MEMORANDUM

TO: Docket ID No. EPA-HQ-OAR-2014-0831

FROM: Alexis McKittrick and Mark de Figueiredo, EPA/CCD

DATE: September 23, 2015
SUBJECT: Assessment of Impacts of the 2015 Revisions to Sub part W

Introduction The EPA is finalizing technical revisions and other clarifications to subpart W of the Greenhouse Gas Reporting Rule (40 CFR part 98, subp art W) (hereafter referred to as “subpart W”). In this memorandum, we discuss the potential b urden to reporters affected by these amendments.

The EPA estimated the cost of these amendments to s ubpart W as the incremental costs above the previously estimated costs of the require ments under subpart W. 1 The EPA calculated this incremental cost based on the number of report ers in each segment that are likely to be affected by these amendments. The details for estim ating this incremental cost (the potential burden to reporters) are included in the sections b elow.
Costs to reporters associated with this rulemaking are expressed as labor costs (i.e., the cost of labor by facility staff to comply with the amendments), capital costs for equipment and travel, and operation and maintenance (O&M) costs. The EPA determined labor costs using an approach consistent with previous impacts analyses associated with the Greenhouse Gas Reporting Program (GHGRP). For all subpart W indust ry segments the labor rates are $121.72 for senior managers, $106.89 for middle managers, $ 78.29 for engineers and $66.57 for technicians. 2
Summary of Amendments
Oil Well Completions and Workovers with Hydraulic F racturing within the Onshore Petroleum and Natural Gas Production Segment The EPA is amending subpart W to clarify the applic ability of the current provisions for the reporting of GHG emissions from completions and workovers for wells in the Onshore

1 The previously estimated costs of the requirements under subpart W are included in the Information Col lection Request for the Greenhouse Gas Reporting Program, O MB Control No. 2060-0629, EPA ICR No. 2300.15. 2 The engineering and technician labor rates are from the May 2011 National Industry-Specific Occupation al Employment and Wage Estimates (http://www.bls.gov/o es/2011/may/oessrci.htm) and Employer Costs for Employee Compensation for June of 2011 (http://www. bls.gov/news.release/archives/ecec_09082011.pdf).2

Petroleum and Natural Gas Production segment, regar dless of whether their primary product is oil or natural gas, and to include provisions for t he reporting of GHG emissions from completions and workovers from oil wells with hydra ulic fracturing. The provisions include the reporting of activity data on the number of oil wel ls with hydraulic fracturing and on the use of flaring and reduced emissions completions. These re visions represent a potential increase to burden and cost because facilities with oil wells w ould be reporting emissions that they were not previously required to report.
The addition of data elements related to completion s and workovers from oil wells with hydraulic fracturing is expected to cause an increa se in the number of facilities reporting in subpart W, because this additional emissions source may cause some facilities to cross the applicable 25,000 metric ton carbon dioxide equival ent (CO 2 e) threshold. We expect that most of the facilities that include this emission source al ready report under subpart W, because the owners/operators of these facilities typically own other oil and gas operations that fall within the Onshore Petroleum and Natural Gas Production segmen t. Therefore, we do not anticipate a large number of new reporters and assumed that the additi on of oil wells with hydraulic fracturing would increase the number of new reporters in this segment by 5 percent (%). As documented in ICR number 2300.15, the number of existing reporter s in the Onshore Petroleum and Natural Gas Production segment is 1,033. Therefore, the num ber of new reporters that are expected to exceed the reporting threshold as a result of these changes to subpart W is approximately 50 per year. The changes will also affect existing reporters. Ba sed on RY2012 subpart W data, 322 of the existing facilities in the Onshore Petroleum an d Natural Gas Production segment already reported sub-basins that are classified in the Oil sub-basin category. 3 The number of completions and workovers for oil wells with hydraulic fracturi ng is not known. However, using oil well completions data from 2011, we can estimate the num ber of existing reporters expected to report completions and workovers for oil wells with hydrau lic fracturing in the future. An EPA white paper from April 2014 included a list of sub-basins where oil well completions with hydraulic fracturing took place in 2011. 4 By comparing the list of sub-basins identified in the white paper with the list of sub-basins reported under subpart W, a list of 246 overlapping facilities were identified. These 246 facilities in the Onshore Pet roleum and Natural Gas Production segment are located in sub-basins where oil well completion s with hydraulic fracturing have taken place. Assuming that oil well completions with hydraulic f racturing in those sub-basins are likely to continue in the future, the number of existing repo rters that are expected to report completions

