transmission or reinjected.
We treat the potential natural gas recovery associated with recompletions of existing wells differently in that we estimated the natural gas recovery by natural gas resource type based on a combination of the engineering analysis and production patterns from the 2011 Annual Energy Outlook.  We estimate that additional natural gas product recovered by recompleting existing wells to be about 3.4 bcf, with 1.6 bcf accruing to shale gas, 1.4 bcf accruing to tight sands, and 0.4 bcf accruing to CBM, respectively.  This quantity is distributed within the NGTDM to reflect regional production by resource type.
Fixing Canadian Drilling Costs to Baseline Path
Domestic drilling costs serve as a proxy for Canadian drilling costs in the Canadian oil and natural gas sub-model within the NGTDM.  This implies that, without additional modification, additional costs imposed by a U.S. regulation will also impact drilling decisions in Canada.   Changes in international oil and gas trade are important in the analysis, as a large majority of natural gas imported into the U.S. originates in Canada.  To avoid this problem, we fixed Canadian drilling costs using U.S. drilling costs from the baseline scenario.  This solution enables a more accurate analysis of U.S.-Canada energy trade, as increased drilling costs in the U.S. as a result of environmental regulation serve to increase Canada's comparative advantage.
Energy System Impacts
As mentioned earlier, we estimate impacts to drilling activity, reserves, 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, as well as whether and to what extent the final NSPS and NESHAP Amendments might alter the mix of fuels consumed at a national level.  In each of these estimates, we present estimates for the baseline year of 2015 and predicted results for 2015 under the final rules.  For context, we provide estimates of production activities in 2011.
Impacts on Drilling Activities
      Because the potential costs of the final rules are concentrated in production activities, we first report estimates of impacts on crude oil and natural gas drilling activities and production and price changes at the wellhead.  Table 7-3 presents estimates of successful wells drilled in the U.S. in 2015, the analysis year.

Table 7-3	Successful Oil and Gas Wells Drilled, NSPS

                             Future Scenario, 2015

                                     2011
                                   Baseline
                               Under Final NSPS

Successful Wells Drilled

Natural Gas
                                    16,373
                                    19,097
                                    19,162

Crude Oil
                                    10,352
                                    11,025
                                    11,025

Total
                                    26,725
                                    30,122
                                    30,164

% Change in Successful Wells Drilled from Baseline

Natural Gas

                                     0.34%

Crude Oil

                                     0.00%

Total

                                     0.22%

We estimate that the number of successful natural gas wells drilled increases slightly for the final NSPS, while the number of successful crude oil wells drilled does not change.  The number of successful natural gas wells drilled is estimated to increase about 0.34%.  Table 7-4 presents the forecast of successful wells by well type, for onshore drilling in the lower 48 states.  The results show that conventional well drilling is unaffected by the NSPS, as reduced emission completion and completion combustion requirements are directed not toward wells in conventional reserves but toward wells that are hydraulically fractured, the wells in so-called unconventional reserves.  The number of successful wells drilled increase in tight sands, shale gas, as well as coalbed methane.

Table 7-4	Successful Wells Drilled by Well Type (Onshore, Lower 48 States), NSPS

                             Future Scenario, 2015

                                     2011
                                   Baseline
                               Under Final NSPS

Successful Wells Drilled

Conventional Gas Wells
                                     7,267
                                     7,607
                                     7,607

Tight Sands
                                     2,441
                                     2,772
                                     2,785

Shale Gas
                                     5,007
                                     7,022
                                     7,066

Coalbed Methane
                                     1,593
                                     1,609
                                     1,618

Total
                                    16,308
                                    19,010
                                    19,076

% Change in Successful Wells Drilled from Baseline

Conventional Gas Wells

                                     0.00%

Tight Sands

                                     0.47%

Shale Gas

                                     0.63%

Coalbed Methane

                                     0.56%

Total

                                     0.35%

Well drilling in tight sands is estimated to increase slightly, about 0.47 percent.  Drilling in shale gas is forecast to increase from the baseline by 0.63 percent.  Wells in CBM reserves are also estimated to increase from the baseline by 0.56 percent.
Impacts on Production, Prices, and Consumption
Table 7-5 shows estimates of the changes in the domestic production of natural gas and crude oil under the final NSPS and NESHAP Amendments, as of 2015.  Domestic natural gas and crude oil production are not forecast to change under the final rules, again because impacts of the rules are expected to be negligible.

Table 7-5	Annual Domestic Natural Gas and Crude Oil Production, NSPS

                             Future Scenario, 2015

                                     2011
                                   Baseline
                               Under Final NSPS
Domestic Production

Natural Gas (trillion cubic feet)
                                     21.05
                                     22.43
                                     22.43

Crude Oil (million barrels/day)
                                     5.46
                                     5.81
                                     5.81

