Regulatory Impact Analysis

Final New Source Performance Standards and Amendments to the National Emissions Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry

                     U.S. Environmental Protection Agency
                          Office of Air and Radiation
                 Office of Air Quality Planning and Standards
                       Research Triangle Park, NC 27711

	April 2012

                              CONTACT INFORMATION

      This document has been prepared by staff from the Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency. Questions related to this document should be addressed to Alexander Macpherson, U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, C445-B, Research Triangle Park, North Carolina 27711 (email: macpherson.alex@epa.gov).

                               ACKNOWLEDGEMENTS
In addition to EPA staff from the Office of Air Quality Planning and Standards, personnel from the U.S. EPA Office of Atmospheric Programs, EC/R Incorporated, and ICF International contributed data and analysis to this document. Specific sections where EC/R Incorporated made contributions include the sections describing emissions options, pollution control options, secondary impacts analysis, engineering cost analysis, and employment impacts.  Specific sections where ICF International made contributions also include the sections describing emissions options, pollution control options, engineering cost analysis, employment impacts, and small business impacts.

 Table of Contents

Table of Contents	iii
List of Tables	vi
List of Figures	viii
1	Executive Summary	1-1
1.1	Background	1-1
1.2	Summary of Results	1-3
1.2.1	NSPS Results	1-3
1.2.2	NESHAP Amendments Results	1-6
1.2.3	Results of Energy System Impacts Analysis of the NSPS and NESHAP Amendments	1-8
1.2.4	Results for Combined Small Entity Analysis for the NSPS and NESHAP Amendments	1-8
1.3	Summary of NSPS Impacts Changes from the Proposal RIA	1-8
1.4	Summary of NESHAP Amendments Impacts Changes from the Proposal RIA	1-10
1.5	Organization of this Report	1-11
2	Industry Profile	2-1
2.1	Introduction	2-1
2.2	Products of the Crude Oil and Natural Gas Industry	2-2
2.2.1	Crude Oil	2-2
2.2.2	Natural Gas	2-2
2.2.3	Condensates	2-3
2.2.4	Other Recovered Hydrocarbons	2-3
2.2.5	Produced Water	2-4
2.3	Oil and Natural Gas Production Processes	2-4
2.3.1	Exploration and Drilling	2-4
2.3.2	Production	2-5
2.3.3	Natural Gas Processing	2-7
2.3.4	Natural Gas Transmission and Distribution	2-8
2.4	Reserves and Markets	2-8
2.4.1	Domestic Proved Reserves	2-9
2.4.2	Domestic Production	2-13
2.4.3	Domestic Consumption	2-21
2.4.4	International Trade	2-24
2.4.5	Forecasts	2-26
2.5	Industry Costs	2-31
2.5.1	Finding Costs	2-31
2.5.2	Lifting Costs	2-33
2.5.3	Operating and Equipment Costs	2-34
2.6	Firm Characteristics	2-36
2.6.1	Ownership	2-36
2.6.2	Size Distribution of Firms in Affected	2-37
2.6.3	Trends in National Employment and Wages	2-39
2.6.4	Horizontal and Vertical Integration	2-44
2.6.5	Firm-level Information	2-45
2.6.6	Financial Performance and Condition	2-49
2.7	References	2-53
3	Emissions and Engineering Costs	3-1
3.1	Introduction	3-1
3.2	Emissions Points, Controls, and Engineering Costs Analysis	3-1
3.2.1	Emission Points and Pollution Controls assessed in the RIA	3-2
<IP_ADDRESS>	NSPS Emission Points and Pollution Controls	3-2
<IP_ADDRESS>	NESHAP Emission Points and Pollution Controls	3-6
3.2.2	Engineering Cost Analysis	3-8
<IP_ADDRESS>	NSPS Sources	3-8
<IP_ADDRESS>	NESHAP Sources	3-33
3.3	References	3-35
4	Benefits of Emissions Reductions	4-1
4.1	Introduction	4-1
4.2	Direct Emission Reductions from the Oil and Natural Gas Rules	4-2
4.3	Secondary Impacts Analysis for Oil and Gas Rules	4-4
4.4	Hazardous Air Pollutant (HAP) Benefits	4-8
4.4.1	Benzene	4-14
4.4.2	Toluene	4-16
4.4.3	Carbonyl sulfide	4-16
4.4.4	Ethylbenzene	4-17
4.4.5	Mixed xylenes	4-18
4.4.6	n-Hexane	4-18
4.4.7	Other Air Toxics	4-19
4.5	VOC	4-19
4.5.1	VOC as a PM2.5 precursor	4-19
4.5.2	PM2.5 health effects and valuation	4-20
4.5.3	Organic PM welfare effects	4-24
4.5.4	Visibility Effects	4-25
4.6	VOC as an Ozone Precursor	4-25
4.6.1	Ozone health effects and valuation	4-26
4.6.2	Ozone vegetation effects	4-27
4.6.3	Ozone climate effects	4-27
4.7	Methane (CH4)	4-28
4.7.1	Methane climate effects and valuation	4-28
4.7.2	Methane as an ozone precursor	4-35
4.7.3	Combined methane and ozone effects	4-35
4.8	References	4-36
5	Statutory and Executive Order Reviews	5-1
5.1	Executive Order 12866, Regulatory Planning and Review and Executive Order 13563, Improving Regulation and Regulatory Review	5-1
5.2	Paperwork Reduction Act	5-2
5.3	Regulatory Flexibility Act	5-5
5.4	Unfunded Mandates Reform Act	5-7
5.5	Executive Order 13132:  Federalism	5-8
5.6	Executive Order 13175:  Consultation and Coordination with Indian Tribal Governments	5-8
5.7	Executive Order 13045:  Protection of Children from Environmental Health Risks and Safety Risks	5-9
5.8	Executive Order 13211:  Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use	5-9
5.9	National Technology Transfer and Advancement Act	5-11
5.10	Executive Order 12898:  Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations	5-11
5.11	Congressional Review Act	5-13
6	Comparison of Benefits and Costs	6-1
7	Economic Impact Analysis and Distributional Assessments	7-1
7.1	Introduction	7-1
7.2	Energy System Impacts Analysis of Final NSPS and NESHAP Amendments	7-1
7.2.1	Description of the Department of Energy National Energy Modeling System	7-2
7.2.2	Inputs to National Energy Modeling System	7-5
<IP_ADDRESS>	Compliance Costs for Oil and Gas Exploration and Production	7-6
<IP_ADDRESS>	Adding Averted Methane Emissions into Natural Gas Production	7-8
<IP_ADDRESS>	Fixing Canadian Drilling Costs to Baseline Path	7-10
7.2.3	Energy System Impacts	7-10
<IP_ADDRESS>	Impacts on Drilling Activities	7-10
<IP_ADDRESS>	Impacts on Production, Prices, and Consumption	7-12
<IP_ADDRESS>	Impacts on Imports and National Fuel Mix	7-16
7.3	Employment Impact Analysis	7-19
7.3.1	Employment Impacts from Pollution Control Requirements	7-20
7.3.2	Employment Impacts Primarily on the Regulated Industry	7-24
7.4	Small Business Impacts Analysis	7-27
7.4.1	Small Business National Overview	7-28
7.4.2	Small Entity Economic Impact Measures	7-33
7.4.3	Small Entity Economic Impact Analysis, Final NSPS	7-35
<IP_ADDRESS>	Overview of Sample Data and Methods	7-35
<IP_ADDRESS>	Small Entity Impact Analysis, Final NSPS, Results	7-43
<IP_ADDRESS>	Small Entity Impact Analysis, Final NSPS, Additional Qualitative Discussion	7-49
7.4.4	Small Entity Economic Impact Analysis, Final NESHAP Amendments	7-52
7.4.5	Conclusions for NSPS and NESHAP Amendments	7-54
7.5	References	7-55

