1,667,593
                                                                        870,812
                                                                        179,781
                                       7
Northern Natural Gas Co.
                                                                         15,028
                                                                        922,745
                                                                        690,863
                                                                        171,427
                                       8
Florida Gas Transmission Co. LLC
                                                                          4,852
                                                                        821,297
                                                                        520,641
                                                                        164,792
                                       9
Tennessee Gas Pipeline Co.
                                                                         14,113
                                                                      1,704,976
                                                                        820,273
                                                                        147,378
                                      10
Southern Natural Gas Co.
                                                                          7,563
                                                                        867,901
                                                                        510,500
                                                                        137,460
                                      11
El Paso Natural Gas Co.
                                                                         10,235
                                                                      1,493,213
                                                                        592,503
                                                                        126,000
                                      12
Gas Transmission Northwest Corp.
                                                                          1,356
                                                                        809,206
                                                                        216,526
                                                                        122,850
                                      13
Rockies Express Pipeline LLC
                                                                          1,682
                                                                        721,840
                                                                        555,288
                                                                        117,243
                                      14
CenterPoint Energy Gas Transmission Co.
                                                                          6,162
                                                                      1,292,931
                                                                        513,315
                                                                        116,979
                                      15
Colorado Interstate Gas Co.
                                                                          4,200
                                                                        839,184
                                                                        384,517
                                                                        108,483
                                      16
Kern River Gas Transmission Co.
                                                                          1,680
                                                                        789,858
                                                                        371,951
                                                                        103,430
                                      17
Trunkline LNG Co. LLC
                                                                             --
                                                                             --
                                                                        134,150
                                                                        101,920
                                      18
Northwest Pipeline GP
                                                                          3,895
                                                                        817,832
                                                                        434,379
                                                                         99,340
                                      19
Texas Gas Transmission LLC
                                                                          5,881
                                                                      1,006,906
                                                                        361,406
                                                                         91,575
                                      20
Algonquin Gas Transmission LLC
                                                                          1,128
                                                                        388,366
                                                                        237,291
                                                                         82,472

TOTAL FOR TOP 20
                                                                        124,903
                                                                     21,097,914
                                                                     11,510,401
                                                                      3,021,774

TOTAL FOR ALL COMPANIES
                                                                        198,381
                                                                     38,793,532
                                                                     18,934,674
                                                                      4,724,456
Source: Oil and Gas Journal. "Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil Profits Grow." November 1, 2010.

Financial Performance and Condition
	From a broad industry perspective, the EIA Financial Reporting System (FRS) collects financial and operating information from a subset of the U.S. major energy producing companies.  This information is used in annual report to Congress, as well as is released to the public in aggregate form.  While the companies that report information to FRS each year changes, EIA makes an effort to retain sufficient consistency such that trends can be evaluated.  For 2008, there are 27 companies in the FRS  that accounted for 41 percent of total U.S. crude oil and NGL production, 43 percent of natural gas production, 77 percent of U.S. refining capacity, and 0.2 percent of U.S. electricity net generation (U.S. EIA, 2010).  Table 2-22 shows a series of financial trends in 2008 dollars selected and aggregated from FRS firms' financial statements.  The table shows operating revenues and expenses rising significantly from 1990 to 2008, with operating income (the difference between operating revenues and expenses) rising as well.  Interest expenses remained relatively flat during this period.  Meanwhile, recent years have shown that other income and income taxes have played a more significant role for the industry.  Net income has risen as well, although 2008 saw a decline from previous periods, as oil and natural gas prices declined significantly during the latter half of 2008.
Table 2-22	Selected Financial Items from Income Statements (Billion 2008 Dollars)
                                     Year
                              Operating Revenues
                              Operating Expenses
                               Operating Income
                               Interest Expense
                                 Other Income*
                                 Income Taxes
                                  Net Income
                                     1990
                                                                          766.9
                                                                          706.4
                                                                           60.5
                                                                           16.8
                                                                           13.6
                                                                           24.8
                                                                           32.5
                                     1991
                                                                          673.4
                                                                          635.7
                                                                           37.7
                                                                           14.4
                                                                           13.4
                                                                           15.4
                                                                           21.3
                                     1992
                                                                          670.2
                                                                          637.2
                                                                           33.0
                                                                           12.7
                                                                           -5.6
                                                                           12.2
                                                                            2.5
                                     1993
                                                                          621.4
                                                                          586.6
                                                                           34.8
                                                                           11.0
                                                                           10.3
                                                                           12.7
                                                                           21.5
                                     1994
                                                                          606.5
                                                                          565.6
                                                                           40.9
                                                                           10.8
                                                                            6.8
                                                                           14.4
                                                                           22.5
                                     1995
                                                                          640.8
                                                                          597.5
                                                                           43.3
                                                                           11.1
                                                                           12.9
                                                                           17.0
                                                                           28.1
                                     1996
                                                                          706.8
                                                                          643.3
                                                                           63.6
                                                                            9.1
                                                                           13.4
                                                                           26.1
                                                                           41.8
                                     1997
                                                                          673.6
                                                                          613.8
                                                                           59.9
                                                                            8.2
                                                                           13.4
                                                                           23.9
                                                                           41.2
                                     1998
                                                                          614.2
                                                                          594.1
                                                                           20.1
                                                                            9.2
                                                                           11.0
                                                                            6.0
                                                                           15.9
                                     1999
                                                                          722.9
                                                                          682.6
                                                                           40.3
                                                                           10.9
                                                                           12.7
                                                                           13.6
                                                                           28.6
                                     2000
                                                                        1,114.3
                                                                        1,011.8
                                                                          102.5
                                                                           12.9
                                                                           18.4
                                                                           42.9
                                                                           65.1
                                     2001
                                                                          961.8
                                                                          880.3
                                                                           81.5
                                                                           10.8
                                                                            7.6
                                                                           33.1
                                                                           45.2
                                     2002
                                                                          823.0
                                                                          776.9
                                                                           46.2
                                                                           12.7
                                                                            7.9
                                                                           17.2
                                                                           24.3
                                     2003
                                                                          966.9
                                                                          872.9
                                                                           94.0
                                                                           10.1
                                                                           19.5
                                                                           37.2
                                                                           66.2
                                     2004
                                                                        1,188.5
                                                                        1,051.1
                                                                          137.4
                                                                           12.4
                                                                           20.1
                                                                           54.2
                                                                           90.9
                                     2005
                                                                        1,447.3
                                                                        1,263.8
                                                                          183.5
                                                                           11.6
                                                                           34.6
                                                                           77.1
                                                                          129.3
                                     2006
                                                                        1,459.0
                                                                        1,255.0
                                                                          204.0
                                                                           12.4
                                                                           41.2
                                                                           94.8
                                                                          138.0
                                     2007
                                                                        1,475.0
                                                                        1,297.7
                                                                          177.3
                                                                           11.1
                                                                           47.5
                                                                           86.3
                                                                          127.4
                                     2008
                                                                        1,818.1
                                                                        1,654.0
                                                                          164.1
                                                                           11.4
                                                                           32.6
                                                                           98.5
                                                                           86.9
Source: Energy Information Administration, Form EIA-28 (Financial Reporting System). * Other Income includes other revenue and expense (excluding interest expense), discontinued operations, extraordinary items, and accounting changes.  Totals may not sum due to independent rounding.
      Table 2-23 shows in percentage terms the estimated return on investments for a variety of business lines, in 1998, 2003, and 2008, for FRS companies.  For U.S. petroleum-related business activities, oil and natural gas production has remained the most profitable line of business relative to refining/marketing and pipelines, sustaining a return on investment greater than 10 percent for the three years evaluated.  Returns to foreign oil and natural gas production rose above domestic production in 2008.  Electric power generation and sales emerged in 2008 as a highly profitable line of business for the FRS companies.

Table 2-23	Return on Investment for Lines of Business (all FRS), for 1998, 2003, and 2008 (percent)
Line of Business
                                     1998
                                     2003
                                     2008
Petroleum
                                     10.8
                                     13.4
                                     12.0
   U.S. Petroleum
                                      10
                                     13.7
                                      8.2
       Oil and Natural Gas Production
                                     12.5
                                     16.5
                                     10.7
       Refining/Marketing
                                      6.6
                                      9.3
                                      2.6
       Pipelines
                                      6.7
                                     11.5
                                      2.4
   Foreign Petroleum
                                     11.9
                                     13.0
                                     17.8
       Oil and Natural Gas Production
                                     12.5
                                     14.2
                                     16.3
       Refining/Marketing
                                     10.6
                                      8.0
                                     26.3
Downstream Natural Gas*
                                       -
                                      8.8
                                      5.1
Electric Power*
                                       -
                                      5.2
                                     181.4
Other Energy
                                      7.1
                                      2.8
                                     -2.1
Non-energy
                                     10.9
                                      2.4
                                     -5.3
Source: Energy Information Administration, Form EIA-28 (Financial Reporting System). Note: Return on investment measured as contribution to net income/net investment in place.  * The downstream natural gas and electric power lines of business were added to the EIA-28 survey form beginning with the 2003 reporting year.

