**TO:** Kate Cardamone , U.S. EPA

**FROM:** Hemant Mallya , Eric Stricklin, IC F International **DATE:** August 18 , 2011 **SUBJECT:** Mandatory Greenhouse Gas Reporting: Changes in National Cost Estimates Associated with the Notice of Revisions for Subpart W On November 8, 2010, Administrator Jackson signed a rule that finalizes reporting requirements for the petroleum and natural gas industry under 40 CFR Part 98, the regulatory framework for the Greenhouse Gas (GHG) Reporting Program (11/30/10; 75 FR 74458)
. This final rule requires petroleum and natural gas facilities that emit 25,000 metric tons or more of carbon dioxide (CO 2 ) equivalent per ye ar to report annual methane (CH 4 ) and CO 2 emissions from equipment leaks and venting, and emissions of CO 2 , CH 4 , and nitrous ox ide (N2 O) from gas flaring and from onshore petroleum and natural gas production stationary and portable combustion emissions and combustion emissions from stationary equipment involved in natural gas distribution. EPA is amending specific provisions in Subpart W of the GHG rule to resolve issues and questions raised during implementation, and to correct technical and editorial errors that have been identified since publication. This memorandum documents how these proposed revisions would change the estimated compliance costs presented in the Economic Impact Anal ys is for the 2010 final rule. 1 **Proposed Amendment to Gas Well Completion Sampling**  **Requirement: Estimated Change in**  **Compliance Cost**  EPA has proposed to change the methodology for onshore production facilities’ gas well venting during completions with hydraulic fracturing and workovers with hydraulic fracturing . Instead of requiring the sampling from at least one gas well completion and workover per field (“field method”) , the propos ed methodology would require sampl ing of the average flow rate of gas based on a graded scale within a sub
-basin (“sub
- basin method”)
. A sub
- basin is proposed to be defined as : a subdivision of a basin into the unique combination of wells with the surface coordinates within the boundaries of an individual county and subsurface completion in one or more of each of the following four formation types: conventional with >0.1 millidarci permeability, and unconventional with ≤0.1 millidarci permeability shale, coal seam, and other tight reservoir rock. Wells producing from more than one formation type shall be classified into only one based on the formation type

1 See http://www.epa.gov/climatechange/emissions/downloads10/Subpart

- W_EIA.pdf for the Economic Impact Analysis.contributing the most production as determined by engineering knowledge.

Unconventional wells producing from formations categorized in two or more types are considered shale for a combination of “shale and coal”, “shale and other tight”, or “shale, coal and other tight”; and are considered as coal for combinations of “coal and other tight". While this proposed sub
-basin method does not change the cost per sample estimated for the final rule , it decrease s the total number of samples that will be reported from well completions and workovers
. Specifically , the number of samples expected from reporters in the first year will decrease for completions and workovers from 1,970 to 1, 670
. Accordingly , the average compliance cost in the first year will decrease from $14,356 to $14, 182 per onshore production facility
. In addition, the compliance cost in subsequent years will decrease from $7,425 to $7, 3 38 per facility . The table below summari z es the change in compliance costs associated with the proposed sub
-basin method. **Table 1**  **. Summary of First Year**  **Compliance Cost for Field and Sub -**  **Basin Methods (Gas Well Completions and Workovers with Hydraulic Fracturing)**  **Costs and Samples for Reporters Field Method**  (Nov 2010 Final Rule) **Sub -**  **Basin**

**Method** (2011 Proposed Rule) **Difference**

**between Methods** First Year Cost per Facility ($) $14,356 $14,1 82 ( $174 ) Subsequent Year cost Per Facility ($) $7,425 $7,3 38 ( $87 ) Total National Cost ($ million) $10.7 $10. 6 ( $0.1 ) Cost Effectiveness ($/tonneCO2e) 0.05 0.05
- Number of Samples for Completions and Workovers with Hydraulic Fracturing (Count) 1,970 1, 670 ( 300 ) † The cost figures in this table include costs associated with reporting both process and combustion emissions. **Other Amendments in Notice of Revisions** EPA is proposing to revise several other provisions in Subpart W . EPA has determined that thes e revisions do not affect the compliance costs estimated in the Economic Impact Analysis for the 2010 final rule. The se proposed revisions are categorized as follows: 1. P rovide additional flexibility for reporters based on questions raised during implementation. 2. S implif

y existing monitoring method s . 3. C larify existing industry segment definitions
. 4. C orrect and clarify

inconsistencies in monitoring methodologies
. 5. Correct and clarify

data reporting requirements
.6. Add and clarif y other existing definitions
. See Appendix A for an elaboration on each of these changes and examples from the revisions.

### Appendix A **: Revisions that Do Not Affect Cost Estimates** 

**1. Provided additional flexibility for reporters:**  Based on alternative monitoring methods requested b y trade associations and through questions submitted from potential reporters, EPA has proposed additional flexibility in the monitoring methods for estimating emissions from the following sources :

 Gas well liquids unloading
- measure the natural gas flow rate of a liquids unloading event for each **sub -**  **basin** , pressure range, and unique tubing diameter , instead of measuring the natural gas flow rate of a liquids unloading event for each well tubing diameter and producing horizon/formation combination in each gas producing **field**
.  Blowdown vent stacks

– track the volume of each blowdown occurrence instead of estimating the annual average for all blowdown occurrences
.  F lare stacks

– measure emissions using continuous emission monitoring systems (CEMS) , instead of not allowing reporters to determine flaring emissions using CEMS
. These methods do not replace any of the lowest cost methodologies that were modeled in the cost anal ys is for the final rule and therefore do not impact the final rule’s cost estimate
. In short, EPA expects only

those reporters that already have high cost options in place to use them; other rep orters have been assumed to use the low cost option as in the final rule. 2 EPA therefore expects that they will not incur the entire cost of even the low cost option . That is, the EPA cost assumption is conservativel y higher for these reporters that alre ady have the high cost options in place
. **2. S**  **implified existing**  **monitoring methods:** EPA is proposing several changes to the monitoring methods that will potentially simplify monitoring and reporting emissions , as follows :  Pneumatic devices and pneumatic pumps
– determine ty pe of pneumatic device using engineering estimate based on best available data instead of not specifying how to determine the ty pe of pneumatic device and pneumatic pump .  Transmission storage tanks

– measure emissions from vent stack without performing leak detection versus requiring the leak detection before measuring a leak
. An additional option to use calibrated bags and high flow

2 Potential reporters will still be able to determine emissions from liquids unloading and flare stacks using an engineering calculation, which EPA determined to be the lowest cost methodology. Potential reporters can also still use the low

cost option to determine the annual average emissions from blowdown volumes.samplers in addition to the existing options to use meters. Also, an additional option to use stethoscope ty pe acoustic devices to detect leaks.  GHG volumetric emissions

– use default gas composition for CH 4 and CO 2 in natural gas for onshore natural gas transmission, underground natural gas storage, LNG storage, LNG import and export terminals, and natural gas distribution instead of requiring facilities to either use existing gas composition to estimate average annual values or sample gas to determine composition. These simplifications do not impact the cost anal ysis for the final rule because they do not significantl y change the assumptions made for how potential reporter s will comply with the rule. **3. Clarification of existing**  **industry segment category definitions:**  Based on questions and inputs received from potential reporters and trade associations during implementation, EPA is proposing to further clarify the definitions for the following industry segment s : onshore petroleum and natural gas production ; onshore natural gas processing ; onshore natural gas transmission ; and natural gas distribution
. These proposed revisions do not chang e any of the segment boundaries and will not have any impact on who reports or the total number of reporters. Consequently , these revisions do not change the cost estimates . A list of these revisions is provided in the Background Technical Support Document for the proposed Subpart W Revisions Package. **4. Corrections and clarifications to equations and calculation methodologies:**  Based on input from potential reporters and EPA internal review , EPA has identified several inconsistencies and opportunities for clarification to the calculation methodologies in §98.233. EPA is proposing corrections and providing clarification to these equations
. A detailed list of correctio ns to the Equations is available in the Background Technical Support Document for the proposed Subpart W Revisions Package
. These equation changes provide clarity onl y and do not change the inputs required to perform the calculations . Therefore, these revisions do not change the cost estimates
. **5. Corrections and clarifications to**  **data reporting requirements**  **:** Potential reporters have raised questions and identified several inconsistencies in the reporting requirements in §98.236 . EPA is proposing corrections and providing clarification as follows:

 CH 4 , CO 2 and N2 O emissions

– Clarify that emissions for each gas must be reported separatel y.  Flared and vented emissions

– Clarify that flared and vented emissions must be report ed separatel y. Recovered emissions

– Clarify that any recovered emissions must be reported separately
.  Level of reporting

– Clarify whether a specific requirement is on a per equipment basis, facility

level, annual average , or any other applicable level of reporting in Subpart W.  Unique ID name or ID number

– Addition of unique ID name or ID number for applicable source ty

pes . There is no change in the cost estimates from these proposed corrections and clarifications. Also, there is only

one addition to the data repo rting requirement . EPA has added an overarching requirement for each onshore production facility to report average API gravity , gas - to - oil ratio (GOR) , and low pressure separator pressure for each sub
-basin within the facility . However, EPA understands that this is information is already available to the facility operators because it is needed to conduct business. Oil and gas operators know the GOR and API gravity because they are determined at least once a year to pay taxes, royalties, and in general for selling oil and gas. Those operators who use method 1 in 98.233(j) to estimate emissions from tanks will already collect their low pressure separator pressure . Also, those who do not use method 1 for estimating tank emissions can still collect this information when they

collect equipment counts for estimating fugitive emissions. Finally , the data documentation and report submission costs in the final rule already account for any post processing of data collected and reporting . That is, the final rule already accounts for time to collect equipment count at each well pad; collecting one more piece of information at that stage does not increase the cost estimate . Th erefore, EPA does not expect additional costs for reporting this data. A list of new definitions and changes to the reporting requirements is provided in the Background Technical Support Document for the Subpart W Revisions Package. **6. Added and clarified ex**  **isting definitions**  **:** EPA provided new definitions and clarified existing definitions
. The proposed addition of these definitions are meant to help reporters understand the monitoring and reporting requirements finalized in the November 2010 rule; they do not add new requirements and therefore do not change the cost estimates
.