Appendix B to the 2015 Supporting Statement for Subpart W

Dated September 2015 

Respondent Burden for Years 1 through 3
Year 1 through Year 3 (A) Hours 

per 

Occurrence 

(B)

Occurrences 

per 

Respondent 

per Year 

(C) Hours/ 

Respondent/ 

Year (A x B) 

(D) 

Respondents 

per Year 

Engineer 

Hours per 

Year (C x 

D) 

Tech 

Hours 

per 

Year 

Middle 

Manage

r Hours 

per Yea

1. APPLICATIONS (Not Applicable) 2. SURVEY AND STUDIES (Not Applicable) 3. ACQUISITION, INSTALLATION, AND UTILIZATION OF TECHNOLOGY AND SYSTEMS 4. REPORT REQUIREMENTS  A. Read Rule, Instructions, Guidance Documents  Natural Gas Transmission Pipeline (NGTP) Facilities a,b,c,d 5 1 5 183 915.0 91.5 

Onshore Natural Gas Gathering and Boosting (ONGGB) Facilities a,c,d,e 5 1 5 200 1,000.0 100.0 Onshore Petroleum and Natural Gas Production (OPNGP) Facilities a,c,d,f 5 1 5 50 250.0 25.0 

 B. Required Activities  ONGGB Facilities--Acid Gas Removal e,g,h 0.17 2 0.33 200 66.7  ONGGB Facilities--Blowdown Vent Stacks e,i,j 0.13 8 1.07 200 213.3 

Onshore Petroleum and Natural Gas Gathering and Boosting Facilities-- Equipment Leaks by PopulationCounts e,k,l,m 0.0083 44 0.367 200 73.3 - - 

 ONGGB Facilities--Dehydrators e,n,o 0.42 8.2 3.42 200 410.0 273.3  ONGGB Facilities--Flare Stacks e,p 0.33 18 6 200 1,200.0  ONGGB Facilities--Natural Gas Pneumatic Devices e,h,q 0.17 10 1.67 200 333.3  ONGGB Facilities--Onshore Production Storage Tanks e,r 0.52 8 4.13 200 800.0 26.7  OPNGP Facilities--Acid Gas Removal f,g,s 0.17 2 0.33 50 16.7  OPNGP Facilities--Associated Natural Gas Venting f,t,u 1 142 142 50 7,100  OPNGP Facilities--Associated Natural Gas Flaring f,t,v 1 74 74 50 3,700 

OPNGP Facilities--Completions and Workovers with Hydraulic Fracturing of Oil Wells d,w,x,y 24 6 144 296 42,624 

 OPNGP Facilities--Dehydrators f,m,z 0.42 18 7.5 50 225 150 

OPNGP Facilities-- Equipment Leaks by Population Counts f,aa 0.0083 8 0.067 50 3.3 

 OPNGP Facilities--Liquids Unloading f,ab,ac 0.083 5 0.417 50 20.8  OPNGP Facilities--Natural Gas Pneumatic Devices f,p,ad 0.17 3 0.5 50 25 
Year 1 through Year 3 (A) Hours 

per 

Occurrence 

(B)

Occurrences 

per 

Respondent 

per Year 

(C) Hours/ 

Respondent/ 

Year (A x B) 

(D) 

Respondents 

per Year 

Engineer 

Hours per 

Year (C x 

D) 

Tech 

Hours 

per 

Year 

Middle 

Manage

r Hours 

per Yea

 OPNGP Facilities--Onshore Production Storage Tanks f,r,ae 0.52 103 53.22 50 2,575 85.8 

Natural Gas Transmission Pipeline--Blowdown Vent Stacks b,af,ag 0.13 15 2.0 183 366 