	The oil and natural gas industry also produces significant tax revenues for local, state, and federal authorities.  Table 2-24 shows income and production tax trends from 1990 to 2008 for FRS companies.  The column with U.S. federal, state, and local taxes paid or accrued includes deductions for the U.S. Federal Investment Tax Credit ($198 million in 2008) and the effect of the Alternative Minimum Tax ($34 million in 2008). Income taxes paid to state and local authorizes were $3,060 million in 2008, about 13 percent of the total paid to U.S. authorities.
Table 2-24	Income and Production Taxes, 1990-2008 (Million 2008 Dollars)
                                     Year
             U.S. Federal, State, and Local Taxes Paid or Accrued
                                 Total Current
                                Total Deferred
                           Total Income Tax Expense

                    Other Non-Income Production Taxes Paid
                                     1990
                                                                          9,568
                                                                         25,056
                                                                           -230
                                                                         24,826

                                                                          4,341
                                     1991
                                                                          6,672
                                                                         18,437
                                                                         -3,027
                                                                         15,410

                                                                          3,467
                                     1992
                                                                          4,994
                                                                         16,345
                                                                         -4,116
                                                                         12,229

                                                                          3,097
                                     1993
                                                                          3,901
                                                                         13,983
                                                                         -1,302
                                                                         12,681

                                                                          2,910
                                     1994
                                                                          3,348
                                                                         13,556
                                                                            887
                                                                         14,443

                                                                          2,513
                                     1995
                                                                          6,817
                                                                         17,474
                                                                           -510
                                                                         16,965

                                                                          2,476
                                     1996
                                                                          8,376
                                                                         22,493
                                                                          3,626
                                                                         26,119

                                                                          2,922
                                     1997
                                                                          7,643
                                                                         20,764
                                                                          3,141
                                                                         23,904

                                                                          2,743
                                     1998
                                                                          1,199
                                                                          7,375
                                                                         -1,401
                                                                          5,974

                                                                          1,552
                                     1999
                                                                          2,626
                                                                         13,410
                                                                            140
                                                                         13,550

                                                                          2,147
                                     2000
                                                                         14,308
                                                                         36,187
                                                                          6,674
                                                                         42,861

                                                                          3,254
                                     2001
                                                                         10,773
                                                                         28,745
                                                                          4,351
                                                                         33,097

                                                                          3,042
                                     2002
                                                                            814
                                                                         17,108
                                                                             46
                                                                         17,154

                                                                          2,617
                                     2003
                                                                          9,274
                                                                         30,349
                                                                          6,879
                                                                         37,228

                                                                          3,636
                                     2004
                                                                         19,661
                                                                         50,185
                                                                          4,024
                                                                         54,209

                                                                          3,990
                                     2005
                                                                         29,993
                                                                         72,595
                                                                          4,529
                                                                         77,125

                                                                          5,331
                                     2006
                                                                         29,469
                                                                         85,607
                                                                          9,226
                                                                         94,834

                                                                          5,932
                                     2007
                                                                         28,332
                                                                         84,119
                                                                          2,188
                                                                         86,306

                                                                          7,501
                                     2008
                                                                         23,199
                                                                         95,590
                                                                          2,866
                                                                         98,456

                                                                         12,507
Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

	The difference between total current taxes and U.S. federal, state, and local taxes in includes taxes and royalties paid to foreign countries.  As can be seen in Table 2-24, foreign taxes paid far exceeds domestic taxes paid.  Other non-income production taxes paid, which have risen almost three-fold between 1990 and 2008, include windfall profit and severance taxes, as well as other production-related taxes.

References

Andrews, et al. 2009. Unconventional Gas Shales: Development, Technology, and Policy Issues. Congressional Research Service. R40894.
Argonne National Laboratory. 2009.  Produced Water Volumes and Management Practices in the United States.  ANL/EVS/R-09/1.
Hyne, N.J. 2001. Nontechnical Guide to Petroleum Geology, Exploration, Drilling and Production. Tulsa, OK: Penwell Books.
Independent Petroleum Association of America. 2009. Profile of Independent Producers. <http://www.ipaa.org/news/docs/IPAAProfile2009.pdf>  Accessed March 30, 2011.
Manning, F.S. and R.E. Thompson. 1991. Oil Field Processing of Petroleum  -  Volume 3: Produced and Injection Waters. Tulsa, OK: Penn Well Books.
Oil and Gas Journal. "Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil Profits Grow." November 1, 2010.
Oil and Gas Journal. "OGJ150 Financial Results Down in '09; Production, Reserves Up." September 6, 2010.
Oil and Gas Journal. "Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Processing Capacity Ahead in 2009." June 7, 2010.
U.S. Energy Information Administration (U.S. EIA). 2006. Natural Gas Processing: The Crucial Link between Natural Gas Production and Its Transportation to Market. <http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2006/ngprocess/ngprocess.pdf> Accessed February 2, 2011.