Natural Gas

                                     0.00%

Crude Oil

                                     0.00%

The NEMS analysis estimates no increase in domestic natural gas production.  This amount is less than the amount estimated in the engineering analysis to be captured by emissions controls implemented as a result of the NSPS (approximately 43 bcf).  This difference is because NEMS models the adjustment of energy markets to the now relatively more efficient natural gas production sector.  At the new post-rule equilibrium, producers implementing emissions controls still capture and sell approximately 43 bcf of natural gas.  For example, as shown in Table 7-4, about 11,400 new unconventional natural gas wells are completed under the final NSPS; using assumptions from the engineering cost analysis about voluntary RECs performed, RECs required under State regulations and exploratory wells and relatively low pressure wells exempted from REC requirements, about 4,100 NSPS-required RECs would be performed on new natural gas well completions, according to the NEMS analysis, not including the recompletions of existing wells.  This recovered natural gas substitutes for natural gas that would be produced from the ground absent the rule.  In effect, then, the natural gas that would have been extracted and emitted into the atmosphere is left in the formation for future extraction, according to these results.
As we showed for natural gas drilling, Table 7-6 shows natural gas production from onshore wells in the lower 48 states by type of well, predicted for 2015, the analysis year.  With the exception of tight sands, production from all types of wells is estimated to increase under the final rules.  However, the decrease in production from tight sands is estimated to offset the slight production increases estimated in conventional, shale, and coalbed methane formations.
Table 7-6	Natural Gas Production by Well Type (Onshore, Lower 48 States), NSPS

                             Future Scenario, 2015

                                     2011
                                   Baseline
                               Under Final NSPS
Natural Gas Production by Well Type (trillion cubic feet)

Conventional Gas Wells
                                     4.06
                                     3.74
                                     3.75

Tight Sands
                                     5.96
                                     5.89
                                     5.85

Shale Gas
                                     5.21
                                     7.20
                                     7.24

Coalbed Methane
                                     1.72
                                     1.67
                                     1.68

Total
                                     16.95
                                     18.51
                                     18.51

% Change in Natural Gas Production by Well Type from Baseline

Conventional Gas Wells

                                     0.27%

Tight Sands

                                    -0.68%

Shale Gas

                                     0.56%

Coalbed Methane

                                     0.60%

Total

                                     0.05%
Note: Totals may not sum due to independent rounding.
Table 7-7 presents estimates of national average wellhead natural gas and crude oil prices for onshore production in the lower 48 states, estimated for 2015, the year of analysis.  Wellhead natural gas price are not forecast to change under the final rules, while crude oil prices are forecast to decrease slightly under the NSPS.
Table 7-7	Lower 48 Average Natural Gas and Crude Oil Wellhead Price, NSPS

                             Future Scenario, 2015

                                     2011
                                   Baseline
                               Under Final NSPS
Lower 48 Average Wellhead Price

Natural Gas (2008$ per Mcf)
                                     4.07
                                     4.22
                                     4.22

Crude Oil (2008$ per barrel)
                                     83.65
                                     94.60
                                     94.59

% Change in Lower 48 Average Wellhead Price from Baseline

Natural Gas

                                     0.00%

Crude Oil

                                    -0.01%

Table 7-8 presents estimates of the price of natural gas to final consumers in 2008 dollars per million BTU.  Commercial and industrial sector consumers of natural gas are estimated to receive slight price increases, while the national average price to consumers of natural gas is not estimated to change.

Table 7-8	Delivered Natural Gas Prices by Sector (2008$ per million BTU), 2015, NSPS

                             Future Scenario, 2015

                                     2011
                                   Baseline
                               Under Final NSPS
Delivered Prices (2008$ per million BTU)

Residential
                                     10.52
                                     10.35
                                     10.35

Commercial
                                     9.26
                                     8.56
                                     8.57

Industrial
                                     4.97
                                     5.07
                                     5.08

Electric Power
                                     4.81
                                     4.77
                                     4.77

Transportation
                                     12.30
                                     12.24
                                     12.24

Average
                                     6.76
                                     6.59
                                     6.59

% Change in Delivered Prices from Baseline

Residential

                                     0.00%

Commercial

                                     0.12%

Industrial

                                     0.20%

Electric Power

                                     0.00%

Transportation

                                     0.00%

Average

                                     0.00%

Final consumption of natural gas is not estimated to change in 2015 from the baseline under the final rules, as is shown on Table 7-9.  Like delivered price, the consumption shifts are distributed differently across sectors.

Table 7-9	Natural Gas Consumption by Sector, NSPS

                             Future Scenario, 2015

                                     2011
                                   Baseline
                               Under Final NSPS
Consumption (trillion cubic feet)

Residential
                                     4.76
                                     4.81
                                     4.81

Commercial
                                     3.22
                                     3.38
                                     3.38

Industrial
                                     6.95
                                     8.05
                                     8.06

Electric Power
                                     7.00
                                     6.98
                                     6.97

Transportation
                                     0.03
                                     0.04
                                     0.04

Pipeline Fuel
                                     0.64
                                     0.65
                                     0.65

Lease and Plant Fuel
                                     1.27
                                     1.20
                                     1.20

Total
                                     23.86
                                     25.11
                                     25.11

% Change in Consumption from Baseline

Residential

                                     0.00%

Commercial

                                     0.00%

Industrial

                                     0.12%

Electric Power

                                    -0.14%

Transportation

                                     0.00%

Pipeline Fuel

                                     0.00%

Lease and Plant Fuel

                                     0.00%

Total

                                     0.00%
Note: Totals may not sum due to independent rounding.

Impacts on Imports and National Fuel Mix
The NEMS modeling estimates that the impacts from the NSPS and NEHSAP Amendments are not sufficiently large to affect the trade balance of natural gas.  As shown in Table 7-10, estimates of crude oil imports do not vary from the baseline in 2015 under the NSPS.