3 http://www.ccdsupport.com/confluence/display/help/ Sub-Basin+Selection 4 U.S. EPA Office of Air Quality Planning and Standa rds (OAQPS). Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas d uring Ongoing Production: Report for Oil and Natura l Gas Sector, Oil Well Completions and Associated Gas dur ing Ongoing Production Review Panel . April 2014. Available at http://www.epa.gov/airquality/oilandgas/pdfs/201404 15completions.pdf

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and workovers for oil wells with hydraulic fracturi ng as a result of these amendments is 246 per year. Instead of conducting measurements for each complet ion of an oil well with hydraulic fracturing, each affected reporter is assumed to ta ke “representative” measurements from one oil well of each oil well type combination and apply to all wells with that combination (up to 25 completions and workovers) using Equation W-10A. Th e oil well type characteristics are as follows:

• Vertical or horizontal (directional drilling)

• With flaring or without flaring

• Reduced emission completion/workover or not reduced emission completion/workover The maximum number of oil well type combinations us ing the three well type characteristics above is eight, but a typical repor ter is assumed to have three of these well type combinations per sub-basin, no more than 25 complet ions or workovers for each well type combination, and an average of two sub-basins per r eporter. Thus, each reporter is assumed to perform six oil well measurements per year.
After the initial flowback period when meters are n ot typically used, measurements are assumed to be made using a volumetric flow meter to measure the gas flow rate during flowback. The costs for these meters are included in the “Cap ital and Operations and Maintenance (O&M) Costs” section of this memo.
These measurements represent a potential increase i n burden and cost. It was estimated that an engineer would take approximately 24 hours per well to conduct each measurement. While flowbacks generally occur over a three to sev en-day period, the measurements are assumed to be conducted over a multiple-day period for a total of 24 hours per measurement per well. Therefore, engineering labor hours (at a cost of $78.29/hour) were adjusted upwards by 24 hours per reporter. Assuming 6 oil well measurement s per reporter, the labor burden for each reporter is 144 hours per year. Assuming 246 existi ng reporters and 50 new reporters, the total burden is estimated at 43,000 labor hours and $3.3 million per year to collect data and calculate emissions for oil wells with hydraulic fracturing.
Onshore Petroleum and Natural Gas Gathering and Boo sting Segment As part of these amendments, the EPA is adding a ne w industry segment to subpart W, Onshore Petroleum and Natural Gas Gathering and Boo sting, that would cover emissions from equipment used by gathering and boosting systems th at move petroleum and natural gas from the well to either larger gathering and boosting system s, natural gas processing plants, natural gas4

transmission pipelines, or natural gas distribution pipelines. This revision represents an increase in burden and cost for reporters with sources that would be covered by this new industry segment. These sources include venting from natural gas pneumatic devices, natural gas driven pneumatic pumps, storage tanks, reciprocating compr essors, dehydrators, acid gas removal units, and centrifugal compressors; flare stacks; and leak s from gathering pipelines and components such as valves and connectors. Facilities in this i ndustry segment are not currently required to report subpart W-related GHG emissions, but would b e required to collect data, calculate, and report these emissions under the revisions.
According to the Office of Pipeline Safety (OPS), t here are 400 natural gas gathering pipeline operators under regulation by OPS. 5 OPS estimated that 50% of these operators are potentially subject to the new regulation (dependin g upon proximity to population centers), resulting in approximately 200 reporters. 6
Every producing field that is connected to a gather ing and boosting system is assumed to have a compressor or a compression station at the c onnection point to the gathering and boosting system, and every compression station is assumed to have a separator and dehydrator to protect the compressors. Every separator/dehydration system installation is assumed to have at least one storage tank. In between compression points on the gathering line, there will be an isolation/blowdown valve. By definition, the Onshor e Petroleum and Natural Gas Gathering and Boosting segment consists of large, basin-level fac ilities, so it follows that at least one standalone gas treatment site should be assumed per faci lity, the purpose of which is to remove impurities such as sulfur and carbon dioxide (CO 2 ) from the gas. Each gas treatment site would likely have a flare stack, an acid gas removal unit vent, storage tank vents, gas-driven pneumatic pumps and other pneumatic controllers. The stand-al one gas treatment site would be a possible location for an emergency flare system.
In order to calculate the burden on reporters in th e Onshore Petroleum and Natural Gas Gathering and Boosting segment, we created a model reporter loosely based on a description of a “typical” gathering and boosting system by the Colo rado Oil and Gas Conservation Commission. 7

• An average reporter consists of two 40- to 60-mile gathering and boosting systems with the same owner/operator within a singl e basin.