U.S. Department of Energy. 2009. Modern Shale Gas Development in the United States: A Primer. <http://www.netl.doe.gov/technologies/oil-gas/publications/EPreports/Shale_Gas_Primer_2009.pdf> Accessed March 30, 2011.
U.S. Energy Information Administration (U.S. EIA). 2010. Annual Energy Review (AER). <http://www.eia.doe.gov/emeu/aer/contents.html>
U.S. Energy Information Administration (U.S. EIA). 2010. Oil and Gas Lease Equipment and Operating Costs 1994 through 2009 <http://www.eia.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_production/current/coststudy.html>  Accessed March 30, 2011.
U.S. Energy Information Administration (U.S. EIA). 2010. Summary: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Proved Reserves 2009. <http://www.eia.doe.gov/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/cr.html> Accessed March 30, 2011.
U.S. Energy Information Administration (U.S. EIA). 2010. Performance Profiles of Major Energy Producers 2008. <http://www.eia.gov/finance/performanceprofiles> Accessed March 30, 2011.
U.S. Energy Information Administration (U.S. EIA). 2011. Annual Energy Outlook 2011. <http://www.eia.gov/forecasts/aeo> June 2, 2011.
U.S. Environmental Protection Agency (U.S. EPA), Office of Air Quality Planning and Standards. 1996. Economic Analysis of Air Pollution Regulations: Oil and Natural Gas Production. <http://www.epa.gov/ttnecas1/regdata/IPs/Oil%20and%20NG%20Production%20and%20NG%20Transmission_IP.pdf>  Accessed March 30, 2011.
U.S. Environmental Protection Agency (U.S. EPA). 2004. Impacts to Underground Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs. EPA/816-R-04-003.
U.S. Environmental Protection Agency. 2000. EPA Office of Compliance Sector Notebook Project: Profile of the Oil and Gas Extraction Industry.  EPA/310-R-99-006. <http://www.epa.gov/compliance/resources/publications/assistance/sectors/notebooks/oil.html> Accessed March 30, 2011.
Emissions and Engineering Costs
Introduction
This section includes three sets of discussions for both the final NSPS and NESHAP Amendments:
   * Emission Sources and Points
   * Emissions Control Options
   * Engineering Cost Analysis
Emissions Points, Controls, and Engineering Costs Analysis
	This section discusses the emissions points and pollution control options for the final NSPS and NESHAP Amendments.  This discussion of emissions points and control options is meant to assist the reader of the RIA in better understanding the economic impact analysis.  However, we provide reference to the detailed technical memoranda prepared by the Office of Air Quality Planning and Standards (OAQPS) for the reader interested in a greater level of detail.  This section also presents the engineering cost analysis, which provides a cost basis for the energy system, employment, and small business analyses.
      Before going into detail on emissions points and pollution controls, it is useful to provide estimates of overall emissions from the crude oil and natural gas industry to provide context for estimated reductions as a result of the final rules.  To estimate VOC emissions from the oil and gas sector, we modified the emissions estimate for the crude oil and natural gas sector in the 2008 National Emissions Inventory (NEI).  During this review, EPA identified VOC emissions from natural gas sources which are likely relatively under-represented in the NEI, natural gas well completions primarily.  Crude oil and natural gas sector VOC emissions estimated in the 2008 NEI total approximately 1.76 million tons.  Of these emissions, the NEI identifies about 21 thousand tons emitted from natural gas well completion processes.  We substituted the estimates of VOC emissions from natural gas well completions estimated as part of the engineering analysis (249,000 tons, which is discussed in more detail in the next section), bringing the total estimated VOC emissions from the crude oil and natural gas sector to about 1.99 million tons VOC.
      The Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009 (published April 2011) estimates 2009 methane emissions from Petroleum and Natural Gas Systems (not including petroleum refineries and petroleum transportation) to be 251.55 (MMtCO2-e).  It is important to note that the 2009 emissions estimates from well completions and recompletions exclude a significant number of wells completed in tight sand plays and the Marcellus Shale, due to availability of data when the 2009 Inventory was developed.  The estimate in this analysis includes an adjustment for tight sand plays and the Marcellus Shale, and such an adjustment is also being considered as a planned improvement in next year's Inventory. This adjustment would increase the 2009 Inventory estimate by about 80 MMtCO2-e to approximately 330 MMtCO2-e.
Emission Points and Pollution Controls assessed in the RIA
NSPS Emission Points and Pollution Controls
      A series of emissions controls were evaluated as part of the NSPS review.  This section provides a basic description of possible emissions sources and the controls evaluated for each source to facilitate the reader's understanding of the economic impact and benefit analyses.  The reader who is interested in more technical detail on the engineering and cost basis of the analysis is referred to the relevant chapters within the Technical Support Document (TSD) which is published in the Docket.  The chapters are also referenced below.
Centrifugal and reciprocating compressors (UPDATED REFERENCE TO BE ADDED):  There are many locations throughout the oil and gas sector where compression of natural gas is required to move the gas along the pipeline.  This is accomplished by compressors powered by combustion turbines, reciprocating internal combustion engines, or electric motors.  Turbine-powered compressors use a small portion of the natural gas that they compress to fuel the turbine.  The turbine operates a centrifugal compressor, which compresses and pumps the natural gas through the pipeline.  Sometimes an electric motor is used to turn a centrifugal compressor.  This type of compression does not require the use of any of the natural gas from the pipeline, but it does require a source of electricity.  Reciprocating spark ignition engines are also used to power many compressors, referred to as reciprocating compressors, since they compress gas using pistons that are driven by the engine.  Like combustion turbines, these engines are fueled by natural gas from the pipeline.
      Both centrifugal and reciprocating compressors are sources of VOC emissions, and EPA evaluated compressors for coverage under the NSPS.  Centrifugal compressors require seals around the rotating shaft to prevent gases from escaping where the shaft exits the compressor casing. The seals in some compressors use oil, which is circulated under high pressure between three rings around the compressor shaft, forming a barrier against the compressed gas leakage. Very little gas escapes through the oil barrier, but considerable gas is absorbed by the oil.  Seal oil is purged of the absorbed gas (using heaters, flash tanks, and degassing techniques) and recirculated, and the gas is commonly vented to the atmosphere.  These are commonly called "wet" seals.  An alternative to a wet seal system is the mechanical dry seal system. This seal system does not use any circulating seal oil.  Dry seals operate mechanically under the opposing force created by hydrodynamic grooves and static pressure.  Fugitive VOC is emitted from dry seals around the compressor shaft.  The use of dry gas seals substantially reduces emissions.  In addition, they significantly reduce operating costs and enhance compressor efficiency.
      Reciprocating compressors in the natural gas industry leak natural gas during normal operation.  The highest volume of gas loss is associated with piston rod packing systems.  Packing systems are used to maintain a tight seal around the piston rod, preventing the gas compressed to high pressure in the compressor cylinder from leaking, while allowing the rod to move freely.  Monitoring and replacing compressor rod packing systems on a regular basis can greatly reduce VOC emissions.
Equipment leaks (UPDATED REFERENCE TO BE ADDED): Equipment leaks are fugitive emissions emanating from valves, pump seals, flanges, compressor seals, pressure relief valves, open-ended lines, and other process and operation components.   There are several potential reasons for equipment leak emissions.  Components such as pumps, valves, pressure relief valves, flanges, agitators, and compressors are potential sources that can leak due to seal failure.  Other sources, such as open-ended lines, and sampling connections may leak for reasons other than faulty seals.  In addition, corrosion of welded connections, flanges, and valves may also be a cause of equipment leak emissions.  Because of the large number of valves, pumps, and other components within an oil and gas production, processing, and transmission facility, equipment leaks of volatile emissions from these components can be significant.  Natural gas processing plants, especially those using refrigerated absorption, and transmission stations tend to have a large number of components.  These types of equipment also exist at production sites and gas transmission/compressor stations.  While the number of components at individual transmission/compressor stations is relatively smaller than at processing plants, collectively there are many components that can result in significant emissions.  Therefore, EPA evaluated NSPS for equipment leaks for facilities in the production segment of the industry, which includes everything from the wellhead to the point that the gas enters the processing plant or refinery.
Pneumatic controllers (UPDATED REFERENCE TO BE ADDED): Pneumatic controllers are automated instruments used for maintaining a process condition such as liquid level, pressure, delta-pressure, and temperature.  Pneumatic controllers are widely used in the oil and natural gas sector.  In many situations, the pneumatic controllers used in the oil and gas sector make use of the available high-pressure natural gas to regulate temperature, pressure, liquid level, and flow rate across all areas of the industry.  In these "gas-driven" pneumatic controllers, natural gas may be released with every valve movement or continuously from the valve control pilot.  Not all pneumatic controllers are gas driven.  These "non-gas driven" pneumatic controllers use sources of power other than pressurized natural gas.  Examples include solar, electric, and instrument air.  At oil and gas locations with electrical service, non gas-driven controllers are typically used.  Gas-driven pneumatic controllers are typically characterized as "high-bleed" or "low-bleed", where a high-bleed device releases at least 6 cubic feet of gas per hour. EPA evaluated the impact of requiring low-bleed controllers.
Storage vessels (UPDATED REFERENCE TO BE ADDED):  Crude oil, condensate, and produced water are typically stored in fixed-roof storage vessels.  Some vessels used for storing produced water may be open-top tanks.  These vessels, which are operated at or near atmospheric pressure conditions, are typically located at tank batteries.  A tank battery refers to the collection of process equipment used to separate, treat, and store crude oil, condensate, natural gas, and produced water.  The extracted products from productions wells enter the tank battery through the production header, which may collect product from many wells.  Emissions from storage vessels are a result of working, breathing, and flash losses.  Working losses occur due to the emptying and filling of storage tanks.  Breathing losses are the release of gas associated with daily temperature fluctuations and other equilibrium effects.  Flash losses occur when a liquid with entrained gases is transferred from a vessel with higher pressure to a vessel with lower pressure, thus allowing entrained gases or a portion of the liquid to vaporize or flash.  In the oil and natural gas production segment, flashing losses occur when live crude oils or condensates flow into a storage tank from a processing vessel operated at a higher pressure.  Typically, the larger the pressure drop, the more flashing emission will occur in the storage stage.  The two ways of controlling tanks with significant emissions would be to install a vapor recovery unit (VRU) and recover all the vapors from the tanks or to route the emissions from the tanks to a control device.
Well completions (UPDATED REFERENCE TO BE ADDED): In the oil and natural gas sector, well completions contain multi-phase processes with various sources of emissions.  One specific emission source during completion activities is the venting of natural gas to the atmosphere during flowback.  Flowback emissions are short-term in nature and occur as a specific event during completion of a new well or during activities that involve re-drilling or re-fracturing an existing well.  Well completions include multiple steps after the well bore hole has reached the target depth.  These steps include inserting and cementing-in well casing, perforating the casing at one or more producing horizons, and often hydraulically fracturing one or more zones in the reservoir to stimulate production.
	Hydraulic fracturing is one completion step for improving gas production where the reservoir rock is fractured with very high pressure fluid, typically water emulsion with proppant (generally sand) that "props open" the fractures after fluid pressure is reduced.  Emissions are a result of the backflow of the fracture fluids and reservoir gas at high velocity necessary to lift excess proppant to the surface.  This multi-phase mixture is often directed to a surface impoundment where natural gas and VOC vapors escape to the atmosphere during the collection of water, sand, and hydrocarbon liquids.  As the fracture fluids are depleted, the backflow eventually contains more volume of natural gas from the formation.  Thus, we estimate completions involving hydraulic fracturing vent substantially more natural gas, approximately 230 times more, than completions not involving hydraulic fracturing.  Specifically, we estimate that uncontrolled well completion emissions for a hydraulically fractured well are about 23 tons of VOC, where emissions for a conventional gas well completion are around 0.1 ton VOC.  Our data indicate that hydraulically fractured wells have higher emissions but we believe some wells that are not hydraulically fractured may have higher emissions than our data show, or in some cases, hydraulically fractured wells could have lower emissions that our data show.
	Reduced emission completions, which are sometimes referred to as "green completions" or "flareless completions," use equipment at the well site to capture and treat gas so it can be directed into the sales line and avoid emissions from venting.   Equipment required to conduct a reduced emissions completion may include tankage, special gas-liquid-sand separator traps, and gas dehydration.  Equipment costs associated with reduced emission completions will vary from well to well.  Based on information provided to the EPA Natural Gas STAR program, 90 percent of gas potentially vented during a completion can be recovered during a reduced emission completion.
NESHAP Emission Points and Pollution Controls
      A series of emissions controls will be required under the final NESHAP Amendments.  This section provides a basic description of potential sources of emissions and the controls intended for each to facilitate the reader's understanding of the economic impacts and subsequent benefits analysis section.  The reader who is interested in more technical detail on the engineering and cost basis of the analysis is referred to the relevant technical memos which are published in the Docket.  The memos are also referenced below.
Glycol dehydrators:  Once natural gas has been separated from any liquid materials or products (e.g., crude oil, condensate, or produced water), residual entrained water is removed from the natural gas by dehydration.  Dehydration is necessary because water vapor may form hydrates, which are ice-like structures, and can cause corrosion in or plug equipment lines.  The most widely used natural gas dehydration processes are glycol dehydration and solid desiccant dehydration.  Solid desiccant dehydration, which is typically only used for lower throughputs, uses adsorption to remove water and is not a source of HAP emissions.  Glycol dehydration is an absorption process in which a liquid absorbent, glycol, directly contacts the natural gas stream and absorbs any entrained water vapor in a contact tower or absorption column.  The rich glycol, which has absorbed water vapor from the natural gas stream, leaves the bottom of the absorption column and is directed either to (1) a gas condensate glycol separator (GCG separator or flash tank) and then a reboiler or (2) directly to a reboiler where the water is boiled off of the rich glycol.  The regenerated glycol (lean glycol) is circulated, by pump, into the absorption tower.  The vapor generated in the reboiler is directed to the reboiler vent.  The reboiler vent is a source of HAP emissions.  In the glycol contact tower, glycol not only absorbs water but also absorbs selected hydrocarbons, including BTEX and n-hexane.  The hydrocarbons are boiled off along with the water in the reboiler and vented to the atmosphere or to a control device.
      The most commonly used control device is a condenser.  Condensers not only reduce emissions, but also recover condensable hydrocarbon vapors that can be recovered and sold.  In addition, the dry non-condensable off-gas from the condenser may be used as fuel or recycled into the production process or directed to a flare, incinerator, or other combustion device.
	If present, the GCG separator (flash tank) is also a potential source of HAP emissions.  Some glycol dehydration units use flash tanks prior to the reboiler to separate entrained gases, primarily methane and ethane from the glycol.  The flash tank off-gases are typically recovered as fuel or recycled to the natural gas production header.  However, the flash tank may also be vented directly to the atmosphere.  Flash tanks typically enhance the reboiler condenser's emission reduction efficiency by reducing the concentration of non-condensable gases present in the stream prior to being introduced into the condenser.
Storage vessels:  Please see the discussion of storage vessels in the NSPS section above.
Engineering Cost Analysis
In this section, we provide an overview of the engineering cost analysis used to estimate the additional private expenditures industry may make in order to comply with the final NSPS and NESHAP Amendments.  A detailed discussion of the methodology used to estimate cost impacts is presented in series of memos published in the Docket as part of the TSD.
NSPS Sources
      Table 3-1 shows the emissions sources, points, and controls analyzed for the final rule.  The final NSPS contains reduced emission completion (REC) and completion combustion requirements for a subset of newly drilled natural gas wells that are hydraulically fractured.  The NSPS also requires a subset of wells that are recompleted using hydraulic fracturing to implement RECs.  The NSPS requires emissions reductions from reciprocating compressors at gathering and boosting stations and processing plants. The NSPS also requires emissions reductions from centrifugal compressors at processing plants.  Finally, the NSPS requires emissions reductions from pneumatic controllers at oil and gas production facilities and reductions from high throughput storage vessels.