 List of Tables
Table 1-1	Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas NSPS in 2015[1]	1-5
Table 1-2	Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas NESHAP in 2015[1]	1-7
Table 2-1	Technically Recoverable Crude Oil and Natural Gas Resource Estimates, 2007	2-10
Table 2-2	Crude Oil and Natural Gas Cumulative Domestic Production, Proved Reserves, and Proved Ultimate Recovery, 1977-2008	2-11
Table 2-3	Crude Oil and Dry Natural Gas Proved Reserves by State, 2008	2-13
Table 2-4	Crude Oil Domestic Production, Wells, Well Productivity, and U.S. Average First Purchase Price	2-14
Table 2-5	Natural Gas Production and Well Productivity, 1990-2009	2-15
Table 2-6	Crude Oil and Natural Gas Exploratory and Development Wells and Average Depth, 1990-2009	2-17
Table 2-7	U.S. Onshore and Offshore Oil, Gas, and Produced Water Generation, 2007	2-18
Table 2-8	U.S. Oil and Natural Gas Pipeline Mileage, 1990-2008	2-20
Table 2-9	Crude Oil Consumption by Sector, 1990-2009	2-21
Table 2-10	Natural Gas Consumption by Sector, 1990-2009	2-23
Table 2-11	Total Crude Oil and Petroleum Products Imports (Million Bbl), 1990-2009	2-25
Table 2-12	Natural Gas Imports and Exports, 1990-2009	2-26
Table 2-13 	Forecast of Total Successful Wells Drilled, Lower 48 States, 2010-2035	2-27
Table 2-14	Forecast of Crude Oil Supply, Reserves, and Wellhead Prices, 2010-2035	2-29
Table 2-15	Forecast of Natural Gas Supply, Lower 48 Reserves, and Wellhead Price	2-31
Table 2-16	SBA Size Standards and Size Distribution of Oil and Natural Gas Firms	2-38
Table 2-17	Oil and Natural Gas Industry Employment by NAICS, 1990-09	2-39
Table 2-18	Oil and Natural Gas Industry Average Wages by NAICS, 1990-2009 (2008 dollars)	2-43
Table 2-19	Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2010	2-47
Table 2-20	Top 20 Natural Gas Processing Firms (Based on Throughput), 2009	2-48
Table 2-21	Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2009	2-49
Table 2-22	Selected Financial Items from Income Statements (Billion 2008 Dollars)	2-50
Table 2-23	Return on Investment for Lines of Business (all FRS), for 1998, 2003, and 2008 (percent)	2-51
Table 2-24	Income and Production Taxes, 1990-2008 (Million 2008 Dollars)	2-52
Table 3-1	Emissions Sources, Points, and Controls Evaluated at Proposal for the NSPS	3-9
Table 3-2	Summary of Projected No. of Affected Units Under Primary and Alternative Regulatory Baselines and Capital and Annualized Costs per Unit for Final NSPS Emissions Sources and Points	3-12
Table 3-3	Estimated New Hydraulically Fractured and Refractured Natural Gas Well Completions Affected by NSPS, 2015	3-16
Table 3-4	Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction Cost-Effectiveness by NSPS Emissions Sources and Points, Primary Baseline, 2015	3-20
Table 3-5	 Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction Cost-Effectiveness by NSPS Emissions Sources and Points, Alternative Regulatory Baseline, 2015	3-21
Table 3-6	Engineering Compliance Costs, Emission Reductions, and Cost-Effectiveness, Primary Baseline, NSPS (2008$)	3-22
Table 3-7	Estimates of Control Unit-level and National-level Natural Gas and Condensate Recovery, Sources and Emissions Points, Primary Baseline, NSPS, 2015	3-29
Table 3-8	Simple Rate of Return Estimate for Final NSPS Controls, Primary Baseline	3-30
Table 3-9	Summary of Estimated Capital and Annual Costs, Emissions Reductions, and HAP Reduction Cost-Effectiveness for Final NESHAP Amendments	3-35
Table 4-1	Direct Emission Reductions Associated with the Oil and Natural Gas NSPS and NESHAP Amendments in 2015 (short tons per year)	4-4
Table 4-2	Secondary Air Pollutant Impacts Associated with Control Techniques by Emissions Category, Primary Baseline ("Producer-Side") (short tons per year)	4-6
Table 4-3	Modeled Changes in Energy-related CO2-equivalent Emissions by Fuel Type for the Final Oil and Gas NSPS and NESHAP Amendments in 2015 (million metric tonnes) ("Consumer-Side")[1]	4-7
Table 4-4	Total Change in CO2-equivalent Emissions including Secondary Impacts for the Final Oil and Gas NSPS and NESHAP Amendments in 2015 (million metric tonnes)	4-7
Table 4-5	Summary of Emissions Changes for the Final Oil and Gas NSPS and NESHAP Amendments in 2015 (short tons per year)	4-8
Table 4-6	Monetized Benefits-per-Ton Estimates for VOC (2008$)	4-23
Table 4-7	Climate Methane Benefits Using `GWP' Approach	4-33
Table 5-1	Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas NSPS and NESHAP Amendments in 2015[1]	5-2
Table 6-1	Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas NSPS in 2015[1]	6-4
Table 6-2	Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas NESHAP Amendments in 2015[1]	6-5
Table 6-3	Summary of Emissions Changes for the Final Oil and Gas NSPS and NESHAP in 2015 (short tons per year)	6-6
Table 7-1	Summary of Additional Annualized O&M Costs (on a Per New Well Basis) for Environmental Controls Entered into NEMS	7-8
Table 7-2	Summary of Additional Per Completion/Recompletion Costs (2008$) for Environmental Controls Entered into NEMS	7-8
Table 7-3	Successful Oil and Gas Wells Drilled, NSPS	7-11
Table 7-4	Successful Wells Drilled by Well Type (Onshore, Lower 48 States), NSPS	7-12
Table 7-5	Annual Domestic Natural Gas and Crude Oil Production, NSPS	7-13
Table 7-6	Natural Gas Production by Well Type (Onshore, Lower 48 States), NSPS	7-14
Table 7-7	Lower 48 Average Natural Gas and Crude Oil Wellhead Price, NSPS	7-14
Table 7-8	Delivered Natural Gas Prices by Sector (2008$ per million BTU), 2015, NSPS	7-15
Table 7-9	Natural Gas Consumption by Sector, NSPS	7-16
Table 7-10	Net Imports of Natural Gas and Crude Oil, NSPS	7-17
Table 7-11	Total Energy Consumption by Energy Type (Quadrillion BTU), NSPS	7-18
Table 7-12	Modeled Change in Energy-related "Consumer-Side" CO2-equivalent GHG Emissions	7-19
Table 7-13	Labor-based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and Maintaining Control Equipment Requirements, NSPS, 2015	7-25
Table 7-14	Labor-based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and Maintaining Control Equipment Requirements, Final NESHAP Amendments, 2015	7-26
Table 7-15	Number of Firms, Total Employment, and Estimated Receipts by Firm Size and NAICS, 2007	7-30
Table 7-16	Distribution of Small and Large Firms by Number of Firms, Total Employment, and Estimated Receipts by Firm Size and NAICS, 2007	7-31
Table 7-17	Distribution of Crude Oil and Natural Gas Wells by Productivity Level, 2009	7-33
Table 7-18	Estimated Revenues for Firms in Sample, by Firm Type and Size	7-39
Table 7-19	Descriptive Statistics of Capital and Exploration Expenditures, Small and Large Firms in Sample, 2008 and 2009 (million 2008 dollars)	7-40
Table 7-20	Descriptive Statistics of Estimated Wells Drilled, Small and Large Firms in Sample, 2008 and 2009	7-41
Table 7-21	Distribution of Estimated Final NSPS Compliance Costs Without Revenues from Additional Natural Gas Product Recovery across Firm Size in Sample of Firms	7-44
Table 7-22	Distribution of Estimated Final NSPS Compliance Costs With Revenues from Additional Natural Gas Product Recovery across Firm Size in Sample of Firms	7-45
Table 7-23	Summary of Sales Test Ratios, Without Revenues from Additional Natural Gas Product Recovery for Firms Affected by Final NSPS	7-46
Table 7-24	Summary of Sales Test Ratios, With Revenues from Additional Natural Gas Product Recovery for Firms Affected by Final NSPS	7-47
Table 7-25	Impact Levels of Final NSPS on Small Firms as a Percent of Small Firms in Sample, With and Without Revenues from Additional Natural Gas Product Recovery	7-48
Table 7-26	Summary of Sales Test Ratios for Firms Affected by Final NESHAP Amendments	7-53
Table 7-27	Affected Small Firms as a Percent of Small Firms Nationwide, Final NESHAP Amendments	7-54
Table 7-28	Affected Small Firms as a Percent of Small Firms Nationwide, Final NSPS and NESHAP Amendments	7-55

 List of Figures
Figure 2-1	A) Domestic Crude Oil Proved Reserves and Cumulative Production, 1990-2008. B) Domestic Natural Gas Proved Reserves and Cumulative Production, 1990-2008	2-12
Figure 2-2	A) Total Producing Crude Oil Wells and Average Well Productivity, 1990-2009.  B) Total Producing Natural Gas Wells and Average Well Productivity, 1990-2009.	2-16
Figure 2-3	U.S. Produced Water Volume by Management Practice, 2007	2-19
Figure 2-4	Crude Oil Consumption by Sector (Percent of Total Consumption), 1990-2009	2-22
Figure 2-5 	Natural Gas Consumption by Sector (Percent of Total Consumption), 1990-2009	2-24
Figure 2-6	Forecast of Total Successful Wells Drilled, Lower 48 States, 2010-2035	2-28
Figure 2-7	Forecast of Domestic Crude Oil Production and Net Imports, 2010-2035	2-30
Figure 2-8	Costs of Crude Oil and Natural Gas Wells Drilled, 1981-2008	2-32
Figure 2-9	Finding Costs for FRS Companies, 1981-2008	2-33
Figure 2-10	Direct Oil and Natural Gas Lifting Costs for FRS Companies, 1981-2008 (3-year Running Average)	2-34
Figure 2-11	Crude Oil Operating Costs and Equipment Costs Indices (1976=100) and Crude Oil Price (in 1976 dollars), 1976-2009	2-35
Figure 2-12	Natural Operating Costs and Equipment Costs Indices (1976=100) and Natural Gas Price, 1976-2009	2-36
Figure 2-13	Employment in Drilling of Oil and Natural Gas Wells (NAICS 213111), and Total Oil and Natural Gas Wells Drilled, 1990-2009	2-40
Figure 2-14	Employment in Crude Petroleum and Natural Gas Extraction (NAICS 211111) and Total Crude Oil and Natural Gas Production (boe), 1990-2009	2-41
Figure 2-15	Employment in Natural Gas Liquid Extraction (NAICS 211112), Employment in Pipeline Transportation of Natural Gas (NAICS 486210), and Total Natural Gas Production, 1990-2009	2-42
Figure 2-16	Oil and Natural Gas Industry Average Wages by NAICS, 1990-2009 ($2008)	2-44
Figure 3-1	Sensitivity of Final NSPS Annualized Costs to Natural Gas Prices and REC Costs	3-24
Figure 3-2	Sensitivity of Final NSPS Annualized Costs to Natural Gas Prices and Emissions Factor for Hydraulically Fractured Natural Gas Well Completions	3-26
Figure 4-1	Conceptual Diagram of Secondary Impacts from Oil and Gas NSPS and NESHAP Amendments	4-5
Figure 4-2	Estimated Chronic Census Tract Carcinogenic Risk from HAP exposure from outdoor sources (2005 NATA)	4-11
Figure 4-3	Estimated Chronic Census Tract Noncancer (Respiratory) Risk from HAP exposure from outdoor sources (2005 NATA)	4-12
Figure 6-1	Illustrative Break-Even Diagram for Alternate Natural Gas Prices for the NSPS	6-2
Figure 7-1	Organization of NEMS Modules (source: U.S. Energy Information Administration)	7-4

