846
                                      10
ExxonMobil Corp.
                                       6
                                                                          1,238
                                                                            766
                                      11
Occidental Petroleum Corp
                                       7
                                                                            776
                                                                            750
                                      12
Kinder Morgan Energy Partners
                                       9
                                                                          1,318
                                                                            743
                                      13
Enogex Products Corp.
                                       8
                                                                            863
                                                                            666
                                      14
Hess Corp.
                                       3
                                                                          1,060
                                                                            613
                                      15
Norcen Explorer
                                       1
                                                                            600
                                                                            500
                                      16
Copano Energy
                                       1
                                                                            700
                                                                            495
                                      17
Anadarko
                                      18
                                                                            816
                                                                            489
                                      18
Oneok Field Services
                                      10
                                                                          1,751
                                                                            472
                                      19
Shell
                                       4
                                                                            801
                                                                            446
                                      20
DTE Energy
                                       1
                                                                            800
                                                                            400

TOTAL FOR TOP 20
                                      264
                                                                         63,163
                                                                         40,028

TOTAL FOR ALL COMPANIES
                                      579
                                                                         73,767
                                                                         45,472
Source: Oil and Gas Journal. "Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Processing Capacity Ahead in 2009." June 7, 2010, with additional analysis to determine ultimate ownership of plants.

      The OGJ also issues a periodic report on the economics of the U.S. pipeline industry.  This report examines the economic status of all major and non-major natural gas pipeline companies, which amounts to 136 companies in 2010 (Oil and Gas Journal, November 1, 2010).  Table 2-21 presents the pipeline mileage, volumes of natural gas transported, operating revenue, and net income for the top 20 U.S. natural gas pipeline companies in 2009.  Ownership of gas pipelines is mostly independent from ownership of oil and gas production companies, as is seen from the lack of overlap between the OGJ list of pipeline companies and the OGJ150.  This observation shows that the pipeline industry is still largely based upon firms serving regional market.
      The top 20 companies maintain about 63 percent of the total pipeline mileage and transport about 54 percent of the volume of the industry (Table 2-21).  Operating revenues of the top 20 companies equaled $11.5 billion, representing 60 percent of the total operating revenues for major and non-major companies.  The top 20 companies also account for 64 percent of the net income of the industry.
Table 2-21	Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2009
                                     Rank
                                    Company
                             Transmission (miles)
                         Vol. trans for others (MMcf)
                             Op. Rev. (thousand $)
                                  Net Income
                                       1
Natural Gas Pipeline Co of America
                                                                          9,312
                                                                      1,966,774
                                                                      1,131,548
                                                                        348,177
                                       2
Dominion Transmission Inc.
                                                                          3,452
                                                                        609,193
                                                                        831,773
                                                                        212,365
                                       3
Columbia Gas Transmission LLC
                                                                          9,794
                                                                      1,249,188
                                                                        796,437
                                                                        200,447
                                       4
Panhandle Eastern Pipe Line Co. LP
                                                                          5,894
                                                                        675,616
                                                                        377,563
                                                                        196,825
                                       5
Transcontinental Gas Pipe Line Co. LLC
                                                                          9,362
                                                                      2,453,295
                                                                      1,158,665
                                                                        192,830
                                       6
Texas Eastern Transmission LP
                                                                          9,314
                                                                      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 that 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 (132,000 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 1.87 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 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 proposal Technical Support Document (TSD) and Background Supplemental Technical Support Document for the Final New Source Performance Standards, which are published in the Docket.  Technical memos that also discuss revisions to the proposal TSD are noted in the relevant sections.
Centrifugal and reciprocating compressors :  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: 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 the 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: 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: 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 production 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 emissions 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: 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 natural 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 natural gas completions involving hydraulic fracturing vent substantially more natural gas, approximately 230 times more, than natural gas completions not involving hydraulic fracturing.  Specifically, we estimate that uncontrolled natural gas well completion emissions for a hydraulically fractured natural gas well are about 23 tons of VOC, where emissions for a conventional natural gas well completion are around 0.1 ton of VOC.  Our data indicate that hydraulically fractured natural gas wells have higher emissions but we believe some natural gas wells that are not hydraulically fractured may have higher emissions than our data show, or in some cases, hydraulically fractured natural gas wells could have lower emissions than 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 natural gas so it can be directed into the sales line and avoid emissions from venting.   Equipment required to conduct a reduced emissions completion at a natural gas well may include tankage, special gas-liquid-sand separator traps, and gas dehydration.  Equipment costs associated with reduced emission completions of natural gas wells will vary from well to well.  Based on information provided to the EPA Natural Gas STAR program, 90 percent of natural 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 (1) to 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.
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 a 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 in the analysis supporting the proposed and final rules.  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 natural gas wells that are recompleted using hydraulic fracturing to implement a REC and emissions combustion.  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 storage vessels that emit at least six tons of VOC per year.