Table 3-1	Emissions Sources, Points, and Controls Included in the Final NSPS
                         Emissions Sources and Points
                               Emissions Control
                                  Final NSPS
Well Completions of Post-NSPS Wells

Hydraulically Fractured Gas Wells that Meet Criteria for Reduced Emissions Completion (REC)
REC
                                       X

Hydraulically Fractured Gas Wells that Do Not Meet Criteria for REC
Combustion
                                       X

Conventional Gas Wells
Combustion

Oil Wells
Combustion

Well Recompletions

Hydraulically Fractured Gas Wells (post-NSPS wells)
REC
                                       X

Hydraulically Fractured Gas Wells (pre-NSPS wells)
REC
                                       X

Conventional Gas Wells
Combustion

Oil Wells
Combustion

Equipment Leaks

Well Pads
NSPS Subpart VV

Gathering and Boosting Stations
NSPS Subpart VV

Processing Plants
NSPS Subpart VVa
                                       X

Transmission Compressor Stations
NSPS Subpart VV

Reciprocating Compressors

Well Pads
Annual Monitoring/ Maintenance (AMM)

Gathering/Boosting Stations
AMM
                                       X

Processing Plants
AMM
                                       X

Transmission Compressor Stations
AMM

Underground Storage Facilities
AMM

Centrifugal Compressors

Processing Plants
Dry Seals/Route to Process or Control
                                       X

Transmission Compressor Stations
Dry Seals/Route to Process or Control

Pneumatic Controllers -

 Oil and Gas Production
Low Bleed/Route to Process
                                       X

 Natural Gas Transmission and Storage
Low Bleed/Route to Process

Storage Vessels

High Throughput
95% control
                                       X

Low Throughput
95% control

      Table 3-2 summarizes the unit level capital and annualized costs for the evaluated NSPS emissions sources and points.  The detailed description of costs estimates is provided in the series of technical memos included in the TSD in the document, as referenced in Section 3.2.1 of this RIA.  The table also includes the projected number of affected units.  Four issues are important to note on Table 3-2: the approach to annualizing costs, the projection of affected units in the baseline; that capital and annualized costs are equated for RECs; and additional natural gas and hydrocarbon condensates that would otherwise be emitted to the environment are recovered from several control options evaluated in the NSPS review.
      First, engineering capital costs were annualized using a 7 percent interest rate.  However, different emissions control options were annualized using expected lifetimes that were determined to be most appropriate for individual options.  For control options evaluated for the NSPS, the following lifetimes were used:
   * Reduced emissions completions and combustion devices: 1 year (more discussion of the selection of a one-year lifetime follows in this section momentarily)
   * Reciprocating compressors: 3 years
   * Centrifugal compressors and pneumatic controllers: 10 years
   * Storage vessels: 15 years
   * Equipment leaks: 5 to 10 years, depending on specific control

      To estimate total annualized engineering compliance costs, we added the annualized costs of each item without accounting for different expected lifetimes.  This approach is mathematically equivalent to establishing  an overall, representative project time horizon and annualizing costs after consideration of control options that would need to be replaced periodically within the given time horizon.  For example, a 15 year project would require replacing reciprocating compressor-related controls five times, but only require a single installation of controls on storage vessels.
      Second, the projected number of affected units is the number of units that our analysis shows would be affected in 2015, the analysis year.  The projected number of affected units accounts for estimates of the adoption of controls in absence of Federal regulation.  While the procedures used to estimate adoption in absence of Federal regulation are presented in detail within the TSD, because REC requirements provide a significant component of the estimated emissions reductions and engineering compliance costs, it is worthwhile to go into some detail on the projected number of RECs within the RIA.  We use EIA projections consistent with the Annual Energy Outlook 2011 to estimate the number of natural gas well completions with hydraulic fracturing in 2015, assuming that successful wells drilled in coal bed methane, shale, and tight sands used hydraulic fracturing.  Based on this assumption, we estimate that 11,403 wells were successfully completed and used hydraulic fracturing.  To approximate the number of wells that would not be required to perform RECs because of the absence of sufficient infrastructure, we draw upon the distinction in EIA analysis between exploratory and developmental wells.  We assume exploratory wells do not have sufficient access to infrastructure to perform a REC and are exempt from the REC requirement.  These 446 wells are removed from the REC estimate and are assumed to combust emissions using pit flares.
      The number of hydraulically fractured recompletions of existing wells was approximated using assumptions found in Subpart W's TSD and applied to well count data found in the proprietary HPDI[(R)] database.  The underlying assumption is that wells found in coal bed methane, shale, and tight sand formations require re-fracture, on average, every 10 years.  In other words, one percent of the total wells classified as being performed with hydraulic fracturing would perform a recompletion in any given year.  Natural gas well recompletions performed without hydraulic fracturing were based only on 2008 well data from HPDI[(R)].
      The number of completions and recompletions already controlling emissions in absence of a Federal regulation was estimated based on existing State regulations that require applicable control measures for completions and workovers in specific geographic locations. Based on this criterion, 15 percent of natural gas completions with hydraulic fracturing and 15 percent of existing natural gas workovers with hydraulic fracturing are estimated to be controlled by either flare or REC in absence of Federal regulations.  Completions and recompletions without hydraulic fracturing were assumed as having no controls in absence of a Federal regulation. Following these procedures leads to an estimate of 9,313 completions of new wells and 1,205 recompletions of existing wells that will require a REC under the final NSPS in 2015.  However, because the pressure level for some wells may be insufficient to successfully perform an REC, these wells will be required to combust emissions, rather than implement an REC.  EPA analysis shows about 10 percent of the wells that otherwise would be required by the NSPS to perform an REC will combust emissions.  In summary, we expect 8,382 completions of new wells and 1,085 recompletions of existing wells will ultimately require a REC, after consideration of state regulations and pressure levels.
      As just mentioned, the baseline for the impacts analysis of our NSPS for natural gas well completions takes into account reduced emission completions conducted pursuant to state regulations covering these operations.  However, based on public comments and reports to EPA's Natural Gas Star program, EPA acknowledges that some producers conduct well completions using REC techniques voluntarily.  However, EPA normally does not account for voluntary actions in baseline emissions estimates when we analyze potential impacts of our regulatory actions, since there is no assurance that such voluntary emission reduction measures will continue in the future.  As such, emissions reductions obtained from RECs implemented voluntarily are not reflected in our baseline emissions estimates.
      It also should be noted that natural gas prices are stochastic and, historically, there have been periods where prices have increased or decreased rapidly.  These price changes would be expected to affect adoption of emission reduction technologies in absence of regulation, particularly control measures such as RECs that capture emission significantly over short periods of time.
The completion requirements (combustion and RECs) are essentially one-shot events; 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.  After this relatively short period of time, there is no continuing control requirement, unless the well is again completed at a later date, sometimes years later.  Consequently, we counted these requirements as as recurring costs, implicitly treating the number of completions taking place in 2015 as representative of a typical year.the completion requirements (combustion and RECs) are essentially one-shot events; 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.  After this relatively short period of time, there is no continuing control requirement, unless the well is again completed at a later date, sometimes years later.
Fourth, for annualized cost, we present two figures, the annualized costs with revenues from additional natural gas and condensate recovery and annualized costs without additional revenues this product recovery.  Several emission controls for the NSPS capture VOC emissions that otherwise would be vented to the atmosphere.  Since methane is co-emitted with VOC, a large proportion of the averted methane emissions can be directed into natural gas production streams and sold.  When including the additional natural gas recovery in the cost analysis, we assume that producers are paid $4 per thousand cubic feet (Mcf) for the recovered gas at the wellhead.  RECs also capture saleable condensates that would otherwise be lost to the environment.  The engineering analysis assumes a REC will capture 34 barrels of condensate per REC and that the value of this condensate is $70/barrel.
The $4/Mcf is below the 2015 EIA-forecasted wellhead price, $4.22/Mcf in 2008 dollars.  The $4/Mcf payment rate does not reflect any taxes or tax credits that might apply to producers implementing the control technologies.  As natural gas prices can increase or decrease rapidly, the estimated engineering compliance costs can vary when revenue from additional natural gas recovery is included.  There is also geographic variability in wellhead prices, which can also influence estimated engineering costs.  A $1/Mcf change in the wellhead price causes a change in estimated engineering compliance costs of about $82 million in 2008 dollars.
As will be seen in subsequent analysis, the estimate of revenues from additional product recovery is critical to the economic impact analysis.  However, before discussing this assumption in more depth, it is important to further develop the engineering estimates to contextualize the discussion and to provide insight into why, if it is profitable to capture natural gas emissions that are otherwise vented, producers may not already be doing so.
      Table 3-3 presents the estimated nationwide compliance costs, emissions reductions, and VOC reduction cost-effectiveness broken down by emissions sources and points for those sources and points evaluated in the NSPS analysis.  The annual reporting and recordkeeping costs for the final NSPS are estimated at $7.1 million per year and are included in Table 3-3.
      As can be seen from Table 3-3 controls associated with well completions and recompletions of hydraulically fractured wells provide the largest potential for emissions reductions from evaluated emissions sources and points, as well as present the most significant compliance costs if revenue from additional natural gas recovery is not included.  Emissions reductions from conventional natural gas wells and crude oil wells are clearly not as significant as the potential from hydraulically fractured wells, as was discussed in Section <IP_ADDRESS>.
Several evaluated emissions sources and points are estimated to have net financial savings when including the revenue from additional natural gas recovery.  Table 3-4 presents the estimated engineering costs, emissions reductions, and VOC reduction cost-effectiveness for the final NSPS evaluated in the RIA.  The resulting total national annualized cost impact of the final NSPS rule is estimated at $340 million per year without considering revenues from additional natural gas recovery.  Annual costs for the final NSPS are estimated at -$18 million when revenue from additional natural gas recovery is included.  All figures are in 2008 dollars.
Table 3-2	Summary of Capital and Annualized Costs per Unit for NSPS Emissions Points
                            Sources/Emissions Point
                        Projected No. of Affected Units

