MEMORANDUM

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

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

DATE: November 10, 2014

SUBJECT: Assessment of Impacts of the 2015 Proposed Revisio ns to Subpart W

Introduction
The EPA is proposing 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 proposed amendments.

The EPA estimated the cost of these proposed amendm ents to subpart W as the incremental costs above the previously estimated co sts of the requirements under subpart W. 1
The EPA calculated this incremental cost based on t he number of reporters in each segment that are likely to be affected by these proposed amendme nts. The details for estimating this incremental cost (the potential burden to reporters ) are included in the sections below.

Costs to reporters associated with this proposal ar e expressed as labor costs (i.e., the cost of labor by facility staff to meet the proposed ame ndments), 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 industry segment s the labor rates are $121.72 for senior managers, $106.89 for middle managers, $78.29 for e ngineers and $66.57 for technicians. 2

Summary of Proposed Amendments

Oil Well Completions and Workovers with Hydraulic F racturing within the Onshore Petroleum and Natural Gas Production Segment
The EPA is proposing to amend subpart W to clarify the applicability of the current provisions for the reporting of GHG emissions from completions and workovers for wells in the Onshore Petroleum and Natural Gas Production segmen t, regardless of whether their primary

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

product is oil or natural gas, and to include provi sions for the reporting of GHG emissions from completions and workovers from oil wells with hydra ulic fracturing. The proposed provisions include the reporting of activity data on the numbe r of oil wells with hydraulic fracturing and on the use of flaring and reduced emissions completion s. These proposed revisions represent a potential increase to burden and cost because facil ities with oil wells would 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 proposed changes to subpart W is approximately 50 per year.

The proposed changes will also affect existing repo rters. Based on RY2012 subpart W data, 322 of the existing facilities in the Onshore Petroleum and 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 hydrau lic fracturing is not known. However, using oil well completions data from 2011, we can estimat e the number of existing reporters expected to report completions and workovers for oil wells w ith hydraulic fracturing in the future. According to DI Desktop, a production database main tained by DrillingInfo, Inc., 6,169 of the 39,262 conventional and unconventional well complet ions (for gas and oil) in 2011 were identified as oil well completions with hydraulic f racturing. 4 The white paper included a list of sub-basins where these oil well completions with hy draulic fracturing took place in 2011. 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 faciliti es were identified. These 246 facilities in the Onshore Petroleum and Natural Gas Production segmen t are located in sub-basins where oil well completions with hydraulic fracturing have taken pl ace. Assuming that oil well completions with

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 Hydraulical ly 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. Av ailable
at http://www.epa.gov/airquality/oilandgas/pdfs/201404 15completions.pdf

.3

hydraulic fracturing in those sub-basins are likely to continue in the future, the number of existing reporters that are expected to report comp letions and workovers for oil wells with hydraulic fracturing as a result of these proposed 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 proposed measurements represent a potential i ncrease in 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 seven-day period, the measurements are assumed to be conducted over a mul tiple-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 measurements per reporter, the labor burden for each reporter is 144 hours per yea r. Assuming 246 existing 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 proposed amendments, the EPA is pr oposing to add a new industry segment to subpart W, Onshore Petroleum and Natural Gas Gathering and Boosting, that would cover emissions from equipment used by gathering an d boosting systems that move petroleum4

and natural gas from the well to either larger gath ering and boosting systems, natural gas processing plants, natural gas transmission pipelin es, or natural gas distribution pipelines. This proposed revision represents an increase in burden and cost for reporters with sources that would be covered by this new industry segment. These sour ces include venting from natural gas pneumatic devices, natural gas driven pneumatic pum ps, storage tanks, reciprocating compressors, dehydrators, acid gas removal units, a nd centrifugal compressors; flare stacks; and leaks from gathering pipelines and components such as valves and connectors. Facilities in this industry segment are not currently required to repo rt subpart W-related GHG emissions, but would be required to collect data, calculate, and r eport these emissions under the proposed 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 facility would, for safety purposes, have one or more flare stacks at various points in the system to avoid venting of gas during an upset. Each gas treatment site would like ly have a flare stack, an acid gas removal unit vent, storage tank vents, gas-driven pneumatic pump s and other pneumatic controllers. The stand-alone 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

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

• 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.