Table 7-10	Net Imports of Natural Gas and Crude Oil, NSPS

                             Future Scenario, 2015

                                     2011
                                   Baseline
                               Under Final NSPS
Net Imports

Natural Gas (trillion cubic feet)
                                     2.75
                                     2.69
                                     2.69

Crude Oil (million barrels/day)
                                     9.13
                                     8.70
                                     8.70

% Change in Net Imports

Natural Gas

                                     0.00%

Crude Oil

                                     0.00%

Meanwhile, net imports of natural gas are estimated to decrease about 10 bcf (0.37 percent) under the NSPS, as the increased production substitutes for imported natural gas.
Table 7-11 evaluates estimates of energy consumption by energy type at the national level for 2015, the year of analysis.  The NSPS is estimated to have small effects at the national level.  We estimate an increase in 0.01 quadrillion BTU in 2015, a 0.01 percent increase.  The percent contribution of natural gas, coal, and biomass is projected to increase slightly in 2015.

Table 7-11	Total Energy Consumption by Energy Type (Quadrillion BTU), NSPS

                             Future Scenario, 2015

                                     2011
                                   Baseline
                               Under Final NSPS
Consumption (quadrillion BTU)

Liquid Fuels
                                     37.41
                                     39.10
                                     39.10

Natural Gas
                                     24.49
                                     25.77
                                     25.78

Coal
                                     20.42
                                     19.73
                                     19.74

Nuclear Power
                                     8.40
                                     8.77
                                     8.77

Hydropower
                                     2.58
                                     2.92
                                     2.92

Biomass
                                     2.98
                                     3.27
                                     3.28

Other Renewable Energy
                                     1.72
                                     2.14
                                     2.14

Other
                                     0.30
                                     0.31
                                     0.31

Total
                                     98.29
                                    102.02
                                    102.03

% Change in Consumption from Baseline

Liquid Fuels

                                     0.00%

Natural Gas

                                     0.04%

Coal

                                     0.05%

Nuclear Power

                                     0.00%

Hydropower

                                     0.00%

Biomass

                                     0.31%

Other Renewable Energy

                                     0.00%

Other

                                     0.00%

Total

                                     0.01%
Note: Totals may not sum due to independent rounding.

With the national profile of energy consumption estimated to change slightly under the NSPS in 2015, the year of analysis, it is important to examine whether aggregate energy-related CO2-equivalent greenhouse gas (GHG) emissions also shift.  A more detailed discussion of changes in CO2-equivalent GHG emissions from a baseline is presented within the benefits analysis in Section 4.  Here, we present a single NEMS-based table showing estimated changes in energy-related "consumer-side" GHG emissions.  We use the terms "consumer-side" emissions to distinguish emissions from the consumption of fuel from emissions specifically associated with the extraction, processing, and transportation of fuels in the oil and natural gas sector under examination in this RIA.  We term the emissions associated with extraction, processing, and transportation of fuels "producer-side" emissions.

Table 7-12	Modeled Change in Energy-related "Consumer-Side" CO2-equivalent GHG Emissions

                             Future Scenario, 2015

                                     2011
                                   Baseline
                               Under Final NSPS
Energy-related CO2-equivalent GHG Emissions (million metric tons CO2-equivalent)

Petroleum
                                   2,359.59
                                   2,433.60
                                   2,433.53

Natural Gas
                                   1,283.78
                                   1,352.20
                                   1,352.24

Coal
                                   1,946.02
                                   1,882.08
                                   1,882.76

Other
                                     11.99
                                     11.99
                                     11.99

Total
                                   5,601.39
                                   5,679.87
                                   5,680.52

% Change in Energy-related CO2-equivalent GHG Emissions from Baseline

Petroleum

                                     0.00%

Natural Gas

                                     0.00%

Coal

                                     0.04%

Other

                                     0.00%

Total

                                     0.01%
Note: Excludes "producer-side" emissions and emissions reductions estimated to result from NSPS. Totals may not sum due to independent rounding.

