Mandatory Greenhouse Gas Reporting Rule Mr. Charles Frushour U.S. EPA Clean Air Markets Division EPRI CEM User Group Meeting Cleveland, Ohio May 2010

Disclaimer Any communication on the mandatory GHG reporting rule is intended to provide general and administrative information about the Rule. This communication does not provide legal advice, and responses to questions received do not have legally binding effect or expressly or implicitly create, expand, or limit any legal rights, obligations, responsibilities, expectations, or benefits in regard to any person. Facility owners or operators and suppliers are responsible for determining how they would be affected by the requirements of the rule.

3 Background On October 30, 2009, prompted by a Congressional appropriations bill, EPA published a final rule, 40 CFR Part 98, which requires the reporting of greenhouse gas (GHG) emissions from various industries in the American economy, including electricity generation, petroleum refining, cement manufacturing, and many others. Suppliers of coal-based liquid fuels, petroleum products, natural gas and natural gas liquids are also required to report under this rule. The vast majority of the reportable GHG emissions under Part 98 are from stationary fuel combustion sources such as boilers, combustion turbines, engines, incinerators, space heaters etc. Owners and operators are required to calculate and report annual emissions of CO 2, CH 4, and N 2 O from these sources, using the methods specified in the rule. Note: The proposed requirement to report sulfur hexafluoride (SF 6 ) emissions from electrical equipment (Subpart DD) was not finalized in the October 30, 2009 rule. On April 12, 2010, a supplement to the text of the original Subpart DD proposal was published in the Federal Register (See 75 FR 18651). The substance of the supplemental proposal is embedded in the preamble, and addresses the definition of a facility with respect to Subpart DD.

Background (contd) EPA has been sued on various aspects of the rule including definitions, calibration requirements, applicability and implementation issues The Agency is working with litigants to resolve the issues raised EPA has also received a significant number of questions from stakeholders since publication of the final rule, primarily concerning issues related to implementation

5 Assessing Part 98 Applicability In Part 98, the term source category generally refers to a specific industry (e.g., electricity generation, petroleum refining, etc.) The GHG emissions calculation and reporting requirements for each source category are presented in a separate Subpart of Part 98. For example, the requirements for electricity generation are found in Subpart D. Although stationary fuel combustion (Subpart C) is classified as a separate source category, it is actually a cross-cutting category, common to many other subparts. A facility can and will most likely be comprised of multiple source categories. For instance, a facility may have both electricity generation (Subpart D) and stationary fuel combustion units (Subpart C) within its boundaries.

Assessing Part 98 Applicability (contd) You must evaluate each facility separately to assess Part 98 applicability: –Facilities that include certain source categories are automatically subject to the rule. For example, a facility that includes any Acid Rain Program or Regional Greenhouse Gas Initiative (RGGI) units is automatically subject to Subpart D of Part 98. –Facilities that are not automatically in, but include at least one source category listed in the rule, must use the calculation methods in Part 98 to estimate their annual GHG emissions. If the applicability threshold of 25,000 metric tons of CO 2 equivalent (CO 2 e) is exceeded, the facility must report annual GHG emissions under Part 98. When a facility triggers Part 98 applicability, the owner or operator must report GHG emissions for all source categories at the facility for which emissions calculation methods are provided in the rule.

Subpart A – General Provisions Part 98 requires an annual GHG emissions report for each affected facility. The report must be submitted electronically in a format specified by the Administrator, no later than March 31 st of each calendar year. The report summarizes the GHG emissions for the previous year. The first batch of electronic reports is due by March 31, 2011, covering the GHG emissions for calendar year Reporters must assign a Designated Representative (DR) for each affected facility. The DR is responsible for certifying, signing and submitting the GHG emissions reports. The same DR who is assigned to submit reports for any Part 75 program (e.g., Acid Rain, CAIR) must also be assigned to submit the annual Part 98 GHG emissions reports.

Subpart A – General Provisions (contd) The electronic emissions reporting format is currently under development Verification of the reported emissions data will be done electronically by EPA, in conjunction with periodic field audits of selected facilities. EPA considered, but rejected, using third party verification. Note: Part 75 emissions data, as reported to EPA using the ECMPS Client Tool, do not satisfy the reporting requirements of Part 98.

Subpart A – General Provisions (contd) Each Part 98 facility is required to develop and maintain a written GHG monitoring plan (See §98.3(g)(5)). The monitoring plan (MP) must include documentation and a written explanation of the procedures and methods used to collect the data and to quality-assure the measurement devices used to provide inputs for the GHG emissions calculations. The MP may refer to applicable portions of existing corporate documents, e.g., the QA requirements in Part 60 and/or Part 75, Part 75 QA plans, MACT plans, SOPs, etc.

Subpart A – General Provisions (contd) Section 98.3(i) of Part 98 sets forth general calibration requirements for the equipment used to provide data for the GHG emissions calculations. A 5% accuracy standard is specified. These calibration requirements do not apply: –To electricity generating units that monitor and report emissions data to EPA using Part 75 methodologies; or –To Part 98 units and processes for which the use of company records (as defined in §98.6) is specified to quantify fuel usage and/or other parameters Litigants and stakeholders have objected to the calibration requirements in §98.3(i) as being too all-inclusive, i.e., not appropriate for all types of measurement devices.

Subpart A – General Provisions (contd) Section 98.6 of the rule provides definitions of key terms used in Part 98. Reporters should familiarize themselves with these definitions. EPA has received a number of questions on definitions contained in 98.6 (e.g., natural gas, MSW) and received requests to define additional terms (e.g. agricultural byproducts, primary fuel, solid byproducts, wood residuals, etc.)

Subpart A – Questions & Answers Q: May the DR assign agents to submit the Part 98 GHG emissions reports on his behalf, as is allowed for Part 75 electronic reporting? A: Yes. Q: How long must I retain records under Part 98? A: A minimum of three years--- see §98.3(g). Q: May I retain records electronically and at an off-site location? A: Yes, provided the records are readily available for review by inspectors and auditors.

Subpart A – Questions & Answers (contd) Q: I operate a facility with Acid Rain and/or RGGI units that operate infrequently and the entire facility emits less than 25,ooo metric tons of CO 2 e on an annual basis. Am I required to report GHG emissions under Part 98? A: Yes. Acid Rain Program and RGGI units are subject to Subpart D of Part 98, which is one of the source categories that automatically triggers Part 98 applicability, regardless of the facilitys annual GHG emissions. See §98.2(a)(1)(i). Q: Part 98 exempts portable equipment from GHG emissions reporting. How do I determine if my equipment is portable? A: See the definition of portable in §98.6. Equipment that resides at the same location (within a facility) for more than 12 consecutive months is not considered to be portable, unless the equipment is designed to be moved from one location to another within the facility.

Subpart D---Electricity Generation Subpart D of Part 98 (Electricity Generation) includes only EGUs that are subject to the Acid Rain Program, and any other EGUs that are required to monitor and report annual CO 2 mass emissions to EPA using Part 75 (at present, this applies only to RGGI units). All other EGUs and other stationary fuel combustion sources at electricity generating facilities are subject to the requirements of Subpart C – General Stationary Fuel Combustion (see below). Acid Rain and RGGI units must continue to monitor CO 2 mass emissions year-round according to Part 75, and to report these data to EPA quarterly using the ECMPS Client Tool. This electronic reporting is unaffected by Part 98.

Subpart D---Electricity Generation (contd) For the purposes of the Part 98 GHG emissions report, Acid Rain and RGGI units must convert the cumulative annual CO 2 mass emissions reported in their 4 th quarter Part 75 EDRs from units of short tons to metric tons. (Metric tons = Short tons divided by ) Acid Rain and RGGI units must also calculate CH 4 and N 2 O emissions and include these emissions estimates in the GHG emissions report. For units that combust only one type of fuel, CH 4 and N 2 O emissions are calculated using the cumulative annual heat input from the Part 75 report together with emission factors from Table C-2 of Part 98. If a unit combusts more than one type of fuel listed in Table C-2, use the best available information to estimate the portion of the cumulative annual heat input derived from each fuel type.

Subpart D---Electricity Generation (contd) Subpart D units must meet the applicable record keeping and reporting requirements in §98.3(g) of Subpart A and §98.36(d) of Subpart C. EPA has clarified in hotline responses that the requirement to have separate reporting of biogenic CO 2 emissions from Subpart D units is optional.

17 Subpart C---Stationary Fuel Combustion Subpart C applies: To the calculation and reporting of GHG emissions from stationary fuel combustion sources (such as boilers, simple and combined-cycle combustion turbines, engines, incinerators, and process heaters). Subpart C does not apply to: Subpart D electricity generating units Flares Portable equipment Emergency generators and emergency equipment Irrigation pumps Hazardous waste combustion (unless CEMS are used to monitor CO 2 mass emissions) EPA has clarified in hotline responses that reporting of CO 2 emissions from pilots is not required

Subpart C – General Stationary Fuel Combustion (contd) When the use of Subpart C is required for the stationary fuel combustion units in a particular source category, reporters must calculate CO 2, CH 4, and N 2 O emissions for those units using the methods in Subpart C. Subpart C prescribes a four-tiered approach for calculating CO 2 mass emissions: –Tier 1 applies chiefly to smaller units (250 mmBtu/hr or less) that combust fuels listed in Table C-1 of Subpart C. Company records are used to quantify fuel usage. Default high heat values (HHVs) and CO 2 emission factors are used in the calculations. –Tier 2 is similar to Tier 1, except that measured HHVs are used in the calculations. Also, Tier 2 may be used for the combustion of natural gas and distillate oil in larger combustion units (> 250 mmBtu/hr).

Subpart C – General Stationary Fuel Combustion (contd) Tier 3 applies mainly to large combustion units (> 250 mmBtu/hr) and may apply to combustion of a fuel not listed in Table C-1, if the fuel contributes 10% or more of the units annual heat input. Tier 3 requires periodic measurement of the fuel carbon content and molecular weight (gaseous fuels, only). For liquid and gaseous fuels, the use of calibrated flow meters to quantify fuel consumption is required in most cases. (Fuel billing meters and tank drop measurements may also be used) Tier 4 requires the use of CEMS to measure CO 2 mass emissions. Tier 4 only applies if a series of conditions are met. Among other things, the unit must combust solid fossil fuel or MSW and have an established CEMS infrastructure in place. Part 98 allows until January 1, 2011, if necessary, for the required Tier 4 CEMS to be certified. Tier 2 or 3 may be used in An alternative to using the four Tiers is provided in §98.33(a)(5), for certain stationary fuel combustion units. This alternative applies to units that are not in the Acid Rain Program or RGGI, and that report heat input data to EPA year-round using Part 75 methodologies.

Subpart C – General Stationary Fuel Combustion (contd) At present, the alternative applies chiefly to certain EGUs that are subject to the Clean Air Interstate Rule (CAIR) Units that qualify for this alternative may use their Part 75 monitoring data together with appropriate equations from Appendices F and G of Part 75 to calculate annual CO 2 mass emissions. For example, a unit that uses flow rate and CO 2 monitors to determine heat input rate could use hourly data from these monitors and Equation F- 11 to calculate CO 2 mass emissions. (NOxSIP) As a second example, a unit that uses Appendix D of Part 75 to determine heat input rate could use hourly heat input data and Equation G-4 to calculate CO 2 mass emissions. (CAIR Combustion Turbine)

Subpart C – General Stationary Fuel Combustion (contd) Facilities that have Subpart C stationary fuel combustion sources on-site need to identify which of the methods for calculating CO 2 mass emissions they are either required or allowed to use, taking into account the size of the combustion equipment, fuel type(s), availability of HHV data, and other information (see §98.33(b)). CH 4 and N 2 O mass emissions are calculated using fuel-specific, heat input- based emission factors found in Table C-2. The appropriate equation for calculating CH 4 and N 2 O emissions depends upon which method is used for the CO 2 mass emissions calculations (see §98.33(c)). Subpart C units that combust biomass fuels must calculate and report biogenic CO 2 emissions separately, using the appropriate method(s) in § 98.33(e).