                       Per Unit Annualized Cost (2008$)

                             Capital Costs (2008$)
               Without Revenues from Additional Product Recovery
                                     With
                   Revenues from Additional Product Recovery
Well Completions

Hydraulically Fractured Gas Wells that Meet Criteria for REC
                                     8,382
                                    $33,237
                                    $33,237
                                    -$1,543
Hydraulically Fractured Gas Wells that Do Not Meet Criteria for REC (Completion Combustion)
                                     1,498
                                    $3,523
                                    $3,523
                                    $3,523
Conventional Gas Wells
                                     7,694
                                    $3,523
                                    $3,523
                                    $3,523
Oil Wells
                                    12,193
                                    $3,523
                                    $3,523
                                    $3,523
Well Recompletions

Hydraulically Fractured Gas Wells (existing wells)
                                     1,085
                                    $33,237
                                    $33,237
                                    -$1,543
Conventional Gas Wells
                                    42,342
                                    $3,523
                                    $3,523
                                    $3,523
Oil Wells
                                    39,375
                                    $3,523
                                    $3,523
                                    $3,523
Equipment Leaks

Well Pads
                                     4,774
                                    $68,970
                                    $23,413
                                    $21,871
Gathering and Boosting Stations
                                      275
                                   $239,494
                                    $57,063
                                    $51,174
Processing Plants
                                      29
                                    $8,041
                                    $12,273
                                    $8,474
Transmission Compressor Stations
                                      107
                                    $96,542
                                    $25,350
                                    $25,350
Reciprocating Compressors

Well Pads
                                     6,000
                                    $6,480
                                    $3,701
                                    $3,664
Gathering/Boosting Stations
                                      210
                                    $5,346
                                    $2,456
                                     $870
Processing Plants
                                      209
                                    $4,050
                                    $2,090
                                    -$2,227
Transmission Compressor Stations
                                      20
                                    $5,346
                                    $2,456
                                    $2,456
Underground Storage Facilities
                                       4
                                    $7,290
                                    $3,349
                                    $3,349
Centrifugal Compressors

Processing Plants
                                      13
                                    $22,000
                                    $3,132
                                   -$50,106
Transmission Compressor Stations
                                      14
                                    $75,000
                                    $10,678
                                   -$77,622
Pneumatic Controllers -

 Oil and Gas Production
                                    13,632
                                     $165
                                      $23
                                    -$1,519
 Natural Gas Trans. and Storage
                                      67
                                     $165
                                      $23
                                      $23
Storage Vessels

High Throughput
                                      304
                                    $65,243
                                    $19,864
                                    $19,281
Low Throughput
                                    17,086
                                    $65,243
                                    $19,864
                                    $19,281

Table 3-3	Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction Cost-Effectiveness by Emissions Sources and Points, NSPS, 2015
                            Source/Emissions Point
                               Emissions Control
                      Nationwide Annualized Costs (2008$)
                  Nationwide Emissions Reductions (tons/year)
            VOC Emissions Reduction Cost-Effectiveness (2008$/ton)

                            Without Addl. Revenues
                              With Addl. Revenues
                                      VOC
                                    Methane
                                      HAP
                            Without Addl. Revenues
                              With Addl. Revenues
Well Completions (New Wells)

Hydraulically Fractured Gas Wells
REC
                                                                   $278,598,165
                                                                   -$12,931,447
                                                                        180,217
                                                                      1,235,207
                                                                         13,093
                                                                         $1,546
                                                                           -$72
Hydraulically Fractured Gas Wells
Combustion
                                                                     $5,276,674
                                                                     $5,276,674
                                                                         32,204
                                                                        220,726
                                                                          2,340
                                                                           $164
                                                                           $164
Conventional Gas Wells
Combustion
                                                                    $27,104,761
                                                                    $27,104,761
                                                                            857
                                                                          5,875
                                                                             62
                                                                        $31,619
                                                                        $31,619
Oil Wells
Combustion
                                                                    $42,954,036
                                                                    $42,954,036
                                                                             83
                                                                             88
                                                                              0
                                                                       $520,580
                                                                       $520,580
Well Recompletions (Existing Wells)

Hydraulically Fractured Gas Wells (existing wells)
REC
                                                                    $36,045,804
                                                                    -$1,673,106
                                                                         23,317
                                                                        159,815
                                                                          1,694
                                                                         $1,546
                                                                           -$72
Conventional Gas Wells
Combustion
                                                                   $149,164,257
                                                                   $149,164,257
                                                                            316
                                                                          2,165
                                                                             23
                                                                       $472,227
                                                                       $472,227
Oil Wells
Combustion
                                                                   $138,711,979
                                                                   $138,711,979
                                                                             44
                                                                             47
                                                                              0
                                                                     $3,134,431
                                                                     $3,134,431
Equipment Leaks

Well Pads
NSPS Subpart VV
                                                                   $111,773,662
                                                                   $104,412,154
                                                                         10,646
                                                                         38,287
                                                                            401
                                                                        $10,499
                                                                         $9,808
Gathering and Boosting Stations
NSPS Subpart VV
                                                                    $15,692,325
                                                                    $14,072,850
                                                                          2,340
                                                                          8,415
                                                                             88
                                                                         $6,705
                                                                         $6,013
Processing Plants
NSPS Subpart VVa
                                                                       $355,917
                                                                       $245,746
                                                                            132
                                                                            475
                                                                              5
                                                                         $2,693
                                                                         $1,860
Transmission Compressor Stations
NSPS Subpart VV
                                                                     $2,712,450
                                                                     $2,712,450
                                                                            261
                                                                          9,427
                                                                              8
                                                                        $10,389
                                                                        $10,389
Reciprocating Compressors