As is shown in Table 7-12, the final rules are  predicted to slightly increase consumer-side aggregate energy-related CO2-equivalent GHG emissions by about 650,000 metric tons (0.01 percent), mainly because consumer-side emissions from coal combustion increase slightly as a result of the slight consumption increases noted in Table 7-11.
Employment Impact Analysis
While a standalone analysis of employment impacts is not included in a standard cost-benefit analysis, such an analysis is of particular concern in the current economic climate of sustained high unemployment. Executive Order 13563, states, "Our regulatory system must protect public health, welfare, safety, and our environment while promoting economic growth, innovation, competitiveness, and job creation" (emphasis added).  Therefore, we seek to inform the discussion of labor demand and job impacts by providing an estimate of the employment impacts of the regulations using labor requirements for the installation, operation, and maintenance of control requirements, as well as reporting and recordkeeping requirements.  Unlike several recent RIAs, however, we do not provide employment impacts estimates based on the study by Morgenstern et al. (2002); we discuss this decision after presenting estimates of the labor requirements associated with reporting and recordkeeping and the installation, operation, and maintenance of control requirements.
Employment Impacts from Pollution Control Requirements
Regulations set in motion new orders for pollution control equipment and services. New categories of employment have been created in the process of implementing regulations to make our air safer to breathe. When a new regulation is promulgated, a response of industry is to order pollution control equipment and services in order to comply with the regulation when it becomes effective.  Revenue and employment in the environmental technology industry have grown steadily between 2000 and 2008, reaching an industry total of approximately $300 billion in revenues and 1.7 million employees in 2008.  While these revenues and employment figures represent gains for the environmental technologies industry, they are costs to the regulated industries required to install the equipment.  Moreover, it is not clear the 1.7 million employees in 2008 represent new employment as opposed to workers being shifted from the production of goods and services to environmental compliance activities.
Once the equipment is installed, regulated firms hire workers to operate and maintain the pollution control equipment  -  much like they hire workers to produce more output. Morgenstern et al. (2002) examined how regulated industries respond to regulation.  Morgenstern et al. identified three separate components of the employment change in response to a regulation:
   * Higher production costs raise market prices, higher prices reduce consumption (and production), reducing demand for labor within the regulated industry  ("demand effect");
   * As costs go up, plants add more capital and labor.  For example, pollution abatement activities require additional labor services to produce the same level of output ("cost effect");
   * Post-regulation production technologies may be more or less labor intensive (i.e., more/less labor is required per dollar of output) ("factor-shift effect").
The authors found that, on average for the industries they studied, employment increases in regulated firms. Of course, these firms may also reassign existing employees to perform these activities.
Environmental regulations support employment in many basic industries. In addition to the increase in employment in the environmental protection industry (via increased orders for pollution control equipment), environmental regulations also support employment in industries that provide intermediate goods to the environmental protection industry.  The equipment manufacturers, in turn, order steel, tanks, vessels, blowers, pumps, and chemicals to manufacture and install the equipment.
The focus of this part of the analysis is on labor requirements related to the compliance actions of the affected entities within the affected sector.  We do not estimate any potential changes in labor outside of the oil and natural gas sector.  This analysis estimates the employment impacts due to the installation, operation, and maintenance of control equipment, as well as employment associated with new reporting and recordkeeping requirements.
It is important to highlight that unlike the typical case where to reduce a bad output (i.e., emissions) a firm often has to reduce production of the good output, many of the emission controls required by the final NSPS will simultaneously increase production of the good output and reduce production of bad outputs. That is, these controls jointly produce environmental improvements and increase output in the regulated sector.  New labor associated with implementing these controls to comply with the new regulations can also be viewed as additional labor increasing output while reducing undesirable emissions.  To the extent, however, that these rules may require unprofitable investments for some operators, there is a possibility that these producers decrease output in response and create downward pressure on labor demand, both in the regulated sector and on those sectors using natural gas as an input. This RIA excludes these potential adverse effects on the labor market.
No estimates of the labor used to manufacture or assemble pollution control equipment or to supply the materials for manufacture or assembly are included because U.S. EPA does not currently have this information.  The employment analysis uses a bottom-up engineering-based methodology to estimate employment impacts.  The engineering cost analysis summarized in this RIA includes estimates of the labor requirements associated with implementing the regulations.  Each of these labor changes may either be required as part of an initial effort to comply with the new regulation or required as a continuous or annual effort to maintain compliance.  We estimate up-front and continual, annual labor requirements by estimating hours of labor required and converting this number to full-time equivalents (FTEs) by dividing by 2,080 (40 hours per week multiplied by 52 weeks).  We note that this type of FTE estimate cannot be used to make assumptions about the specific number of people involved or whether new jobs are created for new employees.
	In other employment analyses U.S. EPA distinguished between employment changes within the regulated industry and those changes outside the regulated industry (e.g. a contractor from outside the regulated facility is employed to install a control device).  For this regulation however, the structure of the industry makes this difficult.  The mix of in-house versus contracting services used by firms is very case-specific in the oil and natural gas industry.  For example, sometimes the owner of the well, processing plant, or transmission pipelines uses in - house employees extensively in daily operations, while in other cases the owner relies on outside contractors for many of these services.  For this reason, we make no distinction in the quantitative estimates between labor changes within and outside of the regulated sector.
	The results of this employment estimate are presented in Table 7-13 for the final NSPS and in Table 7-14 for the final NESHAP Amendments.  The tables breaks down the installation, operation, and maintenance estimates by type of pollution control evaluated in the RIA and present both the estimated hours required and the conversion of this estimate to FTE.  For both the final NSPS and NESHAP Amendments, reporting and recordkeeping requirements were estimated for the entire rules rather than by anticipated control requirements; the reporting and recordkeeping estimates are consistent with estimates EPA submitted as part of its Information Collection Request (ICR).
      The up-front labor requirement is estimated at 50 FTEs for the final NSPS and about 4 FTEs for the final NESHAP Amendments.  These up-front FTE labor requirements can be viewed as short-term labor requirements required for affected entities to comply with the new regulation.  Ongoing requirements are estimated at about 570 FTEs for the final NSPS and about 30 FTEs for the final NESHAP Amendments.  These ongoing FTE labor requirements can be viewed as sustained labor requirements required for affected entities to continuously comply with the new regulation.
      Two main categories contain the majority of the labor requirements for the final rules: implementing reduced emissions completions (REC) and reporting and recordkeeping requirements for the final NSPS.  Also, note that pneumatic controllers have no up-front or continuing labor requirements.  While the controls do require labor for installation, operation, and maintenance, the required labor is less than that of the controllers that would be used absent the regulation.  In this instance, we assume the incremental labor requirements are zero.
      Implementing RECs are estimated to require about 500 FTE, about 87 percent of the total continuing labor requirements for the final NSPS.  We denote REC-related requirements as continuing, or annual, as the REC requirements will in fact recur annually, albeit at different wells each year.  The REC requirements are associated with certain new well completions or existing well recompletions.  While individual completions occur over a short period of time (days to a few weeks), new wells and other existing wells are completed or recompleted annually.  Because of these reasons, we assume the REC-related labor requirements are annual.
Employment Impacts Primarily on the Regulated Industry
In previous RIAs, we transferred parameters from a study by Morgenstern et al. (2002) to estimate employment effects of new regulations.  (See, for example, the Regulatory Impact Analysis for the finalized Mercury and Air Toxics Standards, promulgated on December 16, 2011).  The fundamental insight of Morgenstern, et al. is that environmental regulations can be understood as requiring regulated firms to add a new output (environmental quality) to their product mixes. Although legally compelled to satisfy this new demand, regulated firms have to finance this additional production with the proceeds of sales of their other (market) products. Satisfying this new demand requires additional inputs, including labor, and may alter the relative proportions of labor and capital used by regulated firms in their production processes.
Using plant-level Census information between the years 1979 and 1991, Morgenstern et al. estimate the size of each effect for four polluting and regulated industries (petroleum refining, plastic material, pulp and paper, and steel). On average across the four industries, each additional $1 million (1987$) spending on pollution abatement results in a (statistically insignificant) net increase of 1.55 (+/- 2.24) jobs. As a result, the authors conclude that increases in pollution abatement expenditures did not necessarily cause economically significant employment changes in those industries at that time.
      For this version of the RIA for the final NSPS and NESHAP Amendments, however, we chose not to quantitatively estimate employment impacts using Morgenstern et al. because of reasons specific to the oil and natural gas industry and the final rules.  We believe the transfer of parameter estimates from the Morgenstern et al. study to the final NSPS and NESHAP Amendments is beyond the range of the study for two reasons.
Table 7-13	Labor-based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and Maintaining Control Equipment Requirements, NSPS, 2015
Source/Emissions Point
Emissions Control
                        Projected No. of Affected Units
                   Per Unit One-time Labor Estimate (hours)
                    Per Unit Annual Labor Estimate (hours)
                     Total One-Time Labor Estimate (hours)
                      Total Annual Labor Estimate (hours)
                         One-time Full-Time Equivalent
                          Annual Full-Time Equivalent
Well Completions and Recompletions