Subpart C – General Stationary Fuel Combustion (contd) Reporters using Tier 4 are not required to notify EPA or State Agencies of the expected date(s) for initial certification testing or on-going QA testing. However, EPA recommends that these notifications be provided as a courtesy to the regulatory agencies. Tier 4 reporters must maintain records of initial certification tests and on- going QA test results (See §98.36(e)(2)(vii)). The reporting section of Subpart C (§98.36) provides several alternatives to individual unit reporting, for units using the four Tiers. These options are intended to reduce the reporting burden by allowing the GHG emissions from multiple units to be combined. –The CO 2 mass emissions from a group of units, each of which has a maximum rated heat input capacity of 250 mmBtu/hr or less, may be aggregated for reporting purposes, provided that the units burn the same fuel type and use the same Tier to calculate CO 2 emissions (See §98.36(c)(1)).

Subpart C – General Stationary Fuel Combustion (contd) Reporting Alternatives (contd) –The combined CO 2 mass emissions from a group of Tier 4 units that share a common stack may be monitored at the common stack (See §98.36(c)(2)). –The combined CO 2 mass emissions may be reported from a group of units that combust the same liquid or gaseous fuel and are fed by a common pipe or supply line (See §98.36(c)(3)). Since publication of the October 30, 2009 final rule, EPA has received significant feedback from industry regarding Subpart C. Areas of concern include, among other things, the applicability of Tiers 1-4, the methods prescribed for calculating biogenic CO 2 emissions, the list of fuels and emission factors in Table C-1, calculation of GHG emissions for blended fuels, the definition of a fuel lot for fuel sampling purposes, and the need for site-specific default moisture values. We are considering how to address the issues and concerns raised.

Subpart C – Questions and Answers Q: May I use Tier 2 to calculate CO 2 mass emissions if HHV data are available at the required frequency specified in §98.34(a)(2), but the method used to determine the HHV is not one of the methods listed in §98.34(a)(6) ? A: At the present time, no. Q: With respect to stationary combustion sources, is waste oil considered to be an unconventional fuel, since it is not included in Table C-1? A: No. For the time being, calculate GHG emissions from the combustion of waste oil using the emission factors in Table C-1 for Other Oil. Q: If I use Tier 1 or 2 to calculate CO 2 mass emissions and measure the annual natural gas consumption using a fuel flow meter, does the flow meter have to meet the calibration requirements of §98.3(i)? A: No. The calibration requirements of §98.3(i) do not apply to Tier 1, which specifies that company records are to be used to quantify fuel usage.

Subpart C – Questions and Answers (contd) Q: If I choose to use the alternative CO 2 mass emissions calculation method in §98.33(a)(5) for a non-Acid Rain unit that is subject to CAIR, may I use my Part 75 DAHS to generate a CO 2 mass emissions data stream and include it in my quarterly Part 75 electronic data reports ? If so, does this satisfy my Part 98 obligation to report CO 2 mass emissions? A: You may add a CO 2 mass emissions data stream to your quarterly Part 75 electronic data reports, even though you are not required to report CO 2 mass emissions under CAIR (see the ECMPS instructions for implementing this option, posted on the CAMD website). However, simply reporting CO 2 mass emissions in your Part 75 electronic reports does not satisfy the Part 98 CO 2 mass emissions reporting requirements. The cumulative annual CO 2 mass emissions from the Part 75 report must be converted from short tons to metric tons and included in the annual Part 98 GHG emissions report. The electronic data system for generating the GHG emissions reports is currently under development.

Example---Applying Part 98 to a Typical Electricity Generating Facility To apply Part 98 at a typical electricity generating facility: Determine the boundaries of the facility---refer to the definition in 98.6 If there are any Acid Rain or RGGI units at the facility, it is automatically subject to Part 98. Otherwise, use the calculation methods in Part 98 to determine whether the facilitys annual GHG emissions exceed 25,000 metric tons of CO 2 e. For the Acid Rain and/or RGGI units (if any) calculate and report CO 2, N 2 O, and CH 4 emissions according to the requirements of Subpart D For other stationary fuel combustion sources at the facility (e.g., auxiliary boilers, combustion turbines, space heaters, etc.), calculate and report CO 2, N 2 O, and CH 4 emissions according to the requirements of Subpart C Determine whether facility also triggers the natural gas supplier reporting requirements of Subpart NN (See 98.2(a)(4))

27 Additional Information –Preamble and rule –FAQs –Technical background documents on source categories –Comment response documents –Technical assistance materials

Questions?