Well Pads
Annual Monitoring/ Maintenance (AMM)
                                                                    $22,204,209
                                                                    $21,984,763
                                                                            263
                                                                            947
                                                                             10
                                                                        $84,379
                                                                        $83,545
Gathering/Boosting Stations
AMM
                                                                       $515,764
                                                                       $182,597
                                                                            400
                                                                          1,437
                                                                             15
                                                                         $1,291
                                                                           $457
Processing Plants
AMM
                                                                       $436,806
                                                                      -$465,354
                                                                          1,082
                                                                          3,892
                                                                             41
                                                                           $404
                                                                          -$430
Transmission Compressor Stations
AMM
                                                                        $49,120
                                                                        $49,120
                                                                             12
                                                                            434
                                                                              0
                                                                         $4,093
                                                                         $4,093
Underground Storage Facilities
AMM
                                                                        $13,396
                                                                        $13,396
                                                                              2
                                                                             87
                                                                              0
                                                                         $5,542
                                                                         $5,542

Table 3-3 (continued)	Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction Cost-Effectiveness by Emissions Sources and Points, NSPS, 2015
                            Source/Emissions Point
                               Emissions Control
                      Nationwide Annualized Costs (2008$)
                  Nationwide Emissions Reductions (tons/year)
            VOC Emissions Reduction Cost-Effectiveness (2008$/ton)

                            Without Addl. Revenues
                              With Addl. Revenues
                                      VOC
                                    Methane
                                      HAP
                            Without Addl. Revenues
                              With Addl. Revenues

Centrifugal Compressors

Processing Plants
Dry Seals/Route to Process or Control
                                                                        $40,720
                                                                      -$651,377
                                                                            254
                                                                          2,810
                                                                              9
                                                                           $161
                                                                        -$2,569
Transmission Compressor Stations
Dry Seals/Route to Process or Control
                                                                       $149,496
                                                                    -$1,086,704
                                                                             43
                                                                          1,546
                                                                              1
                                                                         $3,495
                                                                       -$25,405
Pneumatic Controllers -

 Oil and Gas Production
Low Bleed/Route to Process
                                                                       $320,071
                                                                   -$20,699,918
                                                                         25,210
                                                                         90,685
                                                                            952
                                                                            $13
                                                                          -$821
 Natural Gas Trans. and Storage
Low Bleed/Route to Process
                                                                         $1,541
                                                                         $1,541
                                                                              6
                                                                            212
                                                                              0
                                                                           $262
                                                                           $262
Storage Vessels

High Throughput
95% control
                                                                     $6,031,787
                                                                     $5,855,032
                                                                         29,654
                                                                          6,490
                                                                            876
                                                                           $203
                                                                           $197
Low Throughput
95% control
                                                                   $339,388,204
                                                                   $329,442,792
                                                                         12,900
                                                                          2,824
                                                                            381
                                                                        $26,308
                                                                        $25,537

Table 3-4	Engineering Compliance Costs, NSPS (2008$)

                                  Final NSPS
Capital Costs
                                 $344,724,611
Annualized Costs

   Without Revenues from Additional Natural
        Gas Product Recovery
                                 $334,927,549
With Revenues from Additional Natural Gas
        Product Recovery
                                 -$17,607,568

VOC Reductions (tons per year)
                                    292,532
Methane Reduction (tons per year)
                                   1,721,763
HAP Reductions (tons per year)
                                    19,028

VOC Reduction Cost-Effectiveness ($/ton without additional product revenues)
                                    $1,144
VOC Reduction Cost-Effectiveness ($/ton with additional product revenues)
                                     -$60

Note: the VOC reduction cost-effectiveness estimate assumes there is no benefit to reducing methane and HAP, which is not the case.  We however present the per ton costs of reducing the single pollutant for illustrative purposes.  As product prices can increase or decrease rapidly, the estimated engineering compliance costs can vary when revenue from additional product recovery is included.  There is also geographic variability in wellhead prices, which can also influence estimated engineering costs.  A $1/Mcf change in the wellhead price causes a change in estimated engineering compliance costs of about $82 million in 2008 dollars.  The annualized cost estimates also includes reporting and recordkeeping costs of $7.1 million.

As the price assumption is very influential on estimated impacts, we performed a simple sensitivity analysis of the influence of the assumed wellhead price paid to natural gas producers on the overall engineering costs estimate of the final NSPS.  Figure 3-1 plots the annualized costs after revenues from natural gas product recovery have been incorporated (in millions of 2008 dollars) as a function of the assumed price of natural gas paid to producers at the wellhead for the recovered natural gas (represented by the sloped, dotted line).  The vertical solid lines in the figure represent the natural gas price assumed in the RIA ($4.00/Mcf) for 2015 and the 2015 forecast by EIA in the 2011 Annual Energy Outlook ($4.22/Mcf) in 2008 dollars.

Figure 3-1	Sensitivity Analysis of Final NSPS Annualized Costs after Revenues from Additional Product Recovery are Included

As shown in Table 3-4, at the assumed $4/Mcf, the annualized costs are estimated at -$18 million.  At $4.22/Mcf, the price forecast reported in the 2011 Annual Energy Outlook, the annualized costs are estimated at about -$36 million, which would approximately double the estimate of net cost savings of the final NSPS.  As indicated by this difference, EPA has chosen a relatively conservative assumption (leading to an estimate of few savings and higher net costs) for the engineering costs analysis.  The natural gas price at which the final NSPS breaks-even is around $3.79/Mcf.  As mentioned earlier, a $1/Mcf change in the wellhead natural gas price leads to about a $82 million change in the annualized engineering costs of the final NSPS.  Consequently, annualized engineering costs estimates would increase to about $65 million under a $3/Mcf price or decrease to about -$100 million under a $5/Mcf price.
      It is additionally helpful to put the quantity of natural gas and condensate potentially recovered in the context of domestic production levels.  To do so, it is necessary to make two adjustments.  First, not all emissions reductions can be directed into production streams to be ultimately consumed by final consumers.  Several controls require combustion of the natural gas rather than capture and direction into product streams.  After adjusting estimates of national emissions reductions in Table 3-3 for these combustion-type controls, the final NSPS is estimated to capture about 82 bcf of natural gas and 320,000 barrels of condensate.  Estimates of unit-level and nation-level product recovery are presented in Section 3 of the RIA.  Note that completion-related requirements for new and existing wells generate all the condensate recovery for the NSPS.  For natural gas recovery, RECs contribute about 77 bcf (or 93 percent).

Table 3-5	Estimates of Control Unit-level and National Level Natural Gas and Condensate Recovery, NSPS, 2015

                        Projected No. of Affected Units
                          Unit-level Product Recovery
                            Total Product Recovery
Source/ Emissions Points
Emissions Control

                        Natural Gas Savings (Mcf/unit)
                             Condensate (bbl/unit)
                           Natural Gas Savings (Mcf)
                               Condensate (bbl)
Well Completions

Hydraulically Fractured Gas Wells
REC
                                     8,382
                                     8,100
                                      34
                                  67,895,051
                                   284,992

Hydraulically Fractured Gas Wells
Combustion
                                     1,498
                                       0
                                      0
                                      0
                                      0

Hydraulically Fractured Gas Wells (existing wells)
REC
                                     1,085
                                     8,100
                                      34
                                  8,784,450
                                    36,873
Equipment Leaks

Processing Plants
NSPS Subpart VVa
                                      29
                                      950
                                      0
                                    27,548
                                      0
Reciprocating Compressors

Gathering/Boosting Stations
Annual Monitoring/ Maintenance (AMM)
                                      210
                                      397
                                      0
                                    83,370
                                      0

Processing Plants
AMM
                                      209
                                     1,079
                                      0
                                   225,540
                                      0
Centrifugal Compressors

Processing Plants
Dry Seals/Route to Process or Ctrl
                                      13
                                    11,527
                                      0
                                   149,853
                                      0
Pneumatic Controllers -

Oil and Gas Production
Low Bleed/Route to Process
                                    13,632
                                      386
                                      0
                                  5,254,997
                                      0

Processing Plants
Instrument Air
                                      15
                                      871
                                      0
                                    13,064
                                      0
Storage Vessels

High Throughput
95% control
                                      304
                                      146
                                      0
                                    44,189
                                      0
Total (Mcf)

                                  82,478,062
                                   321,865

A second adjustment to the natural gas quantities is necessary to account for nonhydrocarbon gases removed and gas that reinjected to repressurize wells, vented or flared, or consumed in production processes.  Generally, wellhead production is metered at or near the wellhead and payments to producers are based on these metered values.  In most cases, the natural gas is minimally processed at the meter and still contains impurities or co-products that must be processed out of the natural gas at processing plants.  This means that the engineering cost estimates of revenues from additional natural gas recovery arising from controls implemented at the wellhead include payment for the impurities, such as the VOC and HAP content of the unprocessed natural gas.  According to EIA, in 2009 the gross withdrawal of natural gas totaled 26,013 bcf, but 20,580 bcf was ultimately considered dry production (these figures exclude EIA estimates of flared and vented natural gas).  Using these numbers, we apply a factor of 0.79 (20,580 bcf divided by 26,013 bcf) to the adjusted sums in the previous paragraph to estimate the volume of gas that is captured by controls that may ultimately be consumed by final consumers.
	After making these adjustments, we estimate that the final NSPS will potentially recover about 65 bcf of natural gas that will ultimately be consumed by natural gas consumers.  EIA forecasts that the domestic dry natural gas production in 2015 will be 20,080 bcf.  Consequently, the final NSPS may recover production representing about 0.3 percent of domestic dry natural gas production predicted in 2015.  These estimates, however, do not account for adjustments producers might make, once compliance costs and potential revenues from additional natural gas recovery factor into economic decision-making.  Also, as discussed in the previous paragraph, these estimates do not include the nonhydrocarbon gases removed, natural gas reinjected to repressurize wells, and natural gas consumed in production processes, and therefore will be lower than the estimates of the gross natural gas captured by implementing controls.
      Clearly, this discussion raises the question as to why, if emissions can be reduced profitably using environmental controls, more producers are not adopting the controls in their own economic self-interest.  This question is made clear when examining simple estimates of the rate of return to installing emissions controls that, using the engineering compliance costs estimates, the estimates of natural gas product recovery, and assumed product prices (Table 3-6).  The rates of return presented in are for evaluated controls where estimated revenues from additional product recovery exceed the costs.  The rate of return is calculated using the simple formula: .

