# Appendix B to the Supporting Statement for Subpart W

Dated November 2014

Respondent Burden for Years 1 through 3Year 1 through Year 3(A) HoursperOccurrence(B)OccurrencesperRespondentper Year(C) Hours/Respondent/Year (A x B)(D)Respondentsper YearEngineerHours perYear (C xD)TechHoursperYearMiddleManagerHoursper YearSeniorManagerHours perYear Cost/ Year1. APPLICATIONS (Not Applicable)2. SURVEY AND STUDIES (Not Applicable)3. ACQUISITION, INSTALLATION, AND UTILIZATION OFTECHNOLOGY AND SYSTEMS4. REPORT REQUIREMENTSA. Read Rule, Instructions, Guidance DocumentsNatural Gas Transmission Pipeline (NGTP) Facilitiesa,b,c,d5 1 5 150 750.075.0 37.5 $71,299Onshore Natural Gas Gathering and Boosting(ONGGB)Facilitiesa,c,d,e5 1 5 200 1,000.0100.050.0 $95,065Onshore Petroleum and Natural Gas Production(OPNGP)Facilitiesa,c,d,f5 1 5 50 250.025.012.5 $23,766B. Required ActivitiesONGGB Facilities--Acid Gas Removale,g,h0.17 2 0.33 20066.7$5,219ONGGB Facilities--Blowdown Vent Stackse,i,j0.13 8 1.07 200213.3$16,702Onshore Petroleum and Natural Gas Gathering andBoosting Facilities-- Equipment Leaks by PopulationCountse,k,l,m0.0083 44 0.367 20073.3---$5,741ONGGB Facilities--Dehydratorse,n,o0.42 10 4.17 200 500.0333.3 $61,335ONGGB Facilities--Flare Stackse,p0.33 18 6 200 1,200.0$93,948ONGGB Facilities--Natural Gas Pneumatic Devicese,h,q0.17 10 1.67 200 333.3$26,097ONGGB Facilities--Onshore Production Storage Tankse,r0.52 8 4.13 200 800.026.7 $64,407OPNGP Facilities--Acid Gas Removalf,g,s0.17 2 0.33 50 16.7$1,305OPNGP Facilities--Associated Natural Gas Ventingf,t,u1 142 142 50 7,100$555,859OPNGP Facilities--Associated Natural Gas Flaringf,t,v1 74 74 50 3,700$289,673OPNGP Facilities--Completions and Workovers withHydraulic Fracturing of Oil Wellsd,w,x,y24 6 144 296 42,624$3,337,033OPNGP Facilities--Dehydratorsf,m,z0.42 18 7.5 50225150 $27,601OPNGP Facilities-- Equipment Leaks by Population Countsf,aa0.0083 8 0.067 503.3$261OPNGP Facilities--Liquids Unloadingf,ab,ac0.083 5 0.417 50 20.8$1,631OPNGP Facilities--Natural Gas Pneumatic Devicesf,p,ad0.17 3 0.5 50 25$1,957Year 1 through Year 3(A) HoursperOccurrence(B)OccurrencesperRespondentper Year(C) Hours/Respondent/Year (A x B)(D)Respondentsper YearEngineerHours perYear (C xD)TechHoursperYearMiddleManagerHoursper YearSeniorManagerHours perYear Cost/ YearOPNGP Facilities--Onshore Production Storage Tanksf,r,ae0.52 103 53.22 50 2,57585.8 $207,311Natural Gas Transmission Pipeline--Blowdown Vent Stacksb,af,ag0.13 72 9.6 1501,440$112,738C. Create Information (Included in 4B)$0D. Gather Existing Information (Included in 4E)$0E. Write Report$0Annual Compliance Reporting through e-GGRTah10 1 10 400 4,000400200$380,2605. RECORDKEEPING REQUIREMENTS $0A. Read Instructions (Included in 4A)$0B. Plan Activities (Included in 4B)$0C. Implement Activities (Included in 4B)$0D. Recordkeepingai10 1 10 400 4,000400200$380,260E. Time to Transmit or Disclose Information (included in 4E) $0F. Time to Train Personnel (Not Applicable)$0G. Time for Audits (Not Applicable)TOTAL ANNUAL LABOR BURDEN AND COST538 70,917 596 1,000 500$5,759,46773,012ANNUALIZED CAPITAL COSTSTotal annual capitalaj,ak,al$ 320,571TOTAL ANNUAL COSTS (O&M)am$1,125,000TOTAL ANNUALIZED COSTS (Annualized capital + O&M costs) $1,445,571TOTAL COSTS (Labor, annualized capital, and O&M)$7,205,039a Assuming 5 hours to read and understand subpart Wand requirements for each of the three affected industry segments.b Estimated between 100 and 150 reporters. Due to the current trend of transmission pipeline expansions, 150 reporters were assumed.c Assuming that every hour of engineer work involves 0.10 hours from a Middle Manager for review.d Assuming that every hour of engineer work involves 0.05 hours from a Senior Manager for review.e Assuming that 50% of the 400 natural gas gathering pipeline reporters are large diameter, high pressure lines potentially subject to regulation.f Assuming that 5% additional onshore petroleum andnatural gas production facilities will become subject to subpart W with the addition of hydraulicallyfractured oil wells. Theoriginal ICR has 1,033 reporters so 5% is approximately 50.g Assuming 10 minutes of an engineer's time per acid gas removal vent.h Assuming two gas treatment facilities per typicalgathering and boosting facility and each would have an acid gas removal vent, dehydrator, and pneumatic controls.i Assuming eight compression/booster stations per typical gathering and boosting facility with one isolation valve/blowdown stack for each compression station.j Assuming 8 minutes per blowdown vent stack for emissions calculations.k Assuming that half of the booster stations wouldhave 4 centrifugal compressors apiece for a total of 16 centrifugal compressors. Assuming that half of the booster stationswould be smaller and have 2 reciprocating compressors apiece for a total of 8 reciprocating compressors.l Assuming that each booster station would be protected with a dehydrator and a separator plus a wastetank.m Assuming a total of 44 major pieces of equipmentper reporter per year: 10 dehydrators, 16 centrifugal compressors, 8 reciprocating compressors, and 10 separators.n Assuming ten minutes per dehydrator vent for a technician to collect data and 1.5 minutes per dehydrator vent to perform simulation runs.o Assuming two flare stacks per compression stationand one per gas treatment site.p Assuming 10 minutes per flare stack for engineerto collect data from stack.q Assuming 10 minutes per pneumatic