Executive Summary
Background
The U.S. Environmental Protection Agency (EPA) reviewed the New Source Performance Standards (NSPS) for volatile organic compound and sulfur dioxide emissions from Natural Gas Processing Plants.  As a result of these NSPS, this rule amends the Crude Oil and Natural Gas Production source category currently listed under section 111 of the Clean Air Act to include Natural Gas Transmission and Distribution, amends the existing NSPS for volatile organic compounds (VOC) from Natural Gas Processing Plants, and finalizes the NSPS for stationary sources in the source categories that are not covered by the existing NSPS.  In addition, this rule addresses the residual risk and technology review conducted for two source categories in the Oil and Natural Gas sector regulated by separate National Emission Standards for Hazardous Air Pollutants (NESHAP).  It also finalizes standards for emission sources not currently addressed, as well as amendments to improve aspects of these NESHAP related to applicability and implementation.  Finally, it addresses provisions in these NESHAP related to emissions during periods of startup, shutdown, and malfunction.
As part of the regulatory process, EPA is required to develop a regulatory impact analysis (RIA) for rules that have costs or benefits that exceed $100 million annually.  EPA estimates the final NSPS will have costs that exceed $100 million, so the Agency has prepared an RIA.  Because the NESHAP Amendments are being finalized in the same rulemaking package (i.e., same Preamble), we have chosen to present the economic impact analysis for the final NESHAP Amendments within the same document as the NSPS RIA.
This RIA includes an economic impact analysis and an analysis of human health and climate impacts anticipated from the final NSPS and NESHAP Amendments.  We also estimate potential impacts of the final rules on the national energy economy using the U.S. Energy Information Administration's National Energy Modeling System (NEMS).  The engineering compliance costs are annualized using a 7 percent discount rate.  This analysis assumes an analysis year of 2015.  The final NSPS contains provisions related to reduced emissions completions, pneumatic controllers, and storage vessels that phase-in emissions control requirements over time.  As a result of these provisions, 2015 is the first year that the full requirements of the NSPS are in effect.  Because of the phase-in provisions of the NSPS, the RIA does not present an accurate assessment of the period between promulgation and the end of 2014, but is accurate for 2015.
Several emission controls for the NSPS, such as reduced emissions completions (RECs) of hydraulically fractured natural gas wells, 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.  RECs also recover saleable hydrocarbon condensates that would otherwise be lost to the environment.  The revenues derived from additional natural gas and condensate recovery are expected to offset the engineering costs of implementing the NSPS.  In the economic impact and energy economy analyses for the NSPS, we present results that include the additional product recovery and the revenues we expect producers to gain from the additional product recovery.
      The primary baseline used for the impacts analysis of our NSPS for completions of hydraulically fractured natural gas wells 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 emissions 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, as well as in Section 3 of this RIA.
      Additionally, we provide summary-level estimates of emissions reductions and engineering compliance costs for a case where no voluntary RECs are assumed to occur.  This alternative case is presented in order to show impacts if conditions were such that RECs were no longer performed on a voluntary basis, but rather were compelled by the regulation, and serves in part to capture the inherent uncertainty in projecting voluntary activity into the future. As such, this alternative case establishes the full universe of emissions reductions that are guaranteed by this NSPS (those that are required to occur under the rule, including those that would likely occur voluntarily).  While the primary baseline may better represent actual costs (and emissions reductions) beyond those already expected under business as usual, the alternative case better captures the full amount of emissions reductions where the NSPS acts as a backstop to ensure that emission reduction practices occur (practices covered by this rule).
Summary of Results
NSPS Results
For the final NSPS, the key results of the RIA follow and are summarized in Table 1-1:
         #    Benefits Analysis: The final NSPS is anticipated to prevent significant new emissions, including 190,000 tons of VOC, as well as from 11,000 tons of hazardous air pollutants (HAP) and 1.0 million tons of methane.  While we expect that these avoided emissions will result in improvements in ambient air quality and reductions in health effects associated with exposure to HAP, ozone, and particulate matter (PM), we have determined that quantification of those benefits cannot be accomplished for this rule.   This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. In addition to health improvements, there will be improvements in visibility effects, ecosystem effects, as well as additional natural gas recovery.  The methane emissions reductions associated with the final NSPS are likely to result in climate co-benefits.  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.  If the EPA's estimate of voluntary action is not included in the NSPS baseline (only REC under state regulations are assumed to occur absent the NSPS), the emissions reductions achieved by the final NSPS in HAP, methane and VOC are estimated at about 19,000 tons, 1.7 million tons and 290,000 tons, respectively.
         #    Engineering Cost Analysis: EPA estimates the total capital cost of the final NSPS will be $25 million, regardless of baseline assumptions.  The estimate of total annualized engineering costs of the final NSPS is $170 million.  When estimated revenues from additional natural gas and condensate recovery are included, the annualized engineering costs of the final NSPS are estimated to be -$15 million, assuming a wellhead natural gas price of $4/thousand cubic feet (Mcf) and condensate price of $70/barrel.  Possible explanations for why there appear to be negative cost control technologies are discussed in the engineering costs analysis section in the RIA.  The estimated engineering compliance costs that include the product recovery are sensitive to the assumption about the price of the recovered product.  There is also geographic variability in wellhead prices, which can also influence estimated engineering costs.  For example, $1/Mcf change in the wellhead price causes a change in estimated engineering compliance costs of about $43 million, given EPA estimates that 43 billion cubic feet of natural gas will be recovered by implementing the NSPS.  If voluntary action is not deducted from the baseline, capital costs for the NSPS under the alternative regulatory baseline are estimated at $25 million, and annualized costs without revenues from product recovery for the NSPS are estimated at $330 million.  In this scenario, given the assumptions about product prices, estimated revenues from product recovery are $350 million, yielding an estimated cost of savings of about $22 million.  All estimates are in 2008 dollars.
      *    Small Entity Analyses: For the final NSPS, EPA performed a screening analysis for impacts on a sample of expected affected small entities by comparing compliance costs to entity revenues. When revenue from additional natural gas product recovered is not included, we estimate that 123 of the 127 small firms analyzed (96.9 percent) are likely to have impacts less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, four firms (3.1 percent) are likely to have impacts greater than 1 percent. Three of these four firms are likely to have impacts greater than 3 percent. However, when revenue from additional natural gas product recovery is included, we estimate that none of the analyzed firms will have an impact greater than 1 percent.
         #    Employment Impacts Analysis: EPA estimated the labor impacts due to the installation, operation, and maintenance of control equipment, as well as labor associated with new reporting and recordkeeping requirements.  We estimate up-front and continual, annual labor requirements by estimating hours of labor required for compliance and converting this number to full-time equivalents (FTEs) by dividing by 2,080 (40 hours per week multiplied by 52 weeks).  The up-front labor requirement to comply with the final NSPS is estimated at 50 full-time-equivalent employees. The annual labor requirement to comply with final NSPS is estimated at about 570 full-time-equivalent employees. We note that this type of FTE estimate cannot be used to identify the specific number of people involved or whether new jobs are created for new employees, versus displacing jobs from other sectors of the economy.

Table 1-1	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[6]
                              190,000 tons of VOC

                             11,000 tons of HAP[5]

                        1.0 million tons of methane[5]

                       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.

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.

[6] 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.

NESHAP Amendments Results
For the final NESHAP Amendments, the key results of the RIA follow and are summarized in Table 1-2:
         #    Benefits Analysis: The final NESHAP Amendments are anticipated to reduce a significant amount of existing emissions, including 670 tons of HAP, as well as 1,200 tons of VOC and 420 tons of methane.  While we expect that these avoided emissions will result in improvements in ambient air quality and reductions in health effects associated with exposure to HAP, ozone, and PM, we have determined that quantification of those benefits cannot be accomplished for this rule.  This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available.  In addition to health improvements, there will be improvements in visibility effects, ecosystem effects, and climate effects.  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 about 8,000 metric tons.
         #    Engineering Cost Analysis: EPA estimates the total capital costs of the final NESHAP Amendments to be $2.8 million. Total annualized engineering costs, which includes annualized capital costs and operating and maintenance costs, of the final NESHAP Amendments are estimated to be $3.5 million. All estimates are in 2008 dollars.
         #    Small Entity Analyses: For the final NESHAP Amendments, EPA estimates that 11 of the 35 firms (31 percent) that own potentially affected facilities are small entities. The EPA performed a screening analysis for impacts on all expected affected small entities by comparing compliance costs to entity revenues. Among the small firms, none of the 11 (zero percent) are likely to have impacts of greater than 1 percent in terms of the ratio of annualized compliance costs to revenues.
         #    Employment Impacts Analysis: EPA estimated the labor impacts due to the installation, operation, and maintenance of control equipment, as well as labor associated with new reporting and recordkeeping requirements.  We estimate up-front and continual, annual labor requirements by estimating hours of labor required for compliance and converting this number to full-time equivalents (FTEs) by dividing by 2,080 (40 hours per week multiplied by 52 weeks).  The up-front labor requirement to comply with the final NESHAP Amendments is estimated at 4 full-time-equivalent employees. The annual labor requirement to comply with final NESHAP Amendments is estimated at about 30 full-time-equivalent employees. We note that this type of FTE estimate cannot be used to identify the specific number of people involved or whether new jobs are created for new employees, versus displacing jobs from other sectors of the economy.
         #    Break-Even Analysis: 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, 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.  Previous assessments have shown that the PM2.5 benefits associated with reducing VOC emissions were valued at $280 to $7,000 per ton of VOC emissions reduced in specific urban areas, ozone benefits valued at $240 to $1,000 per ton of VOC emissions reduced, and climate co-benefits valued at $110 to $1,400 per short ton of methane reduced.  All estimates are in 2008 dollars.