Table 3-1	Emissions Sources, Points, and Controls Evaluated at Proposal for the NSPS
                         Emissions Sources and Points
                               Emissions Control
                             Covered by Final NSPS
Crude Oil and Natural Gas Well Completions

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

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

Conventional Gas Wells
                                  Combustion

Oil Wells
                                  Combustion

Crude Oil and Natural Gas Well Recompletions

Hydraulically Refractured Gas Wells that Meet Criteria for Reduced Emissions Completion (REC)
                                REC/Combustion
                                       X

Hydraulically Refractured Gas Wells that Do Not Meet Criteria for REC
                                  Combustion
                                       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 and Boosting Stations
                                      AMM
                                       X

Processing Plants
                                      AMM
                                       X

Transmission Compressor Stations
                                      AMM

Underground Storage Facilities
                                      AMM

Centrifugal Compressors

Processing Plants
                               Route to control
                                       X

Transmission Compressor Stations
                               Route to control

Pneumatic Controllers -

 Oil and Gas Production
                                Emissions limit
                                       X

 Natural Gas Transmission and Storage
                                Emissions limit

Processing Plants
                                Emissions limit
                                       X
Storage Vessels

Emissions at least 6 tons per year
                                  95% control
                                       X

Emissions less than 6 tons per year
                                  95% control

      As discussed in the Executive Summary, several emission controls for the NSPS, such as reduced emissions completions (RECs) of hydraulically fractured natural gas wells, capture VOC emissions that otherwise would be vented to the atmosphere.  Since methane is co-emitted with VOC, a large proportion of the averted methane emissions can be directed into natural gas production streams and sold.  RECs also recover saleable hydrocarbon condensates that would otherwise be lost to the environment.  The revenues derived from additional natural gas and condensate recovery are expected to offset the engineering costs of implementing the NSPS.  In the economic impact and energy economy analyses for the NSPS, we present results that include the additional product recovery and the revenues we expect producers to gain from the additional product recovery.
      The primary baseline used for the impacts analysis of our NSPS for completions of hydraulically fractured natural gas wells takes into account RECs conducted pursuant to state regulations covering these operations and estimates of RECs performed voluntarily.  To account for RECs performed in regulated states, EPA subsumed emissions reductions and compliance costs in states where these completion-related emissions are already controlled into the baseline.  Additionally, based on public comments and reports to EPA's Natural Gas STAR program, EPA recognizes that some producers conduct well completions using REC techniques voluntarily for economic and/or environmental objectives as a normal part of business. To account for emissions reductions and costs arising from voluntary implementation of pollution controls EPA used information on total emissions reductions reported to the EPA by partners of the EPA Natural Gas STAR. This estimate of this voluntary REC activity in the absence of regulation is therefore also in the baseline.  More detailed discussion on the derivation of the baseline is presented in a technical memorandum in the docket, as well as in the RIA.
      Additionally, in the RIA, we provide summary-level estimates of emissions reductions and engineering compliance costs for a case where no voluntary RECs are assumed to occur.  This alternative case is presented in order to show impacts if conditions were such that RECs were no longer performed on a voluntary basis, but rather were compelled by the regulation, and serves in part to capture the inherent uncertainty in projecting voluntary activity into the future. As such, this alternative case establishes the full universe of emissions reductions that are guaranteed by this NSPS (those that are required to occur under the rule, including those that would likely occur voluntarily).  While the primary baseline may better represent actual costs (and emissions reductions) beyond those already expected under business as usual, the alternative case better captures the full amount of emissions reductions where the NSPS acts as a backstop to ensure that emission reduction practices occur (practices covered by this rule).
      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 Docket, as referenced in Section 3.2.1 of this RIA.  The table also includes the number of affected units projected under the primary baseline and the alternative regulatory baseline.  Four issues are important to note  regarding engineering compliance cost estimates: the approach to annualizing costs, the projection of affected units in the baseline; that estimate rental costs are used 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.