Table 3-6	Simple Rate of Return Estimate for Final NSPS Controls
Emission Point
                                Control Option
                                Rate of Return
New Completions of Hydraulically Fractured Wells
                         Reduced Emissions Completions
                                     4.6%
Re-completions of Existing Hydraulically Fractured Wells
                         Reduced Emissions Completions
                                     4.6%
Reciprocating Compressors  (Processing Plants)
                                Replace Packing
                                    106.5%
Centrifigal Compressors (Processing Plants)
                          Dry Seals/Route to Control
                                   1,599.7%
Pneumatic Controllers (Oil and Gas Production )
                          Low Bleed/Route to Process
                                   6,467.2%
Overall NSPS
                                   Low Bleed
                                     5.4%
Note: The table presents only control options  where estimated revenues from natural gas product recovery exceeds estimated annualized engineering costs

      Recall from Table 2-23 in the Industry Profile, that EIA estimates an industry-level rate of return on investments for various segments of the oil and natural gas industry.  While the numbers varies greatly over time because of industry and economic factors, EIA estimates a 10.7 percent rate of return on investments for oil and natural gas production in 2008. While this amount is higher than the 4.6 percent rate estimated for RECs, it is significantly lower than the rate of returns estimated for other controls anticipated to have net savings.
Assuming financially rational producers, standard economic theory suggests that all oil and natural gas firms would incorporate all cost-effective improvements, which they are aware of, without government intervention.  The cost analysis of this RIA nevertheless is based on the observation that emission reductions that appear to be profitable in our analysis have not been generally adopted.  One possible explanation may be the difference between the average profit margin garnered by productive capital and the environmental capital where the primary motivation for installing environmental capital would be to mitigate the emission of pollutants and confer social benefits as discussed in Chapter 4.
Another explanation for why there appear to be negative cost control technologies that are not generally adopted is imperfect information.  If emissions from the oil and natural gas sector are not well understood, firms may underestimate the potential financial returns to capturing emissions.  Quantifying emissions is difficult and has been done in relatively few studies.  Recently, however, advances in infrared imagery have made it possible to affordably visualize, if not quantify, methane emissions from any source using a handheld camera.  This infrared camera has increased awareness within industry and among environmental groups and the public at large about the large number of emissions sources and possible scale of emissions from oil and natural gas production activities.  Since, as discussed in the TSD chapter (UPDATED REFERENCE TO BE ADDED) referenced above, 15 percent of new natural gas well completions with hydraulic fracturing and 15 percent of existing natural gas well recompletions with hydraulic fracturing are estimated to be controlled by either flare or REC in the baseline, it is unlikely that a lack of information will be a significant reason for these emission points to not be addressed in the absence of Federal regulation in 2015.  However, for other emission points, a lack of information, or the cost associated with doing a feasibility study of potential emission capture technologies, may continue to prevent firms from adopting these improvements in the absence of regulation.
Another explanation is the cost associated with irreversibility associated with implementing these environmental controls are not reflected in the engineering cost estimates above.  Due to the high volatility of natural gas prices, it is important to recognize the value of flexibility taken away from firms when requiring them to install and use a particular emissions capture technology.  If a firm has not adopted the technology on its own, then a regulation mandating its use means the firm loses the option to postpone investment in the technology in order to pursue alternative investments today, and the option to suspend use of the technology if it becomes unprofitable in the future.  Therefore, the full cost of the regulation to the firm is the engineering cost and the lost option value minus the revenues from the sale of the additional recovered product.  In the absence of quantitative estimates of this option value for each emission point affected by the NSPS and NESHAP improvements, the costs presented in this RIA may underestimate the full costs faced by the affected firms.  With these caveats in mind, EPA believes it is analytically appropriate to analyze costs and economic impacts costs presented in Table 3-2 and Table 3-3 using the additional product recovery and associated revenues.
NESHAP Sources

As discussed in Section <IP_ADDRESS>, EPA examined three emissions points as part of its analysis for the final NESHAP Amendments.  Unlike the controls for the final NSPS, the controls evaluated under the final NESHAP Amendments do not direct significant quantities of natural gas that would otherwise be flared or vented into the production stream.  Table 3-7 shows the projected number of controls required, estimated unit-level capital and annualized costs, and estimated total annualized costs.  The table also shows estimated emissions reductions for HAP, VOC, and methane, as well as a cost-effectiveness estimate for HAP reduction, based upon annualized engineering costs.

Table 3-7	Summary of Estimated Capital and Annual Costs, Emissions Reductions, and HAP Reduction Cost-Effectiveness for Final NESHAP Amendments
                            Source/Emissions Point
                      Projected No. of Controls Required

                      Emission Reductions (tons per year)

                          Capital Costs/ Unit (2008$)
                         Annualized Cost/Unit (2008$)
                         Total Annualized Cost (2008$)
                                      HAP
                                      VOC
                                    Methane
                 HAP Reduction Cost-Effectiveness (2008$/ton)
Production - Small Glycol Dehydrators
                                      74
                                    35,518
                                    22,396
                                   1,657,300
                                      505
                                      915
                                      316
                                     3,284
Transmission -  Small Glycol Dehydrators
                                       7
                                    19,399
                                    18,957
                                    132,700
                                      164
                                      298
                                      103
                                      808
Storage Vessels
                                      674
                                    65,243
                                    19,864
                                  13,388,039
                                      589
                                     7,812
                                     4,364
                                    22,722
Reporting and Recordkeeping
                                      N/A
                                      N/A
                                      N/A
                                   2,368,627
                                      N/A
                                      N/A
                                      N/A
                                      N/A
Total
                                      755

                                  17,546,667
                                     1,258
                                     9,024
                                     4,783
                                    13,945
Note: Totals may not sum due to independent rounding.

     Under the final NESHAP Amendments, about 750 controls will be required, costing a total of $18 million annually (Table 3-7).  We include reporting and recordkeeping costs as a unique line item showing these costs for the entire set of final amendments.  These controls will reduce HAP emissions by about 1,300 tons, VOC emissions by about 9,000 tons, and methane by about 4,800 tons.  The cost-per-ton to reduce HAP emissions is estimated at about $14,000 per ton. All figures are in 2008 dollars.
References

Oil and Gas Journal. "Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil Profits Grow." November 1, 2010.

Oil and Gas Journal. "OGJ150." September 21, 2009.

Oil and Gas Journal. "OGJ150 Financial Results Down in '09; Production, Reserves Up." September 6, 2010.

Oil and Gas Journal. "Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Processing Capacity Ahead in 2009." June 7, 2010.

Benefits of Emissions Reductions
Introduction

      The final Oil and Natural Gas NSPS and NESHAP Amendments are expected to result in significant reductions in existing emissions and prevent new emissions from expansions of the industry.  While we expect that these avoided emissions will result in improvements in air quality and reduce health effects associated with exposure to HAP, ozone, and fine particulate matter (PM2.5), we have determined that quantification of those health benefits cannot be accomplished for this rule in a defensible way.  This is not to imply that there are no health 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.  For the final NSPS, the HAP and climate benefits can be considered "co-benefits", and for the final NESHAP Amendments, the ozone and PM2.5 health benefits and climate benefits can be considered "co-benefits".  These co-benefits occur because the control technologies used to reduce VOC emissions also reduce emissions of HAP and methane.
The final NSPS is anticipated to prevent 19,000 tons of HAP, 290,000 tons of VOC, and 1.7 million tons of methane from new sources, while the final NESHAP Amendments is anticipated reduce 1,300 tons of HAP, 9,000 tons of VOC, and 4,800 tons of methane from existing sourcesThe 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), 630 tons of nitrogen oxides NOx, 19 tons of PM, 3,400 tons of CO, and 1,300 tons of total hydrocarbons (THC) as well as emission reductions associated with the energy system impacts. Both rules would have additional emission changes associated with the energy system impacts.  The net CO2-equivalent emission reductions are 31 million metric tons for the final NSPS and 90,000 metric tons for the final NESHAP.  As described in the subsequent sections, these pollutants are associated with substantial health effects, welfare effects, and climate effects.  With the data available, we are not able to provide a credible benefits estimates for any of these pollutants for these rules, due to the differences in the locations of oil and natural gas emission points relative to existing information, and the highly localized nature of air quality responses associated with HAP and VOC reductions.  In addition, we do not yet have interagency agreed upon valuation estimates for greenhouse gases other than CO2 that could be used to value the climate co-benefits associated with avoiding methane emissions.  Instead, we provide a qualitative assessment of the benefits and co-benefits as well as a break-even analysis in Chapter 6 of this RIA.  A break-even analysis answers the question, "What would the benefits need to be for the benefits to exceed the costs." While a break-even approach is not equivalent to a benefits analysis, we feel the results are illustrative, particularly in the context of previous benefit per ton estimates.
Direct Emission Reductions from the Oil and Natural Gas Rules