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

                                     Final
Total Monetized Benefits[2]
                                      N/A
Total Costs[3]
                                 $3.5 million
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 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.
Results of Energy System Impacts Analysis of the NSPS and NESHAP Amendments
     The analysis of energy system impacts using NEMS for the final NSPS 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.
Results for Combined Small Entity Analysis for the NSPS and NESHAP Amendments
     After considering the economic impact of the combined NSPS and NESHAP Amendments on small entities, EPA certifies this action will not have a significant economic impact on a substantial number of small entities (SISNOSE). While both the NSPS and NESHAP amendment would individually result in a no SISNOSE finding, EPA performed an additional screening analysis in order to certify the rule in its entirety. This analysis compared compliance costs to entity revenues for the total of all the entities affected by the NESHAP Amendments and the sample of entities analyzed for the NSPS. When revenues from additional natural gas product sales are not included, 132 of the 136 small firms (97 percent) are likely to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, four firms (3 percent) are likely to have impacts greater than 1 percent. Three of these four firms are likely to have impacts greater than 3 percent. When revenues from additional natural gas product sales are included, all 136 small firms (100 percent) in the sample are likely to have impacts of less than 1 percent.
Summary of NSPS Impacts Changes from the Proposal RIA
   This section summarizes major changes from the proposal version of the RIA.  These changes were a result of revised assumptions and technical factors, as well as changes in the rule itself from proposal.
   * Revised baseline to include voluntary RECs: The NSPS analysis used a baseline that accounted for emission controls required by state regulation, but did not include voluntary actions. In the final RIA, to account for emissions reductions and costs arising in the baseline from voluntary implementation of pollution controls, EPA used information on total emissions reductions reported by partners of the EPA Natural Gas STAR. Additionally, we provide summary-level estimates of emissions reductions and engineering compliance costs for a case where no voluntary reduced emission completions (REC) are assumed to occur.  This alternative case is presented in order to show impacts if conditions were such that RECs were no longer performed on a voluntary basis, but rather were compelled by the regulation.
   * Changed estimate of number of recompleted natural gas wells: The NSPS proposal estimated that 12,050 RECs for existing natural gas well recompletions would be required in addition to those already required by state regulations.  EPA has reevaluated the assumption based on data submitted to the Agency.  Based on this information, EPA has estimated the recompletion frequency to be 1 percent of fractured gas wells per year, rather than 10 percent. More detailed discussion is presented in a technical memorandum on this subject in the docket.
   * Recompletions of existing natural gas wells that are hydraulically refractured:  In the final rule, recompletions of existing natural gas wells that are hydraulically refractured are only subject to the NSPS if emissions from these completions are uncontrolled.
   * New hydraulically fractured natural gas well completions with insufficient pressure to implement REC required to combust completions emissions: Using the formula estimated to identify hydraulically fractured natural gas well completions that would not have sufficient pressure to perform a REC, approximately 10 percent of well completions would be required to combust emissions rather than implement a REC. More detailed discussion is presented in a technical memorandum on this subject in the docket.
   * Revised natural gas emissions factor for well completions and recompletions of hydraulically fractured wells: The EPA received several comments regarding the emissions factor selected to calculate whole gas emissions (and the associated VOC emissions) from hydraulically fractured well completions. Comments focused on the data behind the emissions factor, what the emissions factor is intended to represent, and the procedures used to develop the emissions factor from the selected data sets.  We reviewed all information received and have decided to retain the data set and the analysis conducted to develop the emissions factor, but rounded from 9,175 Mcf per completion to 9,000 Mcf per completion. More detailed discussion is presented in a technical memorandum on this subject in the docket.
   * Changed estimate of REC and completion emission combustion capital costs: The requirements related to completions of hydraulically fractured natural gas wells (combustion and REC) are essentially one-shot events that typically occur over a few days to a couple of weeks and are generally performed by independent contractors.  The emissions controls are applied over the course of a well completion, which will typically range over a few days to a couple of weeks.  Given that we base our REC costs estimates on the average cost for contracting the REC as a service, we expect contractors' operation and maintenance costs, depreciations, and potential salvage value of the equipment to be reflected in the total contracting costs.  Because of these factors, we decided to treat the hydraulically fractured natural gas well completion requirements solely as annualized costs, which differed from our analysis at proposal, which equated capital and annualized costs.
   * Removal of compressors and pneumatic devices in the natural gas transmission segment from NSPS: In the final rule, proposed requirements relating to reciprocating and centrifugal compressors and pneumatic devices in the transmission segment are removed.  Given the large number of sources, and the relatively low level of VOCs emitted from these sources, we have concluded that additional evaluation of these compliance and burden issues is appropriate prior to taking final action on compressors and pneumatic controllers in the transmission and storage segment. Requirements pertaining to storage vessels in the transmission segment remain.
   * Reporting and recordkeeping costs: EPA identified several ways to streamline reporting and recordkeeping requirements.  As a result, the estimated annual cost of reporting and recordkeeping decreased from $19 million per year to $2.6 million per year.
Summary of NESHAP Amendments Impacts Changes from the Proposal RIA
     The cost and emissions reduction estimates for the NESHAP Amendments are reduced from proposal because proposed provisions related to storage vessels were not finalized from proposal, as well as because of changes to the proposed provisions for small gycol dehydrators. The estimated capital costs of the NESHAP Amendments decreased by about $49 million (from $52 to about $3 million), while estimated total annualized compliance costs decreased by about $12.5 million per year (from $16 to $3.5 million per year) .  As a result, estimated HAP reductions decreased by about 710 tons per year from proposal (from 1,380 to 670 tons per year).  Also, because of changes in emissions limits from proposal, fewer glycol dehydrators are affected, which reduces capital and annualized costs, as well as emissions reductions for these emissions points.
Organization of this Report
The remainder of this report details the methodology and the results of the RIA.  Section 2 presents the industry profile of the oil and natural gas industry.  Section 3 describes the emissions and engineering cost analysis.  Section 4 presents the benefits analysis.  Section 5 presents statutory and executive order analyses.  Section 6 presents a comparison of benefits and costs.  Section 7 presents energy system impact, employment impact, and small business impact analyses.
Industry Profile
Introduction
      The oil and natural gas industry includes the following five segments: drilling and extraction, processing, transportation, refining, and marketing.  The Oil and Natural Gas NSPS and NESHAP Amendments require controls for the oil and natural gas products and processes of the drilling and extraction of crude oil and natural gas, natural gas processing, and natural gas transportation segments.
      Most crude oil and natural gas production facilities are classified under NAICS 211: Crude Petroleum and Natural Gas Extraction (211111) and Natural Gas Liquid Extraction (211112).  The drilling of oil and natural gas wells is included in NAICS 213111. Most natural gas transmission and storage facilities are classified under NAICS 486210 -- Pipeline Transportation of Natural Gas.  While other NAICS (213112 -- Support Activities for Oil and Gas Operations, 221210 -- Natural Gas Distribution, 486110 -- Pipeline Transportation of Crude Oil, and 541360 -- Geophysical Surveying and Mapping Services) are often included in the oil and natural gas sector, these are not discussed in detail in the Industry Profile because they are not directly affected by the final NSPS and NESHAP Amendments.
      The outputs of the oil and natural gas industry are inputs for larger production processes of gas, energy, and petroleum products.  As of 2009, the Energy Information Administration (EIA) estimates that about 526,000 producing oil wells and 493,000 producing natural gas wells operated in the United States.  Domestic dry natural gas production was 20.5 trillion cubic feet (tcf) in 2009, the highest production level since 1970.  The leading five natural gas producing states are Texas, Alaska, Wyoming, Oklahoma, and New Mexico.  Domestic crude oil production in 2009 was 1,938 million barrels (bbl).  The leading five crude oil producing states are Texas, Alaska, California, Oklahoma, and New Mexico.
      The Industry Profile provides a brief introduction to the components of the oil and natural gas industry that are relevant to the final NSPS and NESHAP Amendments.  The purpose is to give the reader a general understanding of the geophysical, engineering, and economic aspects of the industry that are addressed in subsequent economic analysis in this RIA.  The Industry Profile relies heavily on background material from the U.S. EPA's "Economic Analysis of Air Pollution Regulations: Oil and Natural Gas Production" (1996) and the U.S. EPA's "Sector Notebook Project: Profile of the Oil and Gas Extraction Industry" (2000).
Products of the Crude Oil and Natural Gas Industry
      Each producing crude oil and natural gas field has its own unique properties.  The composition of the crude oil and natural gas and reservoir characteristics are likely to be different from that of any other reservoir.
Crude Oil
      Crude oil can be broadly classified as paraffinic, naphthenic (or asphalt-based), or intermediate.  Generally, paraffinic crudes are used in the manufacture of lube oils and kerosene.  Paraffinic crudes have a high concentration of straight chain hydrocarbons and are relatively low in sulfur compounds.  Naphthenic crudes are generally used in the manufacture of gasolines and asphalt and have a high concentration of olefin and aromatic hydrocarbons.  Naphthenic crudes may contain a high concentration of sulfur compounds.  Intermediate crudes are those that are not classified in either of the above categories.
      Another classification measure of crude oil and other hydrocarbons is by API gravity.  API gravity is a weight per unit volume measure of a hydrocarbon liquid as determined by a method recommended by the American Petroleum Institute (API).  A heavy or paraffinic crude oil is typically one with API gravity of 20[o] or less, while a light or naphthenic crude oil, which typically flows freely at atmospheric conditions, usually has API gravity in the range of the high 30's to the low 40's.
      Crude oils recovered in the production phase of the petroleum industry may be referred to as live crudes.  Live crudes contain entrained or dissolved gases which may be released during processing or storage.  Dead crudes are those that have gone through various separation and storage phases and contain little, if any, entrained or dissolved gases.
Natural Gas
      Natural gas is a mixture of hydrocarbons and varying quantities of non-hydrocarbons that exists in a gaseous phase or in solution with crude oil or other hydrocarbon liquids in natural underground reservoirs.  Natural gas may contain contaminants, such as hydrogen sulfide (H2S), CO2, mercaptans, and entrained solids.
      Natural gas may be classified as wet gas or dry gas.  Wet gas is unprocessed or partially processed natural gas produced from a reservoir that contains condensable hydrocarbons.  Dry gas is either natural gas whose water content has been reduced through dehydration or natural gas that contains little or no recoverable liquid hydrocarbons.
      Natural gas streams that contain threshold concentrations of H2S are classified as sour gases.  Those with threshold concentrations of CO2 are classified as acid gases.  The process by which these two contaminants are removed from the natural gas stream is called sweetening.  The most common sweetening method is amine treating.  Sour gas contains a H2S concentration of greater than 0.25 grain per 100 standard cubic feet, along with the presence of CO2. Concentrations of H2S and CO2, along with organic sulfur compounds, vary widely among sour gases.  A majority of total onshore natural gas production and nearly all offshore natural gas production is classified as sweet.