Table 3-2	Summary of Projected No. of Affected Units Under Primary and Alternative Regulatory Baselines and Capital and Annualized Costs per Unit for Final NSPS Emissions Sources and Points
                            Source/Emissions Point
                        Projected No. of Affected Units

                            Annualized Cost (2008$)

                                    Primary
                                   Baseline
                                 Alternative
                              Regulatory Baseline
                             Capital Costs (2008$)
                   Without Rev. from Addl. Product Recovery
                     With Rev. from Addl. Product Recovery
Hydraulically Fractured Natural Gas Well Completions
Hydraulically Fractured Gas Wells that Meet Criteria for REC
                                     4,107
                                     8,382
                                      $0
                                    $33,237
                                    -$1,543
Hydraulically Fractured Gas Wells that Do Not Meet Criteria for REC (Completion Combustion)
                                     1,377
                                     1,377
                                      $0
                                    $3,523
                                    $3,523
Hydraulically Refractured Natural Gas Well Completions
Hydraulically Refractured Gas Wells that Meet Criteria for REC
                                      532
                                     1,085
                                      $0
                                    $33,237
                                    -$1,543
Hydraulically Refractured Gas Wells that Do Not Meet Criteria for REC (Completion Combustion)
                                      121
                                      121
                                      $0
                                    $3,523
                                    $3,523
Equipment Leaks

Processing Plants
                                      29
                                      29
                                    $8,041
                                    $12,273
                                    $8,474
Reciprocating Compressors

Gathering and Boosting Stations
                                      210
                                      210
                                    $5,346
                                    $2,456
                                     $870
Processing Plants
                                      209
                                      209
                                    $4,050
                                    $2,090
                                    -$2,227
Centrifugal Compressors

Processing Plants
                                      13
                                      13
                                    $22,000
                                    $3,132
                                   -$46,974
Pneumatic Controllers

Oil and Gas Production
                                    13,632
                                    13,632
                                     $165
                                      $23
                                    -$1,519
Processing Plants
                                      15
                                      15
                                   $16,972
                                   $11,090
                                    $7,606
Storage Vessels

Emissions at least 6 tons per year
                                      304
                                      304
                                    $65,243
                                    $19,864
                                    $19,281

<IP_ADDRESS>.1	Approach to Annualizing Engineering Compliance Costs
      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)
   * 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.
<IP_ADDRESS>.2	Projection of Affected Units
      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.  In the National Energy Modeling System  (NEMS) used by the EIA to produce the Annual Energy Outlook identifies wells as being either a natural gas well or oil well.  No criteria, such as a gas-oil ratio, for example, are applied within the model to a well to determine whether it is a natural gas well or an oil well.  Additionally, EIA uses historical information as data for the NEMS.  To collect these data, EIA relies upon States to submit information.  States submit information about natural gas wells and oil wells based upon state-level approaches to classification, which varies greatly across States.  In most instances, no national-level criteria are applied to reclassify the State-submitted information.  To the extent that EPA's definition of a natural gas well differs from the various definitions used by States, potential differences in definitions may explain some difference between forecast impacts of the NSPS and the true costs incurred once the NSPS is implemented.
       To approximate the number of natural gas wells that would not be required to combust emissions rather than perform a REC because they are wildcat (exploratory) and delineation wells, we draw upon the distinction in the EIA's analysis between exploratory and developmental wells.  EIA defines an exploratory well as a "hole drilled a) to find and produce oil or gas in an area previously considered unproductive area; b) to find a new reservoir in a known field, i.e., one previously producing oil and gas from another reservoir, or c) to extend the limit of a known oil or gas reservoir."  According to EIA, a "development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive."   The definitions of exploratory and developmental wells do not take into account whether the wells primarily produce crude oil or natural gas. For the impacts analysis, we assume exploratory wells as defined and estimated by EIA are equivalent to the NSPS-affected wildcat (exploratory) and delineation wells described in the NSPS as requiring to combust completion emissions rather than perform a REC.
      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, as well as information reported to the EPA's Natural Gas STAR program. Based on the criterion relating to State regulations, 15 percent of natural gas completions with hydraulic fracturing and 15 percent of recompletions of existing natural gas workovers with hydraulic fracturing are estimated to be controlled by either flare or REC in absence of Federal regulations.  EPA does not have comprehensive information on the number of hydraulically fractured natural gas well completions that might be required by state or local regulations to combust completion emissions, which upon promulgation of this rule will be required to perform a REC.  Based on the criterion relating to voluntary REC implementation, 51 percent of the completions and recompletions outside of regulated States are assumed to have been performed using a REC.
      However, because the pressure level for some wells may be insufficient to successfully perform a REC, these wells will be required to combust emissions, rather than implement a REC.  EPA analysis shows about 10 percent of the wells that otherwise would be required by the NSPS to perform a REC will combust emissions.