• Each of the two gathering and boosting systems that comprise the model reporter is connected to three producing fields, so six fiel ds total.

5 US DOT, Pipeline and Hazardous Materials Safety Administrat ion, Draft Regulatory Evaluation, Regulated Natural Gas Gathering Lines , Docket Item No. PHMSA-RSPA-1998-4868-0181. 6 Ibid

. 7 Who Regulates Pipelines?, Colorado Oil and Gas Conservation Commission Pipeli ne Safety Staff Presentation, July 17, 2013.5

• There is a compression station associated with each connected field and each gathering and boosting system has a stand-alone gas treatment facility with a compressor station on the outlet side.

• This “model” reporter would thus have a minimum of eight compression (“booster”) stations.

• There would be an isolation valve/blowdown stack do wnstream of each booster station and downstream of the gas treatment site, s o up to eight isolation valves.

• We assume that two thirds of the “booster” stations would be protected with a dehydrator and a separator plus a waste tank.

• We assume that half the booster stations would have four centrifugal compressors and half of the booster stations would be smaller w ith two reciprocating compressors.

• Each compressor station would use natural gas as fu el and to drive pneumatic controllers and equipment.

• We assume that each of the two gas treatment facili ties would have an acid gas removal vent, dehydrator, and pneumatic controls.

• Each of the two gathering and boosting systems that comprise the gathering and boosting facility would have at least one metering point, so two meter runs. For these amendments, the reporters in the Onshore Petroleum and Natural Gas Gathering and Boosting segment will be able to use methods that are already included in subpart W. To be consistent with the monitoring and measure ment levels of effort used for the existing industry segments, all monitoring and measurement l evels of effort were estimated using the Economic Impact Analysis from November 2010. 8
The number of hours per reporter was determined by multiplying the time needed to collect data and calculate emissions for each sourc e type by the count of that source type at a gathering and boosting facility and then summing th e results. The result was an estimate of 4,600 labor hours and $360,000 in labor costs to collect data and calculate emissions for the new Onshore Petroleum and Natural Gas Gathering and Boo sting segment.
Onshore Natural Gas Transmission Pipeline Segment As part of these amendments, the EPA is adding a ne w industry segment to subpart W, the Onshore Natural Gas Transmission Pipeline segme nt. For this new industry segment, the EPA is adding reporting requirements for emissions from blowdowns of natural gas transmission lines between compressor stations. The EPA is final izing that reporters would use one of two methods to calculate or measure emissions from pipe line blowdown events. One method allows a reporter to calculate emissions based on the volume of the pipeline segment between isolation

8 Economic Impact Analysis for the Mandatory Reportin g of Greenhouse Gas Emissions Under Subpart W Final Rule (GHG Reporting); Final Report, U.S. Environmen tal Protection Agency Office of Atmospheric Program s. Climate Change Division. November 2010. Docket Item No. EPA-HQ-OAR-2009-0923-3601. Pages 4-23 through 4-28.6

valves that is blown down and the pressure and temp erature of the gas within the pipeline. This method uses information that should be readily avai lable to the reporter (e.g., pipeline length, diameter, and operating pressure) and so should not be overly burdensome. The second method allows the reporter to measure the emissions from t he blowdown using a flow meter on the blowdown vent stack. In both methods, the reporter would calculate both methane (CH 4 ) and CO 2 emissions from the volume of natural gas vented us ing either default gas composition or engineering estimates of composition. This change i s a potential increase in burden for reporters that have natural gas transmission pipelines covere d by the new segment.
The addition of this new industry segment was expec ted to affect approximately 100 to 150 reporters. Due to the upward trend in transmiss ion pipeline expansions, at proposal we assumed the larger estimate of 150 reporters per ye ar. However, during the public comment period, INGAA asserted that there are 183 reporters regulated by the Pipeline and Hazardous Materials Safety Administration (PHMSA), basing the estimate on the number of operators required to complete a PHMSA annual report (PHMSA F -7100-2) or are regulated by Federal Energy Regulatory Commission (FERC) under Section 3 11 of the Natural Gas Policy Act (NGPA). As a result, the number of reporters in thi s industry segment was adjusted to 183 in the final analysis.
Due to the fact that transmission pipeline compress or stations are unmanned, the pipeline throughput and characteristics are continuously mon itored. The resulting data would be readily available to reporters, so it was assumed that repo rters would choose to calculate emissions from pipeline blowdown events rather than measuring emis sions using a flowmeter. This choice also results in lower burden to the reporters.
These measurements represent a potential increase i n burden and cost. It was estimated that an engineer would spend approximately 8 minute s per calculation per blowdown vent stack to estimate emissions for this new industry segment