Condensates
      Condensates are hydrocarbons in a gaseous state under reservoir conditions, but become liquid in either the wellbore or the production process.  Condensates, including volatile oils, typically have an API gravity of 40[o] or more.  In addition, condensates may include hydrocarbon liquids recovered from gaseous streams from various oil and natural gas production or natural gas transmission and storage processes and operations.
Other Recovered Hydrocarbons
      Various hydrocarbons may be recovered through the processing of the extracted hydrocarbon streams.  These hydrocarbons include mixed natural gas liquids (NGL), natural gasoline, propane, butane, and liquefied petroleum gas (LPG).
Produced Water
      Produced water is the water recovered from a production well.  Produced water is separated from the extracted hydrocarbon streams in various production processes and operations.
Oil and Natural Gas Production Processes
Exploration and Drilling
      Exploration involves the search for rock formations associated with oil or natural gas deposits and involves geophysical prospecting and/or exploratory drilling. Well development occurs after exploration has located an economically recoverable field and involves the construction of one or more wells from the beginning (called spudding) to either abandonment if no hydrocarbons are found or to well completion if hydrocarbons are found in sufficient quantities.
      After the site of a well has been located, drilling commences.  A well bore is created by using a rotary drill to drill into the ground.  As the well bore gets deeper sections of drill pipe are added.  A mix of fluids called drilling mud is released down into the drill pipe then up the walls of the well bore, which removes drill cuttings by taking them to the surface.  The weight of the mud prevents high-pressure reservoir fluids from pushing their way out ("blowing out").  The well bore is cased in with telescoping steel piping during drilling to avoid its collapse and to prevent water infiltration into the well and to prevent crude oil and natural gas from contaminating the water table.  The steel pipe is cemented by filling the gap between the steel casing and the wellbore with cement.
      Horizontal drilling technology has been available since the 1950s.  Horizontal drilling facilitates the construction of horizontal wells by allowing for the well bore to run horizontally underground, increasing the surface area of contact between the reservoir and the well bore so that more oil or natural gas can move into the well.  Horizontal wells are particularly useful in unconventional gas extraction where the gas is not concentrated in a reservoir.  Recent advances have made it possible to steer the drill in different directions (directional drilling) from the surface without stopping the drill to switch directions and allowing for a more controlled and precise drilling trajectory.
      Hydraulic fracturing (also referred to as "fracking") has been performed since the 1940s (U.S. DOE, 2009).  Hydraulic fracturing involves pumping fluids into the well under very high pressures in order to fracture the formation containing the resource.  Proppant is a mix of sand and other materials that is pumped down to hold the fractures open to secure gas flow from the formation (U.S. EPA, 2004).
Production
      Production is the process of extracting the hydrocarbons and separating the mixture of liquid hydrocarbons, gas, water, and solids, removing the constituents that are non-saleable, and selling the liquid hydrocarbons and gas.  The major activities of crude oil and natural gas production are bringing the fluid to the surface, separating the liquid and gas components, and removing impurities.
      Oil and natural gas are found in the pores of rocks and sand (Hyne, 2001).  In a conventional source, the oil and natural gas have been pushed out of these pores by water and moved until an impermeable surface had been reached.  Because the oil and natural gas can travel no further, the liquids and gases accumulate in a reservoir.  Where oil and gas are associated, a gas cap forms above the oil.  Natural gas is extracted from a well either because it is associated with oil in an oil well or from a pure natural gas reservoir.  Once a well has been drilled to reach the reservoir, the oil and gas can be extracted in different ways depending on the well pressure (Hyne, 2001).
      Frequently, oil and natural gas are produced from the same reservoir. As wells deplete the reservoirs into which they are drilled, the gas to oil ratio increases (as does the ratio of water to hydrocarbons).  This increase of gas over oil occurs because natural gas usually is in the top of the oil formation, while the well usually is drilled into the bottom portion to recover most of the liquid.  Production sites often handle crude oil and natural gas from more than one well (Hyne, 2001).
      Well pressure is required to move the resource up from the well to the surface.  During primary extraction, pressure from the well itself drives the resource out of the well directly.  Well pressure depletes during this process.  Typically, about 30 to 35 percent of the resource in the reservoir is extracted this way (Hyne, 2001).  The amount extracted depends on the specific well characteristics (such as permeability and oil viscosity).  Lacking enough pressure for the resource to surface, gas or water is injected into the well to increase the well pressure and force the resource out (secondary or improved oil recovery).  Finally, in tertiary extraction or enhanced recovery, gas, chemicals or steam are injected into the well.  This can result in recovering up to 60 percent of the original amount of oil in the reservoir (Hyne, 2001).
      In contrast to conventional sources, unconventional oil and gas are trapped in rock or sand or, in the case of oil, are found in rock as a chemical substance that requires a further chemical transformation to become oil (U.S. DOE, 2009).  Therefore, the resource does not move into a reservoir as in the case with a conventional source.  Mining, induced pressure, or heat is required to release the resource.  The specific type of extraction method needed depends on the type of formation where the resource is located.  Unconventional natural gas resource types relevant for this rule include:
   * Shale Natural Gas:  Shale natural gas comes from sediments of clay mixed with organic matter.  These sediments form low permeability shale rock formations that do not allow the gas to move.  To release the gas, the rock must be fragmented, making the extraction process more complex than it is for conventional gas extraction.  Shale gas can be extracted by drilling either vertically or horizontally, and breaking the rock using hydraulic fracturing (U.S. DOE, 2009).
   * Tight Sands Natural Gas:  Reservoirs are composed of low-porosity sandstones and carbonate into which natural gas has migrated from other sources.  Extraction of the natural gas from tight gas reservoirs is often performed using horizontal wells.  Hydraulic fracturing is often used in tight sands (U.S. DOE, 2009).
   * Coalbed Methane:  Natural gas is present in a coal bed due to the activity of microbes in the coal or from alterations of the coal through temperature changes.  Horizontal drilling is used but given that coalbed methane reservoirs are frequently associated with underground water reservoirs, hydraulic fracturing is often restricted (Andrews, 2009).
Natural Gas Processing
      Natural gas conditioning is the process of removing impurities from the gas stream so that it is of sufficient quality to pass through transportation systems and used by final consumers.  Conditioning is not always required.  Natural gas from some formations emerges from the well sufficiently pure that it can be sent directly to the pipeline.  As the natural gas is separated from the liquid components, it may contain impurities that pose potential hazards or other problems.
      The most significant impurity is H2S, which may or may not be contained in natural gas. H2S is toxic (and potentially fatal at certain concentrations) to humans and is corrosive for pipes.  It is therefore desirable to remove H2S as soon as possible in the conditioning process.
      Another concern is that posed by water vapor.  At high pressures, water can react with components in the gas to form gas hydrates, which are solids that can clog pipes, valves, and gauges, especially at cold temperatures (Manning and Thompson, 1991).  Nitrogen and other gases may also be mixed with the natural gas in the subsurface.  These other gases must be separated from the methane prior to sale.  High vapor pressure hydrocarbons that are liquids at surface temperature and pressure (benzene, toluene, ethylbenzene, and xylene, or BTEX) are removed and processed separately.
      Dehydration removes water from the gas stream.  Three main approaches toward dehydration are the use of a liquid or solid desiccant, and refrigeration.  When using a liquid desiccant, the gas is exposed to a glycol that absorbs the water.  The water can be evaporated from the glycol by a process called heat regeneration.  The glycol can then be reused.  Solid desiccants, often materials called molecular sieves, are crystals with high surface areas that attract the water molecules.  The solids can be regenerated simply by heating them above the boiling point of water.  Finally, particularly for gas extracted from deep, hot wells, simply cooling the gas to a temperature below the condensation point of water can remove enough water to transport the gas.  Of the three approaches mentioned above, glycol dehydration is the most common when processing at or near the well.
      Sweetening is the procedure in which H2S and sometimes CO2 are removed from the gas stream.  The most common method is amine treatment.  In this process, the gas stream is exposed to an amine solution, which will react with the H2S and separate them from the natural gas.  The contaminant gas solution is then heated, thereby separating the gases and regenerating the amine.  The sulfur gas may be disposed of by flaring, incinerating, or when a market exists, sending it to a sulfur-recovery facility to generate elemental sulfur as a salable product.
Natural Gas Transmission and Distribution
      After processing, natural gas enters a network of compressor stations, high-pressure transmission pipelines, and often-underground storage sites.  Compressor stations are any facility which supplies energy to move natural gas at increased pressure in transmission pipelines or into underground storage.  Typically, compressor stations are located at intervals along a transmission pipeline to maintain desired pressure for natural gas transport.  These stations will use either large internal combustion engines or gas turbines as prime movers to provide the necessary horsepower to maintain system pressure.  Underground storage facilities are subsurface facilities utilized for storing natural gas which has been transferred from its original location for the primary purpose of load balancing, which is the process of equalizing the receipt and delivery of natural gas.  Processes and operations that may be located at underground storage facilities include compression and dehydration.
Reserves and Markets
      Crude oil and natural gas have historically served two separate and distinct markets.  Oil is an international commodity, transported and consumed throughout the world.  Natural gas, on the other hand, has historically been consumed close to where it is produced.  However, as pipeline infrastructure and LNG trade expand, natural gas is increasingly a national and international commodity.  The following subsections provide historical and forecast data on the U.S. reserves, production, consumption, and foreign trade of crude oil and natural gas.
Domestic Proved Reserves
      Table 2-1 shows crude oil and dry natural gas proved reserves, inferred reserves, undiscovered technically recoverable resources and total technically recoverable resources as of 2007.  According to EIA, these concepts are defined as:
         *          Proved reserves: estimated quantities of energy sources that analysis of geologic and engineering data demonstrates with reasonable certainty are recoverable under existing economic and operating conditions.
         *          Inferred reserves: the estimate of total volume recovery from known crude oil or natural gas reservoirs or aggregation of such reservoirs is expected to increase during the time between discovery and permanent abandonment.
         *          Technically recoverable: resources that are producible using current technology without reference to the economic viability of production.
According to EIA, dry natural gas is consumer-grade natural gas.  The dry natural gas volumes reported in Table 2-1 reflect the amount of gas remaining after liquefiable portion has been removed from the natural gas, as well as any non-hydrocarbon gases that render the natural gas unmarketable have been removed.  The sum of proved reserves, inferred reserves, and undiscovered technically recoverable resources equal the total technically recoverable resources.  As seen in Table 2-1, as of 2007, proved domestic crude oil reserves accounted for about 12 percent of the totally technically recoverable crude oil resources.