Table 3-3	Estimated New Hydraulically Fractured and Refractured Natural Gas Well Completions Affected by NSPS, 2015

       Hydraulically Fractured Natural Gas Well Completions of New Wells
    Hydraulically Refractured Natural Gas Well Completions of Existing Wells
Nationwide Hydraulically Fractured Natural Gas Well Completions
                                                                      11,403[1]
                                                                       1,417[2]
Completions Exempt from NSPS REC Requirement

 Wildcat (Exploration Wells) and Delineation[1]
                                                                            446
                                                                              0

Low Pressure[3]
                                                                            931
                                                                            121
RECs Performed Absent Federal Regulation

REC Already Required by States
                                                                          1,644
                                                                            212

Voluntarily Performed RECs Outside of Regulated States[4]
                                                                          4,275
                                                                            553

Total RECs Incrementally Required by NSPS
                                                                          4,107
                                                                            532
Total Completion Combustion Incrementally Required by NSPS
                                                                          1,377
                                                                            121
Note: sums may not total because of independent rounding.

[1]
Annual Energy Outlook 2011 Reference Case (successful completions in tight sands, shale, coalbed methane formations in 2015)
[2]
U.S. Environmental Protection Agency (U.S. EPA). 2010. Greenhouse Gas Emissions Reporting From the Petroleum and Natural Gas Industry: Background Technical Support Document. Climate Change Division. Washington, DC.  Also reflects revised assumptions regarding refracture frequency.
[3]
"NSPS Low Pressure Completion Threshold" in U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution:  Background Supplemental Technical Support Document for the Final New Source Performance Standards.  EPA-453/R-11-002. April 2012.
[4]
"Voluntary Reductions from Gas Well Completions with Hydraulic Fracturing" in U.S. Environmental Protection Agency.  Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution:  Background Supplemental Technical Support Document for the Final New Source Performance Standards.  EPA-453/R-11-002. April 2012.
      Table 3-3 presents the accounting used for the estimate of the number of hydraulically fractured natural gas completions incrementally affected by the NSPS, after accounting for State regulation and voluntary action.  In summary, we estimate 4,107 completions of new hydraulically fractured natural gas wells and 531 existing hydraulically refractured natural gas wells will incrementally be required to perform a REC in 2015.  Additionally, we estimate 1,377 completions of new hydraulically fractured natural gas wells and 121 existing hydraulically refractured natural gas wells will be incrementally required to combust emissions in 2015.  The methods to derive these figures are detailed in a technical memo in the Docket.
      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 REC that capture emissions over short periods of time.
<IP_ADDRESS>.3	REC Unit Rental Costs
The completion requirements (combustion and REC) are essentially one-shot events and are generally performed by independent contractors.  The emissions controls are applied over the course of a well completion, which will typically range over a few days to a couple of weeks.  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, if at all.  After the completion is concluded, the REC equipment is typically moved by contractors to be reused during other well completions.  Given that we base our REC costs on the average cost for contracting the REC as a service, we expect contractors' operation and maintenance costs, depreciations, and potential salvage value of the equipment to be reflected in the total contracting costs.  Because of these factors, we decided to treat the hydraulically fractured natural gas well completion requirements solely as annualized costs.
<IP_ADDRESS>.4	    Revenues from Natural Gas Product Recovery
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 from 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. For the RIA, in the case of a REC, the revenues from captured and sold natural gas products are assumed to accrue in the same year as the REC is performed and only that year.  For other environmental controls that avert the emission of saleable natural gas, such as pneumatic controllers, we base the estimated revenues from averted natural gas emissions on an estimate of the amount of natural gas that would not be emitted during one year for the control.
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 $43 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 3-4 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 $2.6 million per year and are included in Table 3-4.
      As can be seen from Table 3-4, which presents estimates, under the primary baseline, of nationwide compliance costs, emissions reductions, and VOC reduction cost-effectiveness from controls associated with well completions and recompletions, hydraulically fractured natural gas wells provide the largest potential for emissions reductions from evaluated emissions sources and points.  Controlling equipment leaks at processing plants presents the most significant compliance costs if revenue from additional natural gas recovery is not included.  Table 3-5 presents the same set of information under the alternative regulatory baseline.
      Several evaluated emissions sources and points are estimated to have net financial savings when including the revenue from additional natural gas recovery.  Table 3-6 presents the estimated engineering costs, emissions reductions, and VOC reduction cost-effectiveness for the final NSPS under the primary baseline.  The resulting total national annualized cost impact of the final NSPS rule is estimated at $170 million per year without considering revenues from additional natural gas recovery.  Total national annualized costs for the final NSPS are estimated at -$15 million when revenue from additional natural gas recovery is included.  All figures are in 2008 dollars.
Table 3-4	Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction Cost-Effectiveness by NSPS Emissions Sources and Points, Primary Baseline, 2015
                            Source/Emissions Point
                      Nationwide Annualized Costs (2008$)
                             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
Hydraulically Fractured Natural Gas Well Completions