      As described in Section 2 of this RIA, oil and natural gas operations in the U.S. include a variety of emission points for VOC and HAP including wells, processing plants, compressor stations, storage equipment, and transmission and distribution lines.  These emission points are located throughout much of the country with significant concentrations in particular regions.  For example, wells and processing plants are largely concentrated in the South Central, Midwest, and Southern California regions of the U.S., whereas gas compression stations are located all over the country.  Distribution lines to customers are frequently located within areas of high population density.
In implementing these rules, emission controls may lead to reductions in ambient PM2.5 and ozone below the National Ambient Air Quality Standards (NAAQS) in some areas and assist other areas with attaining the NAAQS. Due to the high degree of variability in the responsiveness of ozone and PM2.5 formation to VOC emission reductions, we are unable to determine how these rules might affect attainment status without air quality modeling data.  Because the NAAQS RIAs also calculate ozone and PM benefits, there are important differences worth noting in the design and analytical objectives of each RIA. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air quality standard nationwide based on an array of emission control strategies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, the control strategies that States may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits of other regulations that result in specific costs of control and emission reductions. However, some costs and benefits estimated in this RIA account for the same air quality improvements as estimated in an illustrative NAAQS RIA.
      By contrast, the emission reductions for this rule are from a specific class of well-characterized sources. In general, EPA is more confident in the magnitude and location of the emission reductions for these rules. It is important to note that emission reductions anticipated from these rules do not result in emission increases elsewhere (other than potential energy disbenefits). Emission reductions achieved under these and other promulgated rules will ultimately be reflected in the baseline of future NAAQS analyses, which would reduce the incremental costs and benefits associated with attaining the NAAQS. EPA remains forward looking towards the next iteration of the 5-year review cycle for the NAAQS, and as a result does not issue updated RIAs for existing NAAQS that retroactively update the baseline for NAAQS implementation. For more information on the relationship between the NAAQS and rules such as analyzed here, please see Section 1.2.4 of the SO2 NAAQS RIA (U.S. EPA, 2010d).  Table 4-1 shows the direct emission reductions anticipated for these rules.  It is important to note that these benefits accrue at different spatial scales.  HAP emission reductions reduce exposure to carcinogens and other toxic pollutants primarily near the emission source.  Reducing VOC emissions would reduce precursors to secondary formation of PM2.5 and ozone, which reduces exposure to these pollutants on a regional scale.  Climate effects associated with long-lived greenhouse gases like methane are primarily at a global scale, but methane is also a precursor to ozone, a short-lived climate forcer that exhibits spatial and temporal variability.

Table 4-1	Direct Emission Reductions Associated with the Oil and Natural Gas NSPS and NESHAP Amendments in 2015 (short tons per year)
                                   Pollutant
                               NESHAP Amendments
                                     NSPS
                                      HAP
                                     1,258
                                    19,028
                                      VOC
                                     9,024
                                    292,532
                                    Methane
                                     4,783
                                   1,721,763

Secondary Impacts Analysis for Oil and Gas Rules
     The control techniques to avert leaks and vents of VOC and HAP are associated with several types of secondary impacts, which may partially offset the direct benefits of this rule.  In this RIA, we refer to the secondary impacts associated with the specific control techniques as "producer-side" impacts.  For example, by combusting VOC and HAP, combustion increases emissions of carbon monoxide, NOx, particulate matter and other pollutants.  In addition to "producer-side" impacts, these control techniques would also allow additional natural gas recovery, which would contribute to additional combustion of the recovered natural gas and ultimately a shift in the national fuel mix.  We refer to the secondary impacts associated with the combustion of the recovered natural gas as "consumer-side" secondary impacts.  We provide a conceptual diagram of both categories of secondary impacts in Figure 4-1.

Figure 4-1	Conceptual Diagram of Secondary Impacts from Oil and Gas NSPS and NESHAP Amendments

      Table 4-2 shows the estimated secondary "producer-side" impacts.  Relative to the direct emission reductions anticipated from these rules, the magnitude of these secondary air pollutant impacts is small.  Because the geographic distribution of these emissions from the oil and gas sector is not consistent with emissions modeled in Fann, Fulcher, and Hubbell (2009), we are unable to monetize the PM2.5 disbenefits associated with the producer-side secondary impacts.  In addition, it is not appropriate to monetize the disbenefits associated with the increased CO2 emissions without monetizing the averted methane emissions because the overall global warming potential (GWP) is actually lower.  Through the combustion process, methane emissions are converted to CO2 emissions, which have 21 times less global warming potential compared to methane (IPCC, 2007).
Table 4-2	Secondary Air Pollutant Impacts Associated with Control Techniques by Emissions Category ("Producer-Side") (tons per year)
Emissions Category
                                      CO2
                                      NOx
                                      PM
                                      CO
                                      THC
Total Completions of New Wells (NSPS)
                                   1,120,184
                                      576
                                     14.7
                                     3,133
                                     1,185
   New Well Completions: REC/Combust
                                    271,801
                                      140
                                      0.0
                                      760
                                      288
   New Well Completions: Combust
                                    848,382
                                      436
                                     14.7
                                     2,373
                                      898
Total Recompletions of Existing Wells (NSPS)
                                    109,732
                                      56
                                      1.3
                                      307
                                      116
   Existing Well Recompletions: REC/Combust
                                    35,183
                                      18
                                      0.0
                                      98
                                      37
   Existing  Well Recompletions: Combust
                                    74,549
                                      38
                                      1.3
                                      208
                                      79
Pneumatic Controllers (NSPS)
                                      22
                                      1.0
                                      2.6
                                      0.0
                                      0.0
Storage Vessels (NSPS)
                                      856
                                      0.5
                                      0.0
                                      2.4
                                      0.9
Total NSPS
                                   1,230,794
                                      634
                                      19
                                     3,442
                                     1,302
Total NESHAP (Storage Vessels)
                                     5,543
                                      2.9
                                      0.1
                                      16
                                       6

      For the "consumer-side" impacts associated with the NSPS, we modeled the impact of the final NSPS on the national fuel mix and associated CO2-equivalent emissions (Table 4-3).  We provide the modeled results of the "consumer-side" CO2-equivalent emissions in Table 7-12.
      The modeled results indicate that through a slight shift in the national fuel mix, the CO2-equivalent emissions across the energy sector would increase by 0.54 million metric tons for the final NSPS in 2015.  This is in addition to the other secondary impacts and directly avoided emissions, for a total 31 million metric tons of CO2-equivalent emissions averted as shown in Table 4-4.  We estimate small increases other emissions (e.g., NOx, PM, SOx) associated with the additional national gas consumption or the change in the national fuel mix.
Table 4-3	Modeled Changes in Energy-related CO2-equivalent Emissions by Fuel Type for the Final Oil and Gas NSPS in 2015 (million metric tons) ("Consumer-Side")[1]
Fuel Type
                  NSPS (million metric tons change in CO2-e)
Petroleum
                                     -0.44
Natural Gas
                                     2.49
Coal
                                     -1.51
Other
                                     0.00
Total modeled Change in CO2-e  Emissions
                                     0.54
1 These estimates reflect the modeled change in CO2-e emissions using NEMS shown in Table 7-12. Totals may not sum due to independent rounding.

Table 4-4	Total Change in CO2-equivalent Emissions including Secondary Impacts for the Final Oil and Gas NSPS in 2015 (million metric tons)
Emissions Source
                                     NSPS
                                    NESHAP
                                  Amendments
Averted CO2-e Emissions from New Sources[1]
                                     -32.8
                                     -0.09
Additional CO2-e Emissions from Combustion and Supplemental Energy (Producer-side)[2]
                                      1.1
                                     0.01
Total Modeled Change in Energy-related CO2-e  Emissions (Consumer-side)[3]
                                     0.54
                                      --
Total Change in CO2-e Emissions after Adjustment for Secondary Impacts
                                     -31.1
                                     -0.09
[1] This estimate reflects the GWP of the avoided methane emissions from new sources shown in Table 4-1 and has been converted from short tons to metric tons.
[2] This estimate represents the secondary producer-side impacts associated with additional CO2 emissions from combustion and from additional electricity requirements shown in Table 4-2 and has been converted from short tons to metric tons.
[3]This estimate reflects the modeled change in the energy - related consumer-side impacts shown in Table 4-3.
Totals may not sum due to independent rounding.