Table 2-1	Technically Recoverable Crude Oil and Natural Gas Resource Estimates, 2007
                                    Region
                                   Proved
                                   Reserves
                               Inferred Reserves
                Undiscovered Technically Recoverable Resources
                    Total Technically Recoverable Resources
Crude Oil and Lease Condensate (billion bbl)

   48 States Onshore
                                                                           14.2
                                                                           48.3
                                                                           25.3
                                                                           87.8
   48 States Offshore
                                                                            4.4
                                                                           10.3
                                                                           47.2
                                                                           61.9
   Alaska
                                                                            4.2
                                                                            2.1
                                                                           42.0
                                                                           48.3
   Total U.S.
                                                                           22.8
                                                                           60.7
                                                                          114.5
                                                                          198.0

Dry Natural Gas (tcf)

   Conventionally Reservoired Fields
                                                                          194.0
                                                                          671.3
                                                                          760.4
                                                                         1625.7
      48 States Onshore Non-Associated Gas
                                                                          149.0
                                                                          595.9
                                                                          144.1
                                                                          889.0
      48 States Offshore Non-Associated Gas
                                                                           12.4
                                                                           50.7
                                                                          233.0
                                                                          296.0
      Associated-Dissolved Gas
                                                                           20.7

                                                                          117.2
                                                                          137.9
      Alaska
                                                                           11.9
                                                                           24.8
                                                                          266.1
                                                                          302.8
   Shale Gas and Coalbed Methane
                                                                           43.7
                                                                          385.0
                                                                           64.2
                                                                          493.0
   Total U.S.
                                                                          237.7
                                                                         1056.3
                                                                          824.6
                                                                         2118.7
Source: U.S. Energy Information Administration, Annual Energy Review 2010.  Inferred reserves for associated-dissolved natural gas are included in "Undiscovered Technically Recoverable Resources."  Totals may not sum due to independent rounding.

Proved natural gas reserves accounted for about 11 percent of the totally technically recoverable natural gas resources.  Significant proportions of these reserves exist in Alaska and offshore areas.  While the dry natural gas proved reserves in 2007 were estimated at 237.7 tcf, wet natural gas reserves were estimated at 247.8 tcf.  Of this difference, about 9.1 tcf is accounted for by natural gas liquids.  Of the 247.8 tcf, 215.1 tcf (about 87 percent) is considered to be wet non-associated natural gas, while 32.7 tcf (about 13 percent) is considered to be wet associated-dissolved natural gas.  Associated-dissolved natural gas, according to EIA, is natural gas which occurs in crude oil reservoirs as free natural gas or in solution with crude oil.
      Table 2-2 and Figure 2-1 show trends in crude oil and natural gas production and reserves from 1990 to 2008.  In Table 2-2, proved ultimate recovery equals the sum of cumulative production and proved reserves.  While crude oil and natural gas are nonrenewable resources, the table shows that proved ultimate recovery rises over time as new discoveries become economically accessible.  Reserves growth and decline is also partly a function of exploration activities, which are correlated with oil and natural gas prices.  For example, when oil prices are high there is more of an incentive to use secondary and tertiary recovery, as well as to develop unconventional sources.

Table 2-2	Crude Oil and Natural Gas Cumulative Domestic Production, Proved Reserves, and Proved Ultimate Recovery, 1977-2008

                      Crude Oil and Lease Condensate
                                 (million bbl)
                              Dry Natural Gas
                                     (bcf)
                                     Year
                                 Cumulative
                                  Production
                                   Proved
                                   Reserves
                                   Proved
                                  Ultimate
                                   Recovery
                                  Cumulative
                                  Production
                                   Proved
                                   Reserves
                                   Proved
                                   Ultimate
                                   Recovery
                                     1990
                                    158,175
                                    27,556
                                    185,731
                                    744,546
                                    169,346
                                    913,892
                                     1991
                                    160,882
                                    25,926
                                    186,808
                                    762,244
                                    167,062
                                    929,306
                                     1992
                                    163,507
                                    24,971
                                    188,478
                                    780,084
                                    165,015
                                    945,099
                                     1993
                                    166,006
                                    24,149
                                    190,155
                                    798,179
                                    162,415
                                    960,594
                                     1994
                                    168,438
                                    23,604
                                    192,042
                                    817,000
                                    163,837
                                    980,837
                                     1995
                                    170,832
                                    23,548
                                    194,380
                                    835,599
                                    165,146
                                   1,000,745
                                     1996
                                    173,198
                                    23,324
                                    196,522
                                    854,453
                                    166,474
                                   1,020,927
                                     1997
                                    175,553
                                    23,887
                                    199,440
                                    873,355
                                    167,223
                                   1,040,578
                                     1998
                                    177,835
                                    22,370
                                    200,205
                                    892,379
                                    164,041
                                   1,056,420
                                     1999
                                    179,981
                                    23,168
                                    203,149
                                    911,211
                                    167,406
                                   1,078,617
                                     2000
                                    182,112
                                    23,517
                                    205,629
                                    930,393
                                    177,427
                                   1,107,820
                                     2001
                                    184,230
                                    23,844
                                    208,074
                                    950,009
                                    183,460
                                   1,133,469
                                     2002
                                    186,327
                                    24,023
                                    210,350
                                    968,937
                                    186,946
                                   1,155,883
                                     2003
                                    188,400
                                    23,106
                                    211,506
                                    988,036
                                    189,044
                                   1,177,080
                                     2004
                                    190,383
                                    22,592
                                    212,975
                                   1,006,564
                                    192,513
                                   1,199,077
                                     2005
                                    192,273
                                    23,019
                                    215,292
                                   1,024,638
                                    204,385
                                   1,229,023
                                     2006
                                    194,135
                                    22,131
                                    216,266
                                   1,043,114
                                    211,085
                                   1,254,199
                                     2007
                                    196,079
                                    22,812
                                    218,891
                                   1,062,203
                                    237,726
                                   1,299,929
                                     2008
                                    197,987
                                    20,554
                                    218,541
                                   1,082,489
                                    244,656
                                   1,327,145
Source: U.S. Energy Information Administration, Annual Energy Review 2010.

However, annual production as a percentage of proved reserves has declined over time for both crude oil and natural gas, from above 10 percent in the early 1990s to 8 to 9 percent from 2006 to 2008 for crude oil and from above 11 percent during the 1990s to about 8 percent from 2008 to 2008 for natural gas.

Figure 2-1	A) Domestic Crude Oil Proved Reserves and Cumulative Production, 1990-2008. B) Domestic Natural Gas Proved Reserves and Cumulative Production, 1990-2008

      Table 2-3 presents the U.S. proved reserves of crude oil and natural gas by state or producing area as of 2008.  Four areas currently account for 77 percent of the U.S. total proved reserves of crude oil, led by Texas and followed by U.S. Federal Offshore, Alaska, and California.  The top five states (Texas, Wyoming, Colorado, Oklahoma, and New Mexico) account for about 69 percent of the U.S. total proved reserves of natural gas.