Hydraulically Fractured Gas Wells that Meet Criteria for REC
                                                                   $136,511,391
                                                                    -$6,336,330
                                                                         88,305
                                                                        605,244
                                                                          6,416
                                                                         $1,546
                                                                           -$72
Hydraulically Fractured Gas Wells that Do Not Meet Criteria for REC (Completion Combustion)
                                                                     $4,850,956
                                                                     $4,850,956
                                                                         29,606
                                                                        202,918
                                                                          2,151
                                                                           $164
                                                                           $164
Hydraulically Refractured Natural Gas Well Completions

Hydraulically Refractured Gas Wells that Meet Criteria for REC
                                                                    $17,682,220
                                                                      -$820,740
                                                                         11,438
                                                                         78,397
                                                                            831
                                                                         $1,546
                                                                           -$72
Hydraulically Refractured Gas Wells that Do Not Meet Criteria for REC (Completion Combustion)
                                                                       $426,264
                                                                       $426,264
                                                                          2,602
                                                                         17,831
                                                                            189
                                                                           $164
                                                                           $164
Equipment Leaks

Processing Plants
                                                                       $355,917
                                                                       $245,746
                                                                            132
                                                                            475
                                                                              5
                                                                         $2,693
                                                                         $1,860
Reciprocating Compressors

Gathering and Boosting Stations
                                                                        515,764
                                                                        182,597
                                                                            400
                                                                          1,437
                                                                             15
                                                                         $1,291
                                                                           $457
Processing Plants
                                                                        436,806
                                                                       -465,354
                                                                          1,082
                                                                          3,892
                                                                             41
                                                                           $404
                                                                          -$430
Centrifugal Compressors

Processing Plants
                                                                        $40,720
                                                                      -$610,657
                                                                            254
                                                                          2,810
                                                                              9
                                                                           $161
                                                                        -$2,408
Pneumatic Controllers

 Oil and Gas Production
                                                                       $320,071
                                                                   -$20,699,918
                                                                         25,210
                                                                         90,685
                                                                            952
                                                                            $13
                                                                          -$821
Processing Plants
                                                                       $166,351
                                                                       $114,094
                                                                             63
                                                                            225
                                                                              2
                                                                         $2,659
                                                                         $1,824
Storage Vessels

Emissions at least 6 tons per year
                                                                     $6,031,787
                                                                     $5,855,032
                                                                         29,654
                                                                          6,490
                                                                            876
                                                                           $203
                                                                           $197
Reporting and Recordkeeping
                                                                      2,576,065
                                                                      2,576,065
                                                                            N/A
                                                                            N/A
                                                                            N/A
                                                                            N/A
                                                                            N/A
TOTAL
                                                                   $169,914,312
                                                                   -$14,682,245
                                                                        188,744
                                                                      1,010,405
                                                                         11,487
                                                                           $900
                                                                           -$78

Table 3-5	 Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction Cost-Effectiveness by NSPS Emissions Sources and Points, Alternative Regulatory Baseline, 2015
                            Source/Emissions Point
                      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
Hydraulically Fractured Natural Gas Well Completions