. In order to estimate the average number of blowdown stacks, it was assumed that there are 25 to 50 miles between isolation valves and app roximately 1,600 miles of pipeline are needed to exceed the reporting threshold. For a relatively small reporter, the average number of isolation valves ranges from 32 to 64 per reporter. For a lar ger reporter, it was assumed the facility would average at least 3,200 miles of pipeline. Using the same assumptions above, the average number of isolation valves were assumed to range from 64 t o 128 for larger reporters. At proposal, a value of 72 blowdown stacks was assumed for an aver age reporter.
During the public comment period, commenters reque sted that smaller ancillary equipment located along pipelines be excluded from the definition of blowdown for the Onshore Natural Gas Transmission Pipelines industry segment . One commenter further noted that the7

number of blowdowns assumed at proposal should be a djusted based on whether or not ancillary equipment is included in the count of blowdowns. Th e commenter suggested that including small ancillary equipment results in a much higher number of blowdowns than proposed by EPA (approximately 315 blowdowns per respondent) and th at excluding small ancillary equipment should result in a lower number of blowdowns than p roposed by EPA (approximately 17 blowdowns per respondent).
The EPA agrees that the emphasis for this reportin g segment is on capturing and reporting emissions from pipeline segments so the f inal rule clarifies that the focus of this segment does not include blowdown emissions from sm all ancillary equipment. Therefore, the EPA has changed the estimated number of transmissio n pipeline blowdowns from 72 per respondent to 17 per respondent.
The number of hours per reporter was determined by multiplying the time needed to collect data and calculate emissions by the number of blowdown stacks. The result is an estimate of 370 labor hours and $30,000 in labor costs (at a rate of $78.29/hour) to collect data and calculate emissions for the new Onshore Natural Gas Transmission Pipeline segment.
Well Identification Numbers The EPA is adding reporting requirements for well i dentification numbers for the Onshore Petroleum and Natural Gas Production segmen t. The well identification number is either the US Well Number (formerly called the API Well Number), or if a US Well Number has not been assigned, a unique number assigned by the permitting authority. For reporters in the Onshore Petroleum and Natural Gas Production segmen t that report emissions using input data that are calculated from measurements at individual wells or equipment associated with individual wells, the reporter is required to repor t the well identification number for which those measurements were made and the well identification number(s) of other wells to which the measurements will be applied. The EPA is not finali zing the proposed requirement that reporters in the Onshore Petroleum and Natural Gas Production segment report a list of well identification numbers associated with different emission sources for all wells in a sub-basin included in the reported emissions data.
At proposal, the EPA assumed that well identificati on numbers were already collected. As a result of the comments received, the EPA reeva luated the proposal and agrees that the well ID requirements were more burdensome than initially intended. The final amendments represent numbers that are readily available and do not requi re any additional data gathering or calculation. Therefore, this change would not impose any change in burden and costs from proposal.8

Reporting and Recordkeeping Provisions The EPA is adding 207 new data elements to the repo rting requirements. The new data elements would impose additional burden and costs b ecause, for each of the new data elements that would be required to be reported, reporters wo uld be required to calculate the data element using readily available data, and report the value to the EPA via the EPA’s Electronic Greenhouse Gas Reporting Tool (e-GGRT) as part of t he annual report currently required under Part 98.
The EPA calculated the increase in reporting and re cordkeeping burden associated with new data elements by adjusting labor hours upwards per reporter for all affected industry segments. For all three segments, an estimate of 10 hours per year per reporter was allotted for reporting via e-GGRT and 10 hours per year per repo rter was allotted for recordkeeping.
These amendments are expected to result in approxim ately 9,960 labor hours and $820,000 in labor costs per year to report data and maintain records.
Capital and Operations and Maintenance (O&M) Costs These amendments to subpart W require an inclusion of process- and combustion-related capital and O&M costs for recordkeeping equipment, travel, and monitoring equipment.
Recordkeeping . Assuming the purchase of a 4-drawer vertical file cabinet for storing documents and an external hard drive for storing el ectronic data, the annualized capital cost for each reporter in each of the three industry segment s is $57. 9
For all three affected industry segments, the total annualized capital cost for recordkeeping is approximately $25,000 per year.