• 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 proposed 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 4,700 labor hours and $370,000 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 proposed amendments, the EPA is pr oposing to add a new industry segment to subpart W, the Onshore Natural Gas Trans mission Pipeline segment. For this new

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

industry segment, the EPA is proposing to add repor ting requirements for emissions from blowdowns of natural gas transmission lines between compressor stations. The EPA is proposing that reporters would use one of two methods to calc ulate or measure emissions from pipeline blowdown events. One method allows a reporter to ca lculate emissions based on the volume of the pipeline segment between isolation valves that is blown down and the pressure and temperature of the gas within the pipeline. This me thod uses information that should be readily available to the reporter (e.g., pipeline length, d iameter, and operating pressure) and so should not be overly burdensome. The second method allows the reporter to measure the emissions from the blowdown using a flow meter on the blowdown ven t stack. In both methods, the reporter would calculate both methane (CH 4 ) and CO 2 emissions from the volume of natural gas vented using either default gas composition or engineering estimates of composition. This proposed change is a potential increase in burden for report ers that have natural gas transmission pipelines covered by the proposed new segment.

The addition of this new industry segment is expect ed to affect approximately 100 to 150 reporters. Due to the upward trend in transmission pipeline expansions, we assumed the larger estimate of 150 reporters per year.

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 directly measu ring emissions using a flowmeter. This choice also results in lower burden to the reporter s.
These proposed measurements represent a potential i ncrease in burden and cost. It was estimated that an engineer would spend approximatel y 8 minutes per calculation per blowdown vent stack to estimate emissions for this new indus try 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. A value of 72 blowdown stacks was assumed for an average reporter

. 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 was an estimate of 2,300 labor hours and $180,000 in labor costs per reporter (at a rate of $78.29/hour)7

to collect data and calculate emissions for the new Onshore Natural Gas Transmission Pipeline segment.

Well Identification Numbers
The EPA is proposing to add reporting requirements for well identification numbers for wells in the Onshore Petroleum and Natural Gas Prod uction segment. The well identification number is either the US Well Number (formerly calle d the API Well Number), or if a US Well Number has not been assigned, a unique number assig ned by the permitting authority. The EPA is proposing to require the reporting of well ident ification numbers for the Onshore Petroleum and Natural Gas Production segment in two general c ases. First, the EPA proposes to require reporters in the Onshore Petroleum and Natural Gas Production segment to report a list of well identification numbers for all wells in a sub-basin represented by the reported emissions data. Second, for reporters that report emissions using i nput data that are calculated from measurements at individual wells or equipment assoc iated with individual wells the EPA proposes to require the reporter to report the well identification number for which those measurements were made, or for which the equipment is associated.

These numbers are readily available and do not requ ire any additional data gathering or calculation. Therefore, this proposed change would not impose any additional burden and costs (beyond the additional reporting burden, which is d iscussed in the next section).

Reporting and Recordkeeping Provisions
The EPA is proposing that 232 new data elements be reported. The proposed 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 proposed amendments are expected to result in approximately 9,200 labor hours and $760,000 in labor costs per year to report data and maintain records.8

Capital and Operations and Maintenance (O&M) Costs
These proposed amendments to subpart W affect all t hree industry segments and require an inclusion of process- and combustion-related cap ital 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 $22,800 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 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 . These proposed amendments to subpart W that are i ncluded in this information collection affect the combustion-r elated 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.

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

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 proposed amendments to subpart W.

Process-related costs . These proposed amendments to subpart W included i n this information collection affect reporters in the Onsh ore Petroleum and Natural Gas Production segment with completions or workovers of oil wells with hydraulic fracturing. During flowback, the natural gas flow rate is monitored using a volu metric flow meter. The capital equipment costs were estimated at $2,400 (annualized over 5 years a t 7% interest to $585 per year). 12 The total cost to the 246 existing reporters and 50 new repor ters 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 proposed amendments to subpart W are summarized by industry segment in Tab le 1. There are no changes in burden to these industry segments: Onshore Natural Gas Proces sing, 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 Proposed 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 5,753 38.35 $477,828 $3,186
Onshore Petroleum and Natural Gas Gathering and Boosting 9,297 46.48 $1,899,839 $9,499
Onshore Petroleum and Natural Gas Production 57,963 53.52 $4,827,372 $4,4 57 TOTAL 73,012 $7,205,039