Hydraulically Fractured Gas Wells that Meet Criteria for REC
                                                                   $278,594,675
                                                                   -$12,931,285
                                                                        180,214
                                                                      1,235,192
                                                                         13,093
                                                                         $1,546
                                                                           -$72
Hydraulically Fractured Gas Wells that Do Not Meet Criteria for REC (Completion Combustion)
                                                                     $4,850,956
                                                                     $4,850,956
                                                                         29,606
                                                                        202,918
                                                                          2,151
                                                                           $164
                                                                           $164
Hydraulically Refractured Natural Gas Well Completions

Hydraulically Refractured Gas Wells that Meet Criteria for REC
                                                                    $36,062,422
                                                                    -$1,673,878
                                                                        $23,328
                                                                       $159,888
                                                                         $1,695
                                                                         $1,546
                                                                           -$72
Hydraulically Refractured Gas Wells that Do Not Meet Criteria for REC (Completion Combustion)
                                                                       $426,264
                                                                       $426,264
                                                                         $2,602
                                                                        $17,831
                                                                           $189
                                                                           $164
                                                                           $164
Equipment Leaks

Processing Plants
                                                                       $355,917
                                                                       $245,746
                                                                           $132
                                                                           $475
                                                                             $5
                                                                         $2,693
                                                                         $1,860
Reciprocating Compressors

Gathering and Boosting Stations
                                                                       $515,764
                                                                       $182,597
                                                                           $400
                                                                         $1,437
                                                                            $15
                                                                         $1,291
                                                                           $457
Processing Plants
                                                                       $436,806
                                                                      -$465,354
                                                                         $1,082
                                                                         $3,892
                                                                            $41
                                                                           $404
                                                                          -$430
Centrifugal Compressors

Processing Plants
                                                                        $40,720
                                                                      -$610,657
                                                                           $254
                                                                         $2,810
                                                                             $9
                                                                           $161
                                                                        -$2,408
Pneumatic Controllers

 Oil and Gas Production
                                                                       $320,071
                                                                   -$20,699,918
                                                                        $25,210
                                                                        $90,685
                                                                           $952
                                                                            $13
                                                                          -$821
Processing Plants
                                                                       $166,351
                                                                       $114,094
                                                                            $63
                                                                           $225
                                                                             $2
                                                                         $2,659
                                                                         $1,824
Storage Vessels

Emissions at least 6 tons per year
                                                                     $6,031,787
                                                                     $5,855,032
                                                                        $29,654
                                                                         $6,490
                                                                           $876
                                                                           $203
                                                                           $197
Reporting and Recordkeeping
                                                                     $2,576,065
                                                                     $2,576,065
                                                                            N/A
                                                                            N/A
                                                                            N/A
                                                                            N/A
                                                                            N/A
TOTAL
                                                                   $330,377,798
                                                                   -$22,130,338
                                                                        292,543
                                                                      1,721,844
                                                                         19,029
                                                                         $1,129
                                                                           -$76

Table 3-6	Engineering Compliance Costs, Emission Reductions, and Cost-Effectiveness, Primary Baseline, NSPS (2008$)

                                  Final NSPS
Capital Costs
                                  $24,803,968
Annualized Costs

   Without Revenues from Additional Natural
        Gas Product Recovery
                                 $169,914,312
With Revenues from Additional Natural Gas
        Product Recovery
                                 -$14,682,245

VOC Reductions (tons per year)
                                    188,744
Methane Reduction (tons per year)
                                   1,010,405
HAP Reductions (tons per year)
                                    11,487

VOC Reduction Cost-Effectiveness ($/ton without additional product revenues)
                                     $900
VOC Reduction Cost-Effectiveness ($/ton with additional product revenues)
                                     -$78

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 $43 million in 2008 dollars.  The annualized cost estimates also include reporting and recordkeeping costs of $2.6 million.