New Hydraulically Fractured Gas Wells
REC/Combustion
                                                                          4,107
                                                                              0
                                                                            218
                                                                              0
                                                                        893,397
                                                                              0
                                                                            430

New Hydraulically Fractured Gas Wells
Combustion
                                                                          1,377
                                                                              0
                                                                             22
                                                                              0
                                                                         29,719
                                                                              0
                                                                             14

Hydraulically Re-fractured Gas Wells
REC/Combustion
                                                                            532
                                                                              0
                                                                            218
                                                                              0
                                                                        115,721
                                                                              0
                                                                             56

Hydraulically Re-fractured Gas Wells
Combustion
                                                                            121
                                                                              0
                                                                             22
                                                                              0
                                                                          2,611
                                                                              0
                                                                              1
Equipment Leaks

Processing Plants
NSPS Subpart VVA
                                                                             29
                                                                            587
                                                                            887
                                                                         17,023
                                                                         25,723
                                                                              8
                                                                             12
Reciprocating Compressors

Gathering and Boosting Stations
Annual Monitoring/ Maintenance (AMM)
                                                                            210
                                                                              1
                                                                              1
                                                                            210
                                                                            210
                                                                         < 1
                                                                         < 1

Processing Plants
AMM
                                                                            209
                                                                              1
                                                                              1
                                                                            209
                                                                            209
                                                                         < 1
                                                                         < 1
Centrifugal Compressors

Processing Plants
Route to Control
                                                                             13
                                                                            355
                                                                              0
                                                                          4,615
                                                                              0
                                                                              2
                                                                              0
Pneumatic Controllers

Oil and Gas Production
Low Bleed/Route to Process
                                                                         13,632
                                                                              0
                                                                              0
                                                                              0
                                                                              0
                                                                              0
                                                                              0
Storage Vessels

Emissions at least 6 tons per year
95% control
                                                                            304
                                                                            271
                                                                            190
                                                                         82,279
                                                                         57,582
                                                                             40
                                                                             28
Reporting and Recordkeeping for Complete NSPS
                                                                            All
                                                                            N/A
                                                                            N/A
                                                                              0
                                                                         68,882
                                                                            0.0
                                                                             33
TOTAL

                                                                            N/A
                                                                            N/A
                                                                            N/A
                                                                        104,336
                                                                      1,194,055
                                                                             50
                                                                            574
Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks).  Totals may not sum due to independent rounding.

Table 7-14	Labor-based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and Maintaining Control Equipment Requirements, Final NESHAP Amendments, 2015
Source/Emissions Point
Emissions Control
                        Projected No. of Affected Units
                   Per Unit One-time Labor Estimate (hours)
                    Per Unit Annual Labor Estimate (hours)
                     Total One-Time Labor Estimate (hours)
                      Total Annual Labor Estimate (hours)
                         One-time Full-Time Equivalent
                          Annual Full-Time Equivalent
Small Glycol Dehydrators

Production
Combustion devices, recovery devices, process modifications
                                                                             74
                                                                             27
                                                                            285
                                                                          2,000
                                                                         21,120
                                                                              1
                                                                             10

Transmission
Combustion devices, recovery devices, process modifications
                                                                              7
                                                                             27
                                                                            285
                                                                            189
                                                                          1,998
                                                                          <1
                                                                              1
Reporting and Recordkeeping for Complete NESHAP Amendments
                                                                            N/A
                                                                            N/A
                                                                            N/A
                                                                          6,442
                                                                         38,923
                                                                              3
                                                                             19
TOTAL