device for engineer to determine high bleed or low bleed and applyappropriate population factor.r Assuming 1 minute per separator for technician tocollect pressure data; and 30 minutes per separator for engineer to perform simulation run.s Using RY2012 data for Onshore Petroleum and Natural Gas Production facilities, assuming an average facility contains 2 acid gas removal units.t Assuming one hour per calculation per well for engineer to calculate emissions.u Using RY2012 data for Onshore Petroleum and Natural Gas Production facilities, assuming an average facility contains 142 natural gas vents.v Using RY2012 data for Onshore Petroleum and Natural Gas Production facilities, assuming an average facility contains 74 natural gas vents that are flared.w Assuming 24 hours to conduct the measurements needed for hydraulically fractured oil wells.x Instead of taking a measurement for each oil well, assume that each reporter will elect to take "representative" measurements from each oil well type combination and applyto all wells (up to 25 completions and workovers) using Equation W-10A. The well type combinations areflare/non-flare; vertical/horizontal well type; and REC/nonREC. Themost well type combinations per reporter is 8, butassume that a typical facility has 4 of these welltype combinations.y For RY2012, 246 of the facilities in the OnshorePetroleum and Natural Gas Production segment reported oil sub-basins and the oil sub-basins containedcompanies thatconducted oil well completions with hydraulic fracturing in 2011.z Using RY2012 data for Onshore Petroleum and Natural Gas Production facilities, assuming an average facility contains 9 dehydrators.aa Assuming 0.5 minutes per piece of equipment fortechnician to count equipment for leak checks.ab Assuming 5 minutes per unloaded well for engineer to measure flow from well blowdown.ac Using RY2012 data for Onshore Petroleum and Natural Gas Production facilities, assuming an averagefacility contains 5 wells.ad Using RY2012 data for Onshore Petroleum and Natural Gas Production facilities, assuming an averagefacility contains 3 pneumatic devices.ae Using RY2012 data for Onshore Petroleum and Natural Gas Production facilities, assuming an averagefacility contains 103 storage tanks.af Assuming that the least burdensome option is theengineering calculation based on pressure, temperature, and volume of the pipeline segment, the laborburden wasestimated at 8 minutes per calculation.ag Assuming an average of 72 blowdown stacks per reporter. Assuming that there are 25 to 50 miles between isolation valves and 1,600 miles of pipeline isneeded to exceedthe reporting threshold, the average number of isolation valves ranges from 32 to 64 per small reporter. Assuming a large reporter averages 3,200 miles of pipeline or higher,the average number of isolation valves ranges from64 to 128. The average is 72 blowdown stacks per reporter.ah Assumed 10 hours per reporter to complete e-GGRTreporting. Total reporters = 150+200+50 = 400. This estimate includes the burden of reporting well identificationnumbers. This is expected to be a low burden because reporters already track and maintain well identification numbers.ai Assumed 10 hours per reporter for recordkeeping. Total reporters = 150+200+50 = 400aj Assumed that annualized capital costs for all three segments include the cost of a 4-drawer vertical file cabinet for storing records and an externalhard drive for storingelectronic data, at $57 per reporter per year.ak Assumed that annualized capital costs for Onshore Petroleum and Natural Gas Production facilities and Onshore Petroleum and Natural Gas Gathering andBoosting facilitiesinclude equipment costs of $3,500 per year per reporter (annualized to $500 over 5 years and 7% interest)al Assumed that annualized capital costs for Onshore Petroleum and Natural Gas Production facilities include flow meter costs of $585 per year per reporter (flow meter cost of$2,400 annualized at 5 years and 7% interest). Based on mass and volumetric flow meters for gas applications at Omega Engineering, Flo-Corp, Sierra Instruments, andInstrumart.am For Onshore Petroleum and Natural Gas Gatheringand Boosting, assumed operation and maintenance (O&M) costs include travel costs to measure emissionsacross largerdistances than other segments. Assumes 14 overnighttrips per year per reporter at $150 per night and$100 per diem. O&M costs also include $1,700 per year to maintain theequipment installed to monitor combustion emissions.References for Appendix BUS DOT , Pipeline and Hazardous Materials Safety Administration, Draft Regulatory Evaluation, Regulated Natural Gas Gathering Lines, Docket RSPA-1998-4868.Economic Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions Under Subpart W FinalRule (GHG Reporting); Final Report, U.S.Environmental Protection Agency Office of Atmospheric Programs. Climate Change Division. November 2010. Docket Item No. EPA-HQ-OAR-2009-0923-3601.U.S. EPA Office of Air Quality Planning and Standards (OAQPS). Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and AssociatedGas during Ongoing Production: Report for Oil and Natural Gas Sector, Oil Well Completions and Associated Gas during Ongoing Production Review Panel.April 2014. Available at http://www.epa.gov/airquality/oilandgas/pdfs/20140415completions.pdf. Pages A-7 through A-17.Who Regulates Pipelines?, Colorado Oil and Gas Conservation Commission Pipeline Safety Staff Presentation, July 17, 2013.