      As shown in Table 3-5, if voluntary action is not subsumed into the NSPS baseline, the emissions reductions achieved by the final NSPS are estimated at about 290,000 tons VOC, 19,000 tons HAP, and 1.7 million tons methane, and annualized costs without revenues from product recovery are estimated at $330 million.  In this scenario, given the assumptions about product prices, estimated revenues from product recovery are $350 million, yielding an estimated cost of savings of about $22 million.
As assumptions about natural gas prices, REC costs, and the potential emissions from hydraulically fractured natural gas well completions are influential on estimated impacts, we performed a pair of simple sensitivity analyses of the influence of these factors on the engineering costs estimate of the final NSPS.  To perform this analysis, we vary the national average wellhead natural gas price from $2/Mcf to $7/Mcf while, first, varying REC costs and, second, varying the natural gas emissions that are captured by implementing a REC.
To characterize variation in REC costs, we use the data reported in the proposal TSD that were used to estimate the national average cost of performing a REC.  On the low end of the range, we assume a REC costs $806 per day.  This represents completion and recompletion costs where key pieces of equipment, such as a dehydrator or three phase separator, are already found on site and are of suitable design and capacity for use during flowback.   On the upper end of the range, we use $7,486 per day, which represents the cost in situations where key pieces of equipment, such as a dehydrator or three-phase separator, are temporarily brought on site and then relocated after the completion.  Like the primary analysis of the NSPS cost impacts, we use the average of these two values, $4,146 per day, to represent a mid-range case.  Also like the primary NSPS impacts analysis, each REC also incurs include transportation and setup costs of $691 and completion combustion costs of $3,523 and assume an average flowback period of seven days.  In sum, the low, average, and high REC costs are estimated at $9,856, $33,237, and $56,616, respectively.
For the mean estimate of the potential emissions from hydraulically fractured natural gas well completions, we use the 9,000 Mcf per completion which is used in the primary impacts analysis.  To characterize the variation in potential natural gas emissions, we use the low and high ends of the 95 confidence interval around this mean estimate presented in a supporting technical memo.  The low-end estimate of potential emissions from hydraulically fractured natural gas well completions is estimated at 6,100 Mcf per completion and the high end at 11,700 Mcf per completion.
It is important to note two caveats to the analysis.  First, while the gas price is largely a national-level parameter (producers will face similar wellhead prices across different regions), the REC costs and potential natural gas emissions may be highly variable across the country.  Extrapolating what may be high or low end costs or potential natural gas emissions whose variation is driven by local or regional factors to a national-level estimate may overestimate or underestimate potential cost or emissions impacts.  Second, this analysis holds the number of hydraulically fractured natural gas well completions constant regardless of economic conditions.  It is likely that the decision to perform a REC without a regulatory requirement is conditioned on the producer having already decided to drill and hydraulically fracture a natural gas well.  If economic and technical conditions are conducive to drilling and hydraulically fracturing a natural gas well, it is also possible that conditions are such that RECs are more likely to be profitable if performed.  Conversely, if gas prices were low, we would expect fewer completions, and hence fewer RECs.  Consequently, the assumption of a fixed number of completions will tend to overstate total compliance cost estimates.
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 lines), as well as a function of the low, average, or high REC costs assumed faced by all producers nationally.  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 of Final NSPS Annualized Costs to Natural Gas Prices and REC Costs
      As also shown in Table 3-6, at $4/Mcf and average REC costs, the annualized costs are estimated at -$15 million.  At $4.22/Mcf, the price forecast reported in the 2011 Annual Energy Outlook, the annualized costs are estimated at about -$24 million.  As indicated by this difference, EPA has chosen a relatively conservative assumption (leading to an estimate of lower savings and higher net costs) for the engineering costs analysis.  The natural gas price at which the final NSPS breaks-even is around $3.66/Mcf.  As mentioned earlier, a $1/Mcf change in the wellhead natural gas price leads to about a $43 million change in the annualized engineering costs of the final NSPS.  Consequently, annualized engineering costs estimates would increase to about $29 million under a $3/Mcf price or decrease to about -$58 million under a $5/Mcf price.
      Meanwhile, varying the REC costs shifts the line representing annualized costs downward in the low REC cost scenario and upward in the high REC cost scenario.  At the $4/Mcf assumed wellhead natural gas prices, the annualized costs in the low REC cost scenario would be about -$120 million.  At the $4/Mcf assumed wellhead natural gas prices, the annualized costs in the high REC cost scenario would be about $94 million.
      Figure 3-2 similarly plots the annualized costs as function of the assumed price of natural gas paid to producers, but also depicts how the annualized costs might change when the potentials emissions might differ from our estimate of the national average well.