Table 2-3	Crude Oil and Dry Natural Gas Proved Reserves by State, 2008
State/Region
                                   Crude Oil
                                (million bbls)
                               Dry Natural Gas
                                     (bcf)
                                   Crude Oil
                               (percent of total)
                                Dry Natural Gas
                               (percent of total)
Alaska
                                     3,507
                                     7,699
                                     18.3
                                      3.1
Alabama
                                      38
                                     3,290
                                      0.2
                                      1.3
Arkansas
                                      30
                                     5,626
                                      0.2
                                      2.3
California
                                     2,705
                                     2,406
                                     14.1
                                      1.0
Colorado
                                      288
                                    23,302
                                      1.5
                                      9.5
Florida
                                       3
                                       1
                                      0.0
                                      0.0
Illinois
                                      54
                                       0
                                      0.3
                                      0.0
Indiana
                                      15
                                       0
                                      0.1
                                      0.0
Kansas
                                      243
                                     3,557
                                      1.3
                                      1.5
Kentucky
                                      17
                                     2,714
                                      0.1
                                      1.1
Louisiana
                                      388
                                    11,573
                                      2.0
                                      4.7
Michigan
                                      48
                                     3,174
                                      0.3
                                      1.3
Mississippi
                                      249
                                     1,030
                                      1.3
                                      0.4
Montana
                                      321
                                     1,000
                                      1.7
                                      0.4
Nebraska
                                       8
                                       0
                                      0.0
                                      0.0
New Mexico
                                      654
                                    16,285
                                      3.4
                                      6.7
New York
                                       0
                                      389
                                      0.0
                                      0.2
North Dakota
                                      573
                                      541
                                      3.0
                                      0.2
Ohio
                                      38
                                      985
                                      0.2
                                      0.4
Oklahoma
                                      581
                                    20,845
                                      3.0
                                      8.5
Pennsylvania
                                      14
                                     3,577
                                      0.1
                                      1.5
Texas
                                     4,555
                                    77,546
                                     23.8
                                     31.7
Utah
                                      286
                                     6,643
                                      1.5
                                      2.7
Virginia
                                       0
                                     2,378
                                      0.0
                                      1.0
West Virginia
                                      23
                                     5,136
                                      0.1
                                      2.1
Wyoming
                                      556
                                    31,143
                                      2.9
                                     12.7
Miscellaneous States
                                      24
                                      270
                                      0.1
                                      0.1
U.S. Federal Offshore
                                     3,903
                                    13,546
                                     20.4
                                      5.5
Total Proved Reserves
                                    19,121
                                    244,656
                                     100.0
                                     100.0
Source: U.S. Energy Information Administration, Annual Energy Review 2010.  Totals may not sum due to independent rounding.

Domestic Production
      Domestic oil production is currently in a state of decline that began in 1970. Table 2-4 shows U.S. production in 2009 at 1938 million bbl per year, the highest level since 2004.  However, annual domestic production of crude oil has dropped by almost 750 million bbl since 1990.

Table 2-4	Crude Oil Domestic Production, Wells, Well Productivity, and U.S. Average First Purchase Price
                                     Year
                        Total Production (million bbl)
                            Producing Wells (1000s)
                       Avg. Well Productivity (bbl/well)
            U.S. Average First Purchase Price/Barrel (2005 dollars)
                                     1990
                                     2,685
                                      602
                                     4,460
                                     27.74
                                     1991
                                     2,707
                                      614
                                     4,409
                                     22.12
                                     1992
                                     2,625
                                      594
                                     4,419
                                     20.89
                                     1993
                                     2,499
                                      584
                                     4,279
                                     18.22
                                     1994
                                     2,431
                                      582
                                     4,178
                                     16.51
                                     1995
                                     2,394
                                      574
                                     4,171
                                     17.93
                                     1996
                                     2,366
                                      574
                                     4,122
                                     22.22
                                     1997
                                     2,355
                                      573
                                     4,110
                                     20.38
                                     1998
                                     2,282
                                      562
                                     4,060
                                     12.71
                                     1999
                                     2,147
                                      546
                                     3,932
                                     17.93
                                     2000
                                     2,131
                                      534
                                     3,990
                                     30.14
                                     2001
                                     2,118
                                      530
                                     3,995
                                     24.09
                                     2002
                                     2,097
                                      529
                                     3,964
                                     24.44
                                     2003
                                     2,073
                                      513
                                     4,042
                                     29.29
                                     2004
                                     1,983
                                      510
                                     3,889
                                     38.00
                                     2005
                                     1,890
                                      498
                                     3,795
                                     50.28
                                     2006
                                     1,862
                                      497
                                     3,747
                                     57.81
                                     2007
                                     1,848
                                      500
                                     3,697
                                     62.63
                                     2008
                                     1,812
                                      526
                                     3,445
                                     86.69
                                     2009
                                     1,938
                                      526
                                     3,685
                                    51.37*
Source: U.S. Energy Information Administration, Annual Energy Review 2010.
First purchase price represents the average price at the lease or wellhead at which domestic crude is purchased. * 2009 Oil price is preliminary

Average well productivity has also decreased since 1990 (Table 2-4 and Figure 2-2).  These production and productivity decreases are in spite of the fact that average first purchase prices have shown a generally increasing trend.  The exception to this general trend occurred in 2008 and 2009 when the real price increased up to 86 dollars per barrel and production in 2009 increased to almost 2 million bbl of oil.
      Annual production of natural gas from natural gas wells has increased nearly 3000 bcf from the 1990 to 2009 (Table 2-5).  Natural gas extracted from crude oil wells (associated natural gas) has remained more or less constant for the last twenty years.  Coalbed methane has become a significant component of overall gas withdrawals in recent years.

Table 2-5	Natural Gas Production and Well Productivity, 1990-2009

                       Natural Gas Gross Withdrawals
                                     (bcf)
                             Natural Gas Well
                                 Productivity
                                     Year
                                Natural Gas
                                     Wells
                                 Crude Oil
                                     Wells
                               Coalbed Methane
                                     Wells
                                     Total
                              Dry Gas Production*
                             Producing Wells (no.)
                       Avg. Productivity per Well (MMcf)
                                     1990
                                    16,054
                                     5,469
                                      NA
                                    21,523
                                    17,810
                                    269,100
                                    59.657
                                     1991
                                    16,018
                                     5,732
                                      NA
                                    21,750
                                    17,698
                                    276,337
                                    57.964
                                     1992
                                    16,165
                                     5,967
                                      NA
                                    22,132
                                    17,840
                                    275,414
                                    58.693
                                     1993
                                    16,691
                                     6,035
                                      NA
                                    22,726
                                    18,095
                                    282,152
                                    59.157
                                     1994
                                    17,351
                                     6,230
                                      NA
                                    23,581
                                    18,821
                                    291,773
                                    59.468
                                     1995
                                    17,282
                                     6,462
                                      NA
                                    23,744
                                    18,599
                                    298,541
                                    57.888
                                     1996
                                    17,737
                                     6,376
                                      NA
                                    24,114
                                    18,854
                                    301,811
                                    58.770
                                     1997
                                    17,844
                                     6,369
                                      NA
                                    24,213
                                    18,902
                                    310,971
                                    57.382
                                     1998
                                    17,729
                                     6,380
                                      NA
                                    24,108
                                    19,024
                                    316,929
                                    55.938
                                     1999
                                    17,590
                                     6,233
                                      NA
                                    23,823
                                    18,832
                                    302,421
                                    58.165
                                     2000
                                    17,726
                                     6,448
                                      NA
                                    24,174
                                    19,182
                                    341,678
                                    51.879
                                     2001
                                    18,129
                                     6,371
                                      NA
                                    24,501
                                    19,616
                                    373,304
                                    48.565
                                     2002
                                    17,795
                                     6,146
                                      NA
                                    23,941
                                    18,928
                                    387,772
                                    45.890
                                     2003
                                    17,882
                                     6,237
                                      NA
                                    24,119
                                    19,099
                                    393,327
                                    45.463
                                     2004
                                    17,885
                                     6,084
                                      NA
                                    23,970
                                    18,591
                                    406,147
                                    44.036
                                     2005
                                    17,472
                                     5,985
                                      NA
                                    23,457
                                    18,051
                                    425,887
                                    41.025
                                     2006
                                    17,996
                                     5,539
                                      NA
                                    23,535
                                    18,504
                                    440,516
                                    40.851
                                     2007
                                    17,065
                                     5,818
                                     1,780
                                    24,664
                                    19,266
                                    452,945
                                    37.676
                                     2008
                                    18,011
                                     5,845
                                     1,898
                                    25,754
                                    20,286
                                    478,562
                                    37.636
                                     2009
                                    18,881
                                     5,186
                                     2,110
                                    26,177
                                    20,955
                                    495,697
                                    38.089
Source: U.S. Energy Information Administration, Annual Energy Review 2010.
*Dry gas production is gas production after accounting for gas used repressurizing wells, the removal of
nonhydrocarbon gases, vented and flared gas, and gas used as fuel during the production process.

The number of wells producing natural gas wells has nearly doubled between 1990 and 2009 (Figure 2-2).  While the number of producing wells has increased overall, average well productivity has declined, despite improvements in exploration and gas well stimulation technologies.

Figure 2-2	A) Total Producing Crude Oil Wells and Average Well Productivity, 1990-2009.  B) Total Producing Natural Gas Wells and Average Well Productivity, 1990-2009.

      Domestic exploration and development for oil has continued during the last two decades.  From 2002 to 2009, crude oil well drilling showed significant increases, although the 1992-2001 period showed relatively low levels of crude drilling activity compared to periods before and after (Table 2-6).  The drop in 2009 showed a departure from this trend, likely due to the recession experienced in the U.S.
      Meanwhile, natural gas drilling has increased significantly during the 1990-2009 period.  Like crude oil drilling, 2009 saw a relatively low level of natural gas drillings.  The success rate of wells (producing wells versus dry wells) has also increased gradually over time from 75 percent in 1990, to 86 percent in 2000, to 90 percent in 2009 (Table 2-6).  The increasing success rate reflects improvements in exploration technology, as well as technological improvements in well drilling and completion.  Similarly, well average depth has also increased by during this period (Table 2-6).
Table 2-6	Crude Oil and Natural Gas Exploratory and Development Wells and Average Depth, 1990-2009