Travel . For Onshore Petroleum and Natural Gas Gathering a nd Boosting facilities, the size of a facility was assumed to encompass a much larger geographic area than a relatively compact producing field or a gas processing plant. In order to account for emissions measurement across a larger area, travel costs were included and assumed to consist of 14 overnight trips per reporter per year. Assuming $15 0 per night and $100 per diem, 10 a cost of $3,500 per reporter per year was assumed.

No travel costs were assumed for the Onshore Natura l Gas Transmission Pipeline segment. Due to the fact that compressor stations a re unmanned, pipeline throughput is

9 Ibid. Page 4-29. 10 Economic Impact Analysis for the Mandatory Reportin g of Greenhouse Gas Emissions Under Subpart W Final Rule (GHG Reporting); Final Report, U.S. Environmen tal Protection Agency Office of Atmospheric Program s. Climate Change Division. November 2010. Docket Item No. EPA-HQ-OAR-2009-0923-3601. Page 4-29.9

continuously monitored and controlled and the engin eering data would be readily available to the reporters in the Onshore Natural Gas Transmission P ipeline segment. Therefore, reporters are assumed to perform engineering calculations based o n pressure, temperature, and volume of the pipeline segment rather than traveling to the compr essor stations to take measurements.
To be consistent with past ICR analyses, no travel costs were assumed for the Onshore Petroleum and Natural Gas Production segment.
The total annual cost for travel is $700,000 per ye ar.

Combustion-related costs . The amendments to subpart W that are included in this information collection affect the combustion-relate d capital and O&M costs for the Onshore Petroleum and Natural Gas Production segment and th e Onshore Petroleum and Natural Gas Gathering and Boosting segment. For all other segme nts, the capital and O&M costs have not changed from ICR Number 2300.15.
For Onshore Petroleum and Natural Gas Gathering and Boosting and Onshore Petroleum and Natural Gas Production segments, the capital an d O&M costs associated with combustion emissions were based on the assumptions in ICR Numb er 2376.02, which assumed the use of Tier 1 methodology and included capital equipment c osts of $3,500 (annualized over 10 years at 7% interest to $500 per year) and O&M costs of $1,7 00 per year. 11 The total cost to the two industry segments is approximately $550,000 per yea r.

There are no combustion sources at Onshore Natural Gas Transmission Pipeline facilities, so there are no increases to combustion-related cap ital and O&M costs as a result of these amendments to subpart W.

Process-related costs . The amendments to subpart W included in this info rmation collection affect reporters in the Onshore Petroleu m and Natural Gas Production segment with completions or workovers of oil wells with hydrauli c fracturing. During flowback, the natural gas flow rate is monitored using a volumetric flow meter. The capital equipment costs were estimated at $2,400 (annualized over 5 years at 7% interest to $585 per year). 12 The total cost to the 246 existing reporters and 50 new reporters is approximately $170,000 per year.

11 Ibid. Page 4-11 12 Based on an average cost of five volumetric gas fl ow meters from Omega Engineering, FLO-CORP, Sierra Instruments, and Instrumart.10

Results of Analysis The estimated change in burden (labor hours) and co st for these amendments to subpart W are summarized by industry segment in Table 1. Th ere are no changes in burden to these industry segments: Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, LNG I mport and Export Equipment, Natural Gas Distribution, LNG Storage, and Offshore Petrole um and Natural Gas Production.
Table 1. Annual Average Change in Reporter Burden a nd Cost for Changes to Subpart W

Industry Segment Change in Total

Burden (Technical Labor Hours) Change in Burden

(Technical Labor Hours/Reporter) Change in Total Cost ($) Change in Cost

($/reporter) Onshore Natural Gas Transmission Pipeline 5,627 30.75 $474,065 $2,591 Onshore Petroleum and Natural Gas Gathering and Boosting 9,147 45.73 $1,888,798 $9,444 Onshore Petroleum and Natural Gas Production 57,963 195.82 $4,827,372 $16 ,309 TOTAL 72,737 $7,190,235