                                                                             81
                                                                            N/A
                                                                            N/A
                                                                          8,631
                                                                         62,040
                                                                              4
                                                                             30
Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to independent rounding.
First, the possibility that the revenues producers are estimated to receive from additional natural gas recovery as a result of the final NSPS might offset the costs of complying with the rule presents challenges to estimating employment effects (see Section <IP_ADDRESS> of the RIA for a detailed discussion of the natural gas recovery).  The Morgenstern et al. paper, for example, is intended to analyze the impact of environmental compliance expenditures on industry employment levels, and it may not be appropriate to draw on their demand and net effects when compliance costs are expected to be negative.
Second, the final regulations primarily affect the natural gas production, processing, and transmission segments of the industry.  While the natural gas processing segment of the oil and natural gas industry is similar to petroleum refining, which is examined in Morgenstern et al., the production side of the oil and natural gas industry (drilling and extraction, primarily) and natural gas pipeline transmission are not similar to petroleum refining.  Because of the likelihood of negative compliance costs for the final NSPS and because the segments of the oil and natural gas industry affected by the rules are not examined by Morgenstern et al., we decided not to use the parameters estimated by Morgenstern et al. to estimate within-industry employment effects for the final oil and natural gas NESHAP Amendments and NSPS.
That said, the likelihood of additional natural gas recovery is an important component of the market response to the rule, as it is expected that this additional natural gas recovery will reduce the price of natural gas.  Because of the estimated fall in prices in the natural gas sector due to the final NSPS, prices in other sectors that consume natural gas are likely drop slightly due to the decrease in energy prices.  This small production increase and price decrease may have a slight stimulative effect on employment in industries that consume natural gas.
Small Business Impacts Analysis
     The Regulatory Flexibility Act 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.
After considering the economic impact of the final rules on small entities for both the NESHAP Amendments and NSPS, the analysis indicates that these rules will not have a significant economic impact on a substantial number of small entities (or "SISNOSE").  The supporting analyses for these determinations are presented in this section of the RIA.
As discussed in previous sections of the economic impact analysis, under the final NSPS, some affected producers are likely to be able to recover natural gas that would otherwise be vented to the atmosphere, as well as recover saleable condensates that would otherwise be emitted.  EPA estimates that the revenues from this additional natural gas product recovery will offset the costs of implementing control options as a result of the final NSPS.  However, not all components of the final NSPS are estimated to have cost savings.  Therefore, we analyze potential impacts to better understand the potential distribution of impacts across industry segments and firms.  Unlike the controls for the final NSPS, the controls evaluated under the final NESHAP Amendments do not recover significant quantities of natural gas products.
	This small entity impacts analysis uses the primary baseline used for the impacts analysis of our NSPS.  This primary baseline takes into account RECs conducted pursuant to state regulations covering these operations and estimates of RECs performed voluntarily.  To estimate emissions reductions and compliance costs arising from these voluntary RECs, EPA used information reported to EPA by partners of the EPA Natural Gas STAR.  More detailed discussion on the derivation of the baseline is presented in a technical memorandum in the docket, as well as in Section 3 of this RIA.
Small Business National Overview
The industry sectors covered by the final rule were identified during the development of the engineering cost analysis.  The U.S. Census Bureau's Statistics of U.S. Businesses (SUSB) provides national information on the distribution of economic variables by industry and enterprise size. The Census Bureau and the Office of Advocacy of the Small Business Administration (SBA) supported and developed these files for use in a broad range of economic analyses.  Statistics include the total number of establishments and receipts for all entities in an industry; however, many of these entities may not necessarily be covered by the final rule. SUSB also provides statistics by enterprise employment and receipt size (Table 7-15 and Table 7-16).
The Census Bureau's definitions used in the SUSB are as follows:
         #          Establishment: A single physical location where business is conducted or where services or industrial operations are performed.
         #          Firm: A firm is a business organization consisting of one or more domestic establishments in the same state and industry that were specified under common ownership or control. The firm and the establishment are the same for single-establishment firms. For each multi-establishment firm, establishments in the same industry within a state will be counted as one firm- the firm employment and annual payroll are summed from the associated establishments.
         #          Receipts: Receipts (net of taxes) are defined as the revenue for goods produced, distributed, or services provided, including revenue earned from premiums, commissions and fees, rents, interest, dividends, and royalties. Receipts exclude all revenue collected for local, state, and federal taxes.
         #          Enterprise: An enterprise is a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise -- the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the sum of employment of all associated establishments.

Because the SBA's business size definitions (SBA, 2008) apply to an establishment's "ultimate parent company," we assumed in this analysis that the "firm" definition above is consistent with the concept of ultimate parent company that is typically used for SBREFA analyses, and the terms are used interchangeably.

Table 7-15	Number of Firms, Total Employment, and Estimated Receipts by Firm Size and NAICS, 2007

                             Owned by Firms with:

                                     NAICS
                               NAICS Description
                  SBA Size Standard (effective Nov. 5, 2010)
                               < 20 Employees
                                20-99 Employees
                               100-499 Employees
                           Total < 500 Employees
                              > 500 Employees
                                  Total Firms
Number of Firms by Firm Size

                                    211111
Crude Petroleum and Natural Gas Extraction
                                      500
                                                                          5,759
                                                                            455
                                                                            115
                                                                          6,329
                                                                             95
                                                                          6,424
                                    211112
Natural Gas Liquid Extraction
                                      500
                                                                             77
                                                                              9
                                                                             12
                                                                             98
                                                                             41
                                                                            139
                                    213111
Drilling Oil and Gas Wells
                                      500
                                                                          1,580
                                                                            333
                                                                             97
                                                                          2,010
                                                                             49
                                                                          2,059
                                    486210
Pipeline Transportation of Natural Gas
                                 $7.0 million
                                                                             63
                                                                             12
                                                                              9
                                                                             84
                                                                             42
                                                                            126

