EPA’s Proposed GHG Reporting Rule:Oil and Natural Gas Systems

Presented to the Wyoming Pipeline Authority Quarterly Public Meeting

Tuesday, May 19th, 2009Casper, Wyoming

Outline of Presentation

Regulatory backgroundGeneral information on EPA GHG ruleEPA GHG rule specific to Oil and Gas SystemsReview of applicable subpartsMissing dataRecordkeepingTopics for CommentingSummary

How it All Got Started: Massachusetts et al. vs. EPA (April 2007)

Greenhouse gases are “air pollutants”CAA does give the EPA the authority to regulate tailpipe emissions of GHG

GHG fit well within the CAA capacious definition of air pollutant

EPA must consider endangerment(1) Make a positive endangerment finding; (2) Make a negative endangerment finding; or (3) offer a “reasonable explanation as to why it cannot or will not exercise its discretion to determine whether they do.”

**This ruling opened the door to regulation of GHG under Section 202 of CAA**

Draft EPA Endangerment Finding(April 17, 2009)

Endangerment: EPA declared CO2 a danger to public health and welfareCause and Contribute: Emissions from cars contribute to atmospheric levels of GHGsNational GHG plan vs. regulate under existing lawsPublic comment period: June 23, 2009

**Likely increase pressure on Congress to adopt federal GHG regulations.**

The First Step:EPA GHG Proposed Reporting Rule

As required by the FY2008 Consolidated Appropriations ActEPA Draft Rule March 10, 2009, published in Federal Register on April 10, 2009Comments on proposed rule June 9, 2009EPA Target for Final Rule: Late Fall 2009EPA estimates 13,000 affected facilities (large emitters) ~85 % of GHG’s Includes energy intensive sectors: cement production, iron and steel production, electricity generation, refineries, and oil and natural gas (NG) Systems

The First Step:EPA GHG Proposed Reporting Rule

Annual monitoring and reporting of GHGFacility Level**First Report: 2011 reporting of 2010 emissionsCertification: GHG report shall be submitted, signed and certified by a designated representativePenalties (CAA): Up to $32,500 per day per violation, Criminal penalties are also possibleEPA estimated cost to comply (all private sectors): ~$160 million for the first year, ~$127 million in the following year ($0.04 per tonne CO2e)

Key Definition:

**Facility –“any physical property, plant, building, structure, source, or stationary equipment located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control.”

The Specifics:Oil and Natural Gas Systems

Must report if total GHG emissions ≥ 25,000 tonnes CO2e/yearGasses covered: CO2, CH4, