Implications of the proposed federal greenhouse gas mandatory reporting rule on the Oil & Gas Industry.

1. Oil & Gas Meet Greenhouse Gas Andrew D. Shroads, QEP Regional Director S. Cohen & Associates P.O. Box 1276 • Westerville, OH 43086 ) (614) 887-7227 • 8ashroads@scainc.com

2. Greenhouse Gas Timeline - I 1863 John Tyndall lectures about Earth’s atmosphere exhibiting a “greenhouse effect” 1896 Svante Arrhenius develops theory relating carbon dioxide (CO2) concentration to temperature changes 1958 Dr. Charles Keeling begins measuring atmospheric CO2 1990 International Panel for Climate Change Report: Emissions from humans are substantially increasing greenhouse gas concentration and warming the Earth 2

3. Greenhouse Gas Timeline - II 1997 Kyoto Protocol ratified – legally binding commitments to reduce GHG emissions 2005 Kyoto Protocol takes effect (blame Russia) 2007 Bulletin of Atomic Scientists moves Doomsday clock to 11:55 PM, due to global warming 2009 Environmental Protection Agency (EPA) proposes greenhouse gas regulations March 31, 2011 First GHG emissions report (C.Y. 2010) due to EPA 3

4. What are Greenhouse Gases? 4 Gases that absorb thermal infrared radiation (heat), making the Earth about 59º F warmer than without the gases There are several greenhouse gases (GHGs); 6 are regulated by this rule: 1. Carbon Dioxide (CO2) 2. Methane (CH4) 3. Nitrous Oxide (N2O) 4. Perfluorocabons (PFC) 5. Hydrofluorocarbons (HFC) 6. Sulfur Hexafluoride (SF6)

5. Greenhouse Gas Potency Report emissions of carbon dioxide (CO2), nitrous dioxide (N2O) and methane (CH4) and total emissions in carbon dioxide equivalents (CO2e) CO2e is the GHG multiplied by its global warming potential (GWP) CO2 GWP = 1 CH4 GWP = 21 N2O GWP = 310 CO2e = (CO2×1)+(CH4×21)+(N2O×310)

6. Example: GHG & GWP 6 My home burns 100,000 cf/year N.G., emitting: 12,001.12 lbs. CO2 0.20 lbs. CH4 0.02 lbs. N2O From 40 CFR 98, Tables A-1, C-1, C-2 To calculate the total CO2e emissions, multiply each pollutant by its GWP (CO2 = 1, CH4 = 21, and N2O = 310). 12,001.12 lbs. CO2 × 1 = 12,001 lbs. 0.20 lbs. CH4 × 21 = 4 lbs. 0.02 lbs. N2O × 310 = 6 lbs. Total CO2e 12,011 lbs. (6 U.S. short tons)

8. Onshore Production

9. Liquiefied N.G. Storage

10. Offshore Production

11. Onshore N.G. Processing

12. Natural Gas Transmission, Compression and Underground Storage

14. GHG Reporting Applicability - LDC Subpart W: Total GHG emissions ≥25,000 MT CO2e/year from: Facility (Gas Distribution Equipment after “City Gate”) Any stationary fuel combustion sources (heaters) or other categories in §98.2(a)(2) (H2 production) Subpart NN: All LDC must report On August 11, 2010, EPA proposed modifying this requirement to only LDC supplying >460 MMCF/year of natural gas, as 460 MMCF/year of natural gas is equal to 25,000 metric tons of CO2e

15. Subpart W: LDC - I Subpart W regulates operations distributing natural gas Each LDC must estimate the natural gas lost by the equipment in the distribution system after the “city gate” station (end of high pressure transmission line) Above ground gate stations (metering and regulating stations) Valves, (including pressure safety), and connectors Open-ended lines Natural gas driven pneumatic devices Below grade vaults (regulator stations) Buried pipelines

16. Subpart W: LDC - II For above ground meter regulators; and Gate station fugitive emissions from connectors, block valves, control valves, pressure relief valves, orifice meters, other meters, regulators, and open ended lines Conduct an annual leak detection with an optical gas imaging instrument on any line with a gas content >10% CH4, plus CO2 (by weight) If a leak is detected, estimate emissions from all leaking equipment using EPA emissions factors in Subpart W for leaking equipment and the hours the equipment was used during the year

17. Subpart W: LDC - III For below ground meter regulators and vault fugitives; Pipeline main fugitives; and Service line fugitives Lines with a gas content >10% CH4, plus CO2 (by weight) must be reported; Leak detection not required; EPA emissions factors are provided in Subpart W; Emissions are estimated using a “population count” equation: Source Count × EPA Factor × Hours in Operation

18. Subpart NN: LDC - IV Subpart NN regulates the LDC as a natural gas supplier Emissions are estimated assuming all natural gas delivered is combusted, stored, or re-distributed To reduce double-counting, end-users receiving 460,000,000 standard cubic feet/year (460 MMCF/yr) are removed from calculation These facilities should already have to report their combustion emissions under Subpart C, as 460 MMCF/year is equal to 25,000 metric tons CO2e Equation: EPA Factor ×(Gas In - Gas Otherwise Counted)

19. GHG Reporting Applicability – Producers I Subpart W would be applicable to any facility with total GHG emissions ≥25,000 MT CO2e/year Facility is defined at the “basin-level” EPA proposes to use the Association of Petroleum Geologists (AAPG) three-digit Geological Province Code to define each basin All equipment owned, rented, or leased by the same entity on all well pads within each basin The company required to report GHG emissions is the “operating entity” listed on state well drilling or operating permit for the wells For jointly managed facilities, one entity must be chosen

20. GHG Reporting Applicability – Producers II GHG emissions are estimated from any equipment used in drilling the well, storing gas or petroleum, gathering product from multiple wells, and enhanced oil recovery (EOR) operations, including: Compressors; Generators; Storage facilities; Piping; and Portable non-self-propelled equipment All equipment is included, even if rented or leased

21. Subpart W: Onshore Production - I Each operation must estimate emissions from well drilling operations, device venting, fugitive emissions, vent stacks, tanks, and dissolved CO2 in liquids Emissions are estimated using a combination of: leak detection (using optical imaging equipment), direct analytical measurements, engineering calculations, emissions factors, and emissions simulation software (E&P Tank & GlyCalc)

22. Subpart W: Onshore Production - II EPA tested GHG from four production cases at well pads Range of GHG emissions from a single well pad: 370 metric tons CO2e – production at an associated gas and oil well (no drilling) with minimal equipment and a vapor recovery unit (67 wells = 25,000 MT) 5,000 metric tons CO2e – Unconventional well drilling and operation starting in the beginning of the year with higher emitting practices (5 wells = 25,000 MT) Due to the large number of potential emissions sources, well pad emissions will be extremely variable Could use a “worst-case scenario” to determine when GHG emissions reporting is required

23. Subpart W: Onshore Production - III

24. Subpart W: Onshore Production - IV Records are required for every emissions source Population counts Number of blowdowns, well completions, conventional and unconventional well workovers Analysis of oil / gas produced Oil / gas production information Equipment used for data anaylsis Dates measurements obtained Results of all emissions detected and measurements Calibration reports for measuring equipment Inputs / outputs of calculations or simulations Missing data requires new analysis or calculation

25. Subpart W: Portable Equipment GHG emissions from portable equipment are used to determine applicability and estimate GHG emissions Combustion emissions from portable equipment that cannot move on roadways under its own power and drive train and stationed at a wellhead for more than 30 days in a reporting year Includes: drilling rigs, dehydrators, compressors, electrical generators, steam boilers, and heaters GHG emissions from combustion are calculated using 40 CFR, Part 98, Subpart A

26. Subpart W: Additional Proposals Subpart W is only a proposed rule; EPA is considering field-level reporting, (as defined in Energy Information Administration Oil and Gas Field Code Master) Field-level reporting would allow more wells to fall below the reporting threshold It is unlikely that EPA would overrule basin-level reporting, as it would collect less data EPA is also considering using the U.S. Geologic Survey (USGS) definition for basin, which is based purely on the geology of the hydrocarbon basin, ignoring county lines USGS definition would make it more difficult to map surface operations to a specific basin

27. Subpart C: Stationary Fuel Combustion - I 22 Applicability: All stationary units that combust fuels (e.g. boilers, engines, process heaters, incinerators) Does not include: Portable sources, (unless required by Subpart W) Emergency generators, (emergency use only) Flares, (unless required by Subpart W) Hazardous waste combustion (unless another fuel is used) EPA website has an emissions calculator for Subpart C

28. Subpart C: Stationary Fuel Combustion - II 23 GHG to report: CO2, CH4, and N2O Calculation Methods (Tiers): 1. Fuel Usage × Default Heat Factor × GHG Factor Default heat factor – average heating value per amount of fuel, (e.g. MMBTU/CF); Table C-1 2. Fuel Usage × Measured Heat Factor × GHG Factor Measured heat factor - heating value per amount of fuel 3. Fuel Usage × Fuel Carbon Content × 44(CO2)/12(C) Measuredcarbon content - percent of carbon in fuel 4. Continuous Emissions Monitoring System (CEMS) Measured carbon emissions rate exiting stack

29. Subpart C: Stationary Fuel Combustion - III 24 Using Calculation Method Tier 1 Unit Maximum Rated Heat Capacity ≤250 MMBTU/hour Fuel used is listed in Table C-1: Gases: Natural Gas, Blast Furnace Gas, Coke Oven Gas Petroleum Products: Fuel Oil, Kerosene, LPG, Gasoline Cannot use if fuel heating value is analyzed Using Calculation Method Tier 2 Unit Maximum Rated Heat Capacity ≤250 MMBTU/hr or >250 MMBTU/hr, if firing natural gas or distillate fuel oil Fuel used is listed in Table C-1

30. Subpart C: Stationary Fuel Combustion - IV 25 Fuel Analysis (Tier 2): Periodic fuel analyses for fuels listed in §98.34(a) Natural Gas – Semiannual analyses Coal & Fuel Oil – One from each delivery Liquid & Gas (not Fuel Oil or Natural Gas) – Once per calendar quarter Solid (not Coal) – Weekly samples analyzed monthly From an Ohio EPA air permit: For each shipment of oil received for burning in this emissions unit, the permittee shall collect … a representative grab sample of oil and maintain records of the … analyses for sulfur content and heat content…

31. Subpart C: Stationary Fuel Combustion - V 26 Additional Fuel Analysis Requirements: Fuel sampling is only required if the unit operates within the time period for fuel analysis (e.g. calendar quarter) For blended fuels, either use a weighted heating value, based on the proportions of fuels within the blend or have a representative blended fuel sample analyzed Oil or gas flow meters (Tier 3) must be calibrated Fuel billing meters (if provided by a separate owner) can be used in lieu of oil or gas flow meters For missing analysis data, use the average of the before and after values.

32. Example – Fuel Burning 27

33. Subpart RR: CO2 Injection & Sequestration Proposed subpart applies to any well in which CO2 is injected into the subsurface, including wells for geologic sequestration (GS) or for any other purpose If doing CO2 injection for any other purpose than GS, not subject to other parts of Part 98 GS is long-term storage of CO2

34. So You Have To Report Determine GHG emissions for each applicable subpart: Subpart C – stationary fuel combustion Subpart P – hydrogen production Subpart W – production or LDC (proposed) Total GHG emissions ≥25,000 MT, submit a GHG report For LDC, applicability is also determined as a supplier Subpart NN – all LDC are applicable U.S. EPA has proposed a 460 MMCF/year exemption For CO2 injection, report CO2 injected if otherwise required to report under the GHG rule (≥25,000 MT)

35. Reporting Exemptions 30 Research & development activities: Activities conducted in process units or at laboratory bench-scale settings whose purpose is to conduct research and development for new processes, technologies, or products and whose purpose is not for the manufacture of products for commercial sale.

36. Resource: EPA GHG Applicability Tool 31 www.epa.gov/climatechange/emissions/GHG-calculator Select source categories from the list, calculate annual CO2e emissions, and the results will detail rule applicability and the appropriate subparts. EPA GHG hotline: 877-GHG-1188

37. Discontinuing Reporting Emissions must be reported each year, even if emissions are reduced below 25,000 MT CO2e; however, there are three possible methods whereby a facility can reduce emissions and cease reporting (Subpart RR not applicable): 1. Emissions are less than 25,000 MT CO2e for five consecutive years; 2. Emissions are less than 15,000 MT CO2e for three consecutive years; or 3. ALL applicable GHG-emitting processes cease to operate; not applicable to municipal solid waste landfills. Instead of a final report, a cessation notification is submitted. 32

38. Submitting the Report The GHG emissions report will be submitted through a website setup by EPA The website is called the electronic Greenhouse Gas Reporting Tool (e-GGRT) Currently unavailable e-GGRT registration will be online “soon” Will include the reporting requirements for each Subpart http://www.epa.gov/climatechange/emissions/e-ggrt_faq.html

39. Signing the Report - I 34 Designated Representative (DR): an individual having responsibility for the overall operation of the facility Plant manager; Superintendent; Operator of a well or a well field; Position of equivalent responsibility; or Position having overall responsibility for environmental matters for the company. If subject to 40 CFR 75, must be same individual. Can delegate alternate designated representative (ADR) DR and ADR may be with different companies

40. Signing the Report - II Certificate of Representation: Submitted by the DR and ADR to EPA at least 60 days prior to a GHG due date (January 30, 2011); Separate from the GHG Report; Lists the owners or operators for the facility; Form will be a printout from e-GGRT; Certifies that the DR and ADR have a written “document of agreement” with the owners or operators of the facility; DR and ADR actions are binding upon the facility owners and operators. 35

41. Signing the Report - III 36 Agent: The DR or ADR can further delegate to an agent; An agent submits the report on behalf of the DR or ADR; Agent can be someone within or outside the organization, (e.g. contractors, other partners) Agent is given authorization to EPA by DR or ADR; Agent is delegated through e-GGRT

42. Recordkeeping Requirements The following records are required: Every unit for which GHG emissions were calculated Data used in GHG calculations, required in a Subpart Copies of the annual GHG reports submitted Any missing data computations Written GHG monitoring plan Certification results and maintenance records for instruments required in a Subpart Any additional records required in a Subpart All records must be maintained onsite and readily accessible for three years. 37

43. GHG Monitoring Plan Each facility must develop a written GHG Monitoring Plan (GHGMP) that details the following procedures: Positions responsible for collecting GHG data Processes / methods for collecting GHG data Procedures used for quality assurance, maintenance, and repair of monitoring systems and equipment Delegation Agreement and Certificate of Representation The GHGMP can reference existing documents, provided that the requirements are easily identified. EPA can request a copy of the GHGMP or review the GHGMP during an audit. 38

44. GHG and Title V Permits GHG is now a pollutant in Title V operating permits Emissions trigger is 100,000 tpy of actual or potential GHG emissions Sites not triggering GHG reporting rule would not trigger Title V permit (25,000 MT = 27,000 U.S. tons) Title V was not written for oil & gas production Does not include portable sources “Facility” has to be contiguous, not “basin-level” Ownership / partnership issues What are the potential GHG emissions from drilling?

45. Questions?