Total Employment by Firm Size

                                    211111
Crude Petroleum and Natural Gas Extraction
                                      500
                                                                         21,170
                                                                         16,583
                                                                         17,869
                                                                         55,622
                                                                         77,664
                                                                        133,286
                                    211112
Natural Gas Liquid Extraction
                                      500
                                                                            372
                                                                            305
                                                                          1,198
                                                                          1,875
                                                                          6,648
                                                                          8,523
                                    213111
Drilling Oil and Gas Wells
                                      500
                                                                          5,972
                                                                         13,787
                                                                         16,893
                                                                         36,652
                                                                         69,774
                                                                        106,426
                                    486210
Pipeline Transportation of Natural Gas
                                 $7.0 million
                                                                            241
                                                                            382
                                                                          1,479
                                                                          2,102
                                                                         22,581
                                                                         24,683

Estimated Receipts by Firm Size ($1000)

                                    211111
Crude Petroleum and Natural Gas Extraction
                                      500
                                                                     12,488,688
                                                                     15,025,443
                                                                     17,451,805
                                                                     44,965,936
                                                                    149,141,316
                                                                    194,107,252
                                    211112
Natural Gas Liquid Extraction
                                      500
                                                                        209,640
                                                                        217,982
                                                                      1,736,706
                                                                      2,164,328
                                                                     37,813,413
                                                                     39,977,741
                                    213111
Drilling Oil and Gas Wells
                                      500
                                                                      1,101,481
                                                                      2,460,301
                                                                      3,735,652
                                                                      7,297,434
                                                                     16,550,804
                                                                     23,848,238
                                    486210
Pipeline Transportation of Natural Gas
                                 $7.0 million
                                                                        332,177
                                                                        518,341
                                                                      1,448,020
                                                                      2,298,538
                                                                     18,498,143
                                                                     20,796,681
Source:	U.S. Census Bureau. 2010. "Number of Firms, Number of Establishments, Employment, Annual Payroll, and Estimated Receipts by Enterprise Receipt Size for the United States, All Industries:  2007." <http://www.census.gov/econ/susb/>

Table 7-16	Distribution of Small and Large Firms by Number of Firms, Total Employment, and Estimated Receipts by Firm Size and NAICS, 2007

                               Percent of Firms
                                     NAICS
                               NAICS Description
                                  Total Firms
                               Small Businesses
                               Large Businesses
                                  Total Firms
Number of Firms by Firm Size

                                    211111
Crude Petroleum and Natural Gas Extraction
                                                                          6,424
                                                                          98.5%
                                                                           1.5%
                                                                         100.0%
                                    211112
Natural Gas Liquid Extraction
                                                                            139
                                                                          70.5%
                                                                          29.5%
                                                                         100.0%
                                    213111
Drilling Oil and Gas Wells
                                                                          2,059
                                                                          97.6%
                                                                           2.4%
                                                                         100.0%
                                    486210
Pipeline Transportation of Natural Gas
                                                                            126
                                                                          48.4%
                                                                          51.6%
                                                                         100.0%

Total Employment by Firm Size

                                    211111
Crude Petroleum and Natural Gas Extraction
                                                                        133,286
                                                                          41.7%
                                                                          58.3%
                                                                         100.0%
                                    211112
Natural Gas Liquid Extraction
                                                                          8,523
                                                                          22.0%
                                                                          78.0%
                                                                         100.0%
                                    213111
Drilling Oil and Gas Wells
                                                                        106,426
                                                                          34.4%
                                                                          65.6%
                                                                         100.0%
                                    486210
Pipeline Transportation of Natural Gas
                                                                         24,683
                                                                           N/A*
                                                                           N/A*
                                                                           N/A*

Estimated Receipts by Firm Size ($1000)

                                    211111
Crude Petroleum and Natural Gas Extraction
                                                                    194,107,252
                                                                          23.2%
                                                                          76.8%
                                                                         100.0%
                                    211112
Natural Gas Liquid Extraction
                                                                     39,977,741
                                                                           5.4%
                                                                          94.6%
                                                                         100.0%
                                    213111
Drilling Oil and Gas Wells
                                                                     23,848,238
                                                                          30.6%
                                                                          69.4%
                                                                         100.0%
                                    486210
Pipeline Transportation of Natural Gas
                                                                     20,796,681
                                                                           N/A*
                                                                           N/A*
                                                                           N/A*
Note: Employment and receipts could not be broken down between small and large businesses because of non-disclosure requirements.
Source: SBA