                                Wells Drilled

                                     Year
                                  Crude Oil
                                 Natural Gas
                                  Dry Holes
                                     Total
                          Successful Wells (percent)
                              Average Depth (ft)
                                     1990
                                    12,800
                                    11,227
                                     8,237
                                    32,264
                                      75
                                     4,841
                                     1991
                                    12,542
                                     9,768
                                     7,476
                                    29,786
                                      75
                                     4,872
                                     1992
                                     9,379
                                     8,149
                                     5,857
                                    23,385
                                      75
                                     5,138
                                     1993
                                     8,828
                                     9,829
                                     6,093
                                    24,750
                                      75
                                     5,407
                                     1994
                                     7,334
                                     9,358
                                     5,092
                                    21,784
                                      77
                                     5,736
                                     1995
                                     8,230
                                     8,081
                                     4,813
                                    21,124
                                      77
                                     5,560
                                     1996
                                     8,819
                                     9,015
                                     4,890
                                    22,724
                                      79
                                     5,573
                                     1997
                                    11,189
                                    11,494
                                     5,874
                                    28,557
                                      79
                                     5,664
                                     1998
                                     7,659
                                    11,613
                                     4,763
                                    24,035
                                      80
                                     5,722
                                     1999
                                     4,759
                                    11,979
                                     3,554
                                    20,292
                                      83
                                     5,070
                                     2000
                                     8,089
                                    16,986
                                     4,134
                                    29,209
                                      86
                                     4,942
                                     2001
                                     8,880
                                    22,033
                                     4,564
                                    35,477
                                      87
                                     5,077
                                     2002
                                     6,762
                                    17,297
                                     3,728
                                    27,787
                                      87
                                     5,223
                                     2003
                                     8,104
                                    20,685
                                     3,970
                                    32,759
                                      88
                                     5,418
                                     2004
                                     8,764
                                    24,112
                                     4,053
                                    36,929
                                      89
                                     5,534
                                     2005E
                                    10,696
                                    28,500
                                     4,656
                                    43,852
                                      89
                                     5,486
                                     2006E
                                    13,289
                                    32,878
                                     5,183
                                    51,350
                                      90
                                     5,537
                                     2007E
                                    13,564
                                    33,132
                                     5,121
                                    51,817
                                      90
                                     5,959
                                     2008E
                                    17,370
                                    34,118
                                     5,726
                                    57,214
                                      90
                                     6,202
                                     2009E
                                    13,175
                                    19,153
                                     3,537
                                    35,865
                                      90
                                     6,108
Source: U.S. Energy Information Administration, Annual Energy Review 2010. Values for 2005-2009 are estimates.

      Produced water is an important byproduct of the oil and natural gas industry, as management, including reuse and recycling, of produced water can be costly and challenging.  Texas, California, Wyoming, Oklahoma, and Kansas were the top five states in terms of produced water volumes in 2007 (Table 2-7).  These estimates do not include estimates of flowback water from hydraulic fracturing activities (ANL 2009).
Table 2-7	U.S. Onshore and Offshore Oil, Gas, and Produced Water Generation, 2007
                                    State
                                   Crude Oil
                                  (1000 bbl)
                                  Total Gas
                                    (bcf)
                                Produced Water
                                  (1000 bbl)
             Total Oil and Natural Gas (1000 bbls oil equivalent)
               Barrels Produced Water per Barrel Oil Equivalent
Alabama
                                                                          5,028
                                                                            285
                                                                        119,004
                                                                         55,758
                                                                           2.13
Alaska
                                                                        263,595
                                                                          3,498
                                                                        801,336
                                                                        886,239
                                                                           0.90
Arizona
                                                                             43
                                                                              1
                                                                             68
                                                                            221
                                                                           0.31
Arkansas
                                                                          6,103
                                                                            272
                                                                        166,011
                                                                         54,519
                                                                           3.05
California
                                                                        244,000
                                                                            312
                                                                      2,552,194
                                                                        299,536
                                                                           8.52
Colorado
                                                                          2,375
                                                                          1,288
                                                                        383,846
                                                                        231,639
                                                                           1.66
Florida
                                                                          2,078
                                                                              2
                                                                         50,296
                                                                          2,434
                                                                          20.66
Illinois
                                                                          3,202
                                                                        no data
                                                                        136,872
                                                                          3,202
                                                                          42.75
Indiana
                                                                          1,727
                                                                              4
                                                                         40,200
                                                                          2,439
                                                                          16.48
Kansas
                                                                         36,612
                                                                            371
                                                                      1,244,329
                                                                        102,650
                                                                          12.12
Kentucky
                                                                          3,572
                                                                             95
                                                                         24,607
                                                                         20,482
                                                                           1.20
Louisiana
                                                                         52,495
                                                                          1,382
                                                                      1,149,643
                                                                        298,491
                                                                           3.85
Michigan
                                                                          5,180
                                                                            168
                                                                        114,580
                                                                         35,084
                                                                           3.27
Mississippi
                                                                         20,027
                                                                             97
                                                                        330,730
                                                                         37,293
                                                                           8.87
Missouri
                                                                             80
                                                                        no data
                                                                          1,613
                                                                             80
                                                                          20.16
Montana
                                                                         34,749
                                                                             95
                                                                        182,266
                                                                         51,659
                                                                           3.53
Nebraska
                                                                          2,335
                                                                              1
                                                                         49,312
                                                                          2,513
                                                                          19.62
Nevada
                                                                            408
                                                                              0
                                                                          6,785
                                                                            408
                                                                          16.63
New Mexico
                                                                         59,138
                                                                          1,526
                                                                        665,685
                                                                        330,766
                                                                           2.01
New York
                                                                            378
                                                                             55
                                                                            649
                                                                         10,168
                                                                           0.06
North Dakota
                                                                         44,543
                                                                             71
                                                                        134,991
                                                                         57,181
                                                                           2.36
Ohio
                                                                          5,422
                                                                             86
                                                                          6,940
                                                                         20,730
                                                                           0.33
Oklahoma
                                                                         60,760
                                                                          1,643
                                                                      2,195,180
                                                                        353,214
                                                                           6.21
Pennsylvania
                                                                          1,537
                                                                            172
                                                                          3,912
                                                                         32,153
                                                                           0.12
South Dakota
                                                                          1,665
                                                                             12
                                                                          4,186
                                                                          3,801
                                                                           1.10
Tennessee
                                                                            350
                                                                              1
                                                                          2,263
                                                                            528
                                                                           4.29
Texas
                                                                        342,087
                                                                          6,878
                                                                      7,376,913
                                                                      1,566,371
                                                                           4.71
Utah
                                                                         19,520
                                                                            385
                                                                        148,579
                                                                         88,050
                                                                           1.69
Virginia
                                                                             19
                                                                            112
                                                                          1,562
                                                                         19,955
                                                                           0.08
West Virginia
                                                                            679
                                                                            225
                                                                          8,337
                                                                         40,729
                                                                           0.20
Wyoming
                                                                         54,052
                                                                          2,253
                                                                      2,355,671
                                                                        455,086
                                                                           5.18
State Total
                                                                      1,273,759
                                                                         21,290
                                                                     20,258,560
                                                                      5,063,379
                                                                           4.00
Federal Offshore
                                                                        467,180
                                                                          2,787
                                                                        587,353
                                                                        963,266
                                                                           0.61
Tribal Lands
                                                                          9,513
                                                                            297
                                                                        149,261
                                                                         62,379
                                                                           2.39
Federal Total
                                                                        476,693
                                                                          3,084
                                                                        736,614
                                                                      1,025,645
                                                                           0.72
U.S. Total
                                                                      1,750,452
                                                                         24,374
                                                                     20,995,174
                                                                      6,089,024
                                                                           3.45
Source: Argonne National Laboratory and Department of Energy (2009).  Natural gas production converted to barrels oil equivalent to facilitate comparison using the conversion of 0.178 barrels of crude oil equals 1000 cubic feet natural gas.  Totals may not sum due to independent rounding.

      As can be seen in Table 2-7, the amount of water produced is not necessarily correlated with the ratio of water produced to the volume of oil or natural gas produced.  Texas, Alaska and Wyoming were the three largest producers in barrels of oil equivalent (boe) terms, but had relatively low rates of water production compared to more Midwestern states, such Illinois, Missouri, Indiana, and Kansas.
      Figure 2-3 shows the distribution of produced water management practices in 2007.

Figure 2-3	U.S. Produced Water Volume by Management Practice, 2007

More than half of the water produced (51 percent) was re-injected to enhance resource recovery through maintaining reservoir pressure or hydraulically pushing oil from the reservoir.  Another third (34 percent) was injected, typically into wells whose primary purpose is to sequester produced water.  A small percentage (three percent) is discharged into surface water when it meets water quality criteria.  The destination of the remaining produced water (11 percent, the difference between the total managed and total generated) is uncertain (ANL, 2009).
      The movement of crude oil and natural gas primarily takes place via pipelines.  Total crude oil pipeline mileage has decreased during the 1990-2008 period (Table 2-8), appearing to follow the downward supply trend shown in Table 2-4.  While exhibiting some variation, pipeline mileage transporting refined products remained relatively constant.

Table 2-8	U.S. Oil and Natural Gas Pipeline Mileage, 1990-2008

                                 Oil Pipelines

                             Natural Gas Pipelines
                                     Year
                                  Crude Lines
                                 Product Lines
                                     Total

                              Distribution Mains
                            Transmission Pipelines
                                Gathering Lines
                                     Total
                                     1990
                                    118,805
                                    89,947
                                    208,752

                                    945,964
                                    291,990
                                    32,420
                                   1,270,374
                                     1991
                                    115,860
                                    87,968
                                    203,828

                                    890,876
                                    293,862
                                    32,713
                                   1,217,451
                                     1992
                                    110,651
                                    85,894
                                    196,545

                                    891,984
                                    291,468
                                    32,629
                                   1,216,081
                                     1993
                                    107,246
                                    86,734
                                    193,980

                                    951,750
                                    293,263
                                    32,056
                                   1,277,069
                                     1994
                                    103,277
                                    87,073
                                    190,350

                                   1,002,669
                                    301,545
                                    31,316
                                   1,335,530
                                     1995
                                    97,029
                                    84,883
                                    181,912

                                   1,003,798
                                    296,947
                                    30,931
                                   1,331,676
                                     1996
                                    92,610
                                    84,925
                                    177,535

                                    992,860
                                    292,186
                                    29,617
                                   1,314,663
                                     1997
                                    91,523
                                    88,350
                                    179,873

                                   1,002,942
                                    294,370
                                    34,463
                                   1,331,775
                                     1998
                                    87,663
                                    90,985
                                    178,648

                                   1,040,765
                                    302,714
                                    29,165