 C. Create Information (Included in 4B)  D. Gather Existing Information (Included in 4E)  E. Write Report  Annual Compliance Reporting through e-GGRT ah 10 1 10 433 4,330 435. RECORDKEEPING REQUIREMENTS  A. Read Instructions (Included in 4A)  B. Plan Activities (Included in 4B)  C. Implement Activities (Included in 4B)  D. Recordkeeping ai 10 1 10 433 4,330 43 E. Time to Transmit or Disclose Information (included in 4E)  F. Time to Train Personnel (Not Applicable)  G. Time for Audits (Not Applicable) TOTAL ANNUAL LABOR BURDEN AND COST 30 70,578 536 1,083 ANNUALIZED CAPITAL COSTS  Total annual capital aj,ak,al TOTAL ANNUAL COSTS (O&M) am TOTAL ANNUALIZED COSTS (Annualized capital + O&M costs) TOTAL COSTS (Labor, annualized capital, and O&M) 
a Assuming 5 hours to read and understand subpart W and requirements for each of the three affected industry segments. In the second and third 

assumed to be used for training industry personnel.b During the public comment period INGAA asserted that there are 183 reporters, instead of 150, based on the number of operators that are requiannual report (PHMSA F-7100-2) or are regulated by FERC under Section 311 of the NGPA. 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 and natural gas production facilities will become subject to subpart W with the addition of hydra

The original 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 typical gathering and boosting facility and each would have an acid gas removal vent, dehydrator, and i Assuming eight compression/booster stations per typical gathering and boosting facility with one isolation valve/blowdown stack for each compre

j Assuming 8 minutes per blowdown vent stack for emissions calculations. k Assuming that half of the booster stations would have 4 centrifugal compressors apiece for a total of 16 centrifugal compressors. Assuming that 

would 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 waste tank. 

m Assuming a total of 44 major pieces of equipment per reporter per year: 10 dehydrators, 16 centrifugal compressors, 8 reciprocating compresso

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 20% of compression stations have flare stacks and one flare per gas treatment site. p Assuming 10 minutes per flare stack for engineer to collect data from stack. q Assuming 10 minutes per pneumatic device for engineer to determine high bleed or low bleed and apply appropriate population factor. 

r Assuming 1 minute per separator for technician to collect 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 aw 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 wel

apply to all wells (up to 25 completions and workovers) using Equation W-10A. The well type combinations are flare/non-flare; vertical/horizontal w

The most well type combinations per reporter is 8, but assume that a typical facility has 4 of these well type combinations. y For RY2012, 246 of the facilities in the Onshore Petroleum and Natural Gas Production segment reported oil sub-basins and the oil sub-basins con

conducted 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 for technician 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 average facility contains 5 wells. 

ad Using RY2012 data for Onshore Petroleum and Natural Gas Production facilities, assuming an average facility contains 3 pneumatic devices. ae Using RY2012 data for Onshore Petroleum and Natural Gas Production facilities, assuming an average facility contains 103 storage tanks. af Assuming that the least burdensome option is the engineering calculation based on pressure, temperature, and volume of the pipeline segmentestimated at 8 minutes per calculation. 
ag Assumed an average of 15 blowdown stacks per reporter, based on public comments. 

ah Assumed 10 hours per reporter to complete e-GGRT reporting. Total reporters = 183+200+50 = 433. ai Assumed 10 hours per reporter for recordkeeping. Total reporters = 183+200+50 = 433 aj Assumed that annualized capital costs for all three segments include the cost of a 4-drawer vertical file cabinet for storing records and an extern

electronic 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 Gatfacilities include 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 pe

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, 

Instrumart. am For Onshore Petroleum and Natural Gas Gathering and Boosting, assumed operation and maintenance (O&M) costs include travel costs to me

larger distances than other segments. Assumes 14 overnight trips per year per reporter at $150 per night and $100 per diem. O&M costs also inclu

maintain the equipment installed to monitor combustion emissions. 
References for Appendix B 

US DOT , Pipeline and Hazardous Materials Safety Administration, Draft Regulatory Evaluation, Regulated Natural Gas Gathering Lin

4868. Economic Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions Under Subpart W Final Rule (GHG Reporting)

Environmental Protection Agency Office of Atmospheric Programs. Climate Change Division. November 2010. Docket Item No. EPA

3601. U.S. EPA Office of Air Quality Planning and Standards (OAQPS). Oil and Natural Gas Sector Hydraulically Fractured Oil Well Comp

Gas during Ongoing Production: Report for Oil and Natural Gas Sector, Oil Well Completions and Associated Gas during Ongoing ProApril 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.