While the SBA and Census Bureau statistics provide informative broad contextual information on the distribution of enterprises by receipts and number of employees, it is also useful to additionally contrast small and large enterprises (where large enterprises are defined as those that are not small, according to SBA criteria) in the oil and natural gas industry.  The summary statistics presented in previous tables indicate that there are a large number of relatively small firms and a small number of large firms.  Given the majority of expected impacts of the final rules arises from well completion-related requirements, which impacts production activities, exclusively, some explanation of this particular market structure is warranted as it pertains to production and small entities.  An important question to answer is whether there are particular roles that small entities serve in the production segment of the oil and natural gas industry that may be disproportionately affected by the final rules.
      The first important broad distinction among firms is whether they are independent or integrated.  Independent firms concentrate on exploration and production (E&P) activities, while integrated firms are vertically integrated and often have operations in E&P, processing, refining, transportation, and retail.  To our awareness, there are no small integrated firms.  Independent firms may own and operate wells or provide E&P-related services to the oil and gas industry.  Since we are focused on evaluating potential impacts to small firms owning and operating new and existing hydraulically fractured wells, we should focus on this sector.
      In our understanding, there is no single industry niche for small entities in the production segment of the industry since small operators have different business strategies and that small entities can own different types of wells.  The organization of firms in the oil and natural gas industry also varies greatly from firm to firm.  Additionally, oil and natural gas resources vary widely geographically and can vary significantly within a single field.
      Among many important roles, independent small operators historically pioneered exploration in new areas, as well as developed new technologies.  By taking on these relatively large risks, these small entrepreneurs (wildcatters) have been critical sources of industrial innovation and opened up critical new energy supplies for the U.S. (IHS Global Insight).  In recent decades, as the oil and gas industry has concentrated via mergers, many of these smaller firms have been absorbed into large firms.
      Another critical role, which provides an interesting contrast to small firms pioneering new territory, is that smaller independents maintain and operate a large proportion of the Nation's low producing wells, which are also known as marginal or stripper wells (Duda et al. 2005).  While marginal wells represent about 80 percent of the population of producing wells, they produce about 15 percent of domestic production, according to EIA (Table 7-17).

Table 7-17	Distribution of Crude Oil and Natural Gas Wells by Productivity Level, 2009
Type of Wells
                                  Wells (no.)
                                   Wells (%)
                    Production (MMbbl for oil and Bcf gas)
                                Production (%)
Crude Oil

Stripper Wells (<15 boe per year)
                                                                        310,552
                                                                            85%
                                                                            311
                                                                            19%

Other Wells (>=15 boe per year)
                                                                         52,907
                                                                            15%
                                                                          1,331
                                                                            81%

Total Crude Oil Wells
                                                                        363,459
                                                                           100%
                                                                          1,642
                                                                           100%
Natural Gas

Natural Gas Stripper Wells (<15 boe per year)
                                                                        338,056
                                                                            73%
                                                                          2,912
                                                                            12%

Other Natural Gas Wells (>=15 boe per year)
                                                                        123,332
                                                                            27%
                                                                         21,048
                                                                            88%

Total Natural Gas Wells
                                                                        461,388
                                                                           100%
                                                                         23,959
                                                                           100%
Source: U.S. Energy Information Administration, Distribution of Wells by Production Rate Bracket. <http://www.eia.gov/pub/oil_gas/petrosystem/us_table.html> Accessed 7/10/11.
Note: Natural gas production converted to barrels oil equivalent (boe) uses the conversion of 0.178 barrels of crude oil to 1000 cubic feet of natural gas.

      Many of these wells were likely drilled and initially operated by major firms (although the data are not available to quantify the percentage of wells initially drilled by small versus large producers).  Well productivity levels typically follow a steep decline curve; high production in earlier years but sustained low production for decades.  Because of relatively low overhead of maintaining and operating few relatively co-located wells, some small operators with a particular business strategy purchase low producing wells from the majors, who concentrate on new opportunities.   As small operators have provided important technical innovation in exploration, small operators have also been sources of innovation in extending the productivity and lifespan of existing wells (Duda et al. 2005).
Small Entity Economic Impact Measures
The final Oil and Natural Gas NSPS and NESHAP Amendments will affect the owners of the facilities that will incur compliance costs to control their regulated emissions. The owners, either firms or individuals, are the entities that will bear the financial impacts associated with these additional operating costs. The final rule has the potential to impact all firms owning affected facilities, both large and small.
The analysis provides EPA with an estimate of the magnitude of impacts the final NSPS and NESHAP Amendments may have on the ultimate domestic parent companies that own facilities EPA expects might be impacted by the rules. The analysis focuses on small firms because they may have more difficulty complying with a new regulation or affording the costs associated with meeting the new standard. This section presents the data sources used in the analysis, the methodology we applied to develop estimates of impacts, the results of the analysis, and conclusions drawn from the results.
The small business impacts analysis for the NSPS and NESHAP Amendments relies upon a series of firm-level sales tests (represented as cost-to-revenue ratios) for firms that are likely to be associated with NAICS codes listed in Table 7-15.  For both the NSPS and NESHAP Amendments, we obtained firm-level employment, revenues, and production levels using various sources, including the American Business Directory, the Oil and Gas Journal, corporate websites, and publically-available financial reports.  Using these data, we estimated firm-level compliance cost impacts and calculated cost-to-revenue ratios to identify small firms that might be significantly impacted by the rules.  The approaches taken for the NSPS and NESHAP Amendments differed; more detail on approaches for each set of rules is presented in the following sections.
For the sales test, we divided the estimates of annualized establishment compliance costs by estimates of firm revenue. This is known as the cost-to-revenue ratio, or the "sales test." The "sales test" is the impact methodology EPA employs in analyzing small entity impacts as opposed to a "profits test," in which annualized compliance costs are calculated as a share of profits.  The sales test is often used because revenues or sales data are commonly available for entities impacted by EPA regulations, and profits data normally made available are often not the true profit earned by firms because of accounting and tax considerations.  Revenues as typically published are correct figures and are more reliably reported when compared to profit data. The use of a "sales test" for estimating small business impacts for a rulemaking such as this one is consistent with guidance offered by EPA on compliance with SBREFA and is consistent with guidance published by the U.S. SBA's Office of Advocacy that suggests that cost as a percentage of total revenues is a metric for evaluating cost increases on small entities in relation to increases on large entities (U.S. SBA, 2010).
Small Entity Economic Impact Analysis, Final NSPS
Overview of Sample Data and Methods