Figure 3-2	Sensitivity of Final NSPS Annualized Costs to Natural Gas Prices and Emissions Factor for Hydraulically Fractured Natural Gas Well Completions

As with the average REC costs, factor the annualized costs are estimated at -$15 million when using the average emissions.  Varying the emissions factor shifts the line representing annualized costs upward in the low emissions factor scenario and downward in the high emissions factor cost scenario.  At the $4/Mcf assumed wellhead natural gas prices, the annualized costs in the low emissions factor scenario would be about $33 million.  At the $4/Mcf assumed wellhead natural gas prices, the annualized costs in the high emissions factor cost scenario would be about -$60 million.
	The models used to forecast natural gas prices in the Annual Energy Outlook, also the source of our $4/Mcf wellhead natural gas price assumption, are deterministic.  A deterministic model does not incorporate stochastic influences and produces the same result for each model run using the same inputs and parameters.  While the Annual Energy Outlook is a commonly referenced publication that provides longer term forecasts, the U.S. EIA also produces the Short-Term Energy Outlook (STEO) which provides information about the probability distribution of energy prices over a shorter time frame.  To better understand the uncertainty associated with the 2015 natural gas price assumed in this analysis, EPA reviewed the March 2012 STEO (U.S. EIA, 2012), which includes monthly forecasted natural gas prices through 2013.  While the STEO analysis only extends to the end of 2013, the discussion of the distribution of possible future natural gas prices until that point can illuminate the uncertainty around longer-term forecasts.
      In the STEO, forecasted prices are a function of the volatility associated with a future-delivery contract, as well as the length of time until contract expiration.  The STEO also incorporates an analysis of the probabilities that natural gas prices would fall below or exceed specified prices through 2013.  We note, however, that the probability analysis uses the Henry Hub spot price, rather than the wellhead price paid to producer.  The Henry Hub price will reflect markups for processing and transportation unlike the wellhead price.  In December 2013, the EIA analysis projects a Henry Hub price of $4.28/million Btu (or $4.40/Mcf) with a 90 percent confidence interval of $2.36 to $7.16/million Btu.
      Also, the STEO reports that based upon futures prices as of February 2012, spot natural gas prices in December 2013 at the Henry Hub have a 40 percent probability of being greater than $4.00 per million Btu; a 30 percent probability of being greater than $4.50 per million Btu; a 20 percent probability of being greater than $5.00 per million Btu; and a 10 percent probability of being less than $2.50 per million Btu (U.S. EIA, 2012).  While this information is not directly comparable to the wellhead natural gas price, the probability analysis highlights the challenges associated with precisely predicting future natural gas prices.
      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 3-4 for these combustion-type controls, the final NSPS is estimated to capture about 43 billion cubic feet (bcf) of natural gas and 160,000 barrels of condensate.  Estimates of unit-level and nation-level product recovery are presented in Table 3-7 below.  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 38 bcf (or 87 percent).

Table 3-7	Estimates of Control Unit-level and National-level Natural Gas and Condensate Recovery, Sources and Emissions Points, Primary Baseline, NSPS, 2015

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

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

Hydraulically Fractured Gas Wells that Meet Criteria for REC
                                     4,107
                                     8,100
                                      34
                                  33,268,158
                                   139,644

Hydraulically Refractured Gas Wells that Meet Criteria for REC
                                      532
                                     8,100
                                      34
                                  4,309,200
                                    18,088
Equipment Leaks

Processing Plants
                                      29
                                      950
                                      0
                                    27,548
                                      0
Reciprocating Compressors

Gathering and Boosting Stations
                                      210
                                      397
                                      0
                                    83,370
                                      0

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

Processing Plants
                                      13
                                    12,526
                                      0
                                   162,844
                                      0
Pneumatic Controllers

Oil and Gas Production
                                    13,632
                                      386
                                      0
                                  5,254,997
                                      0

Processing Plants
                                      15
                                      871
                                      0
                                    13,064
                                      0
Storage Vessels

Emissions at least 6 tons per year
                                      304
                                      146
                                      0
                                    44,189
                                      0
Total (Mcf)

                                  43,388,910
                                   157,732

A second adjustment to the natural gas quantities is necessary to account for nonhydrocarbon gases removed and gas that is 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 34 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 22.4 tcf.  Consequently, the final NSPS may recover production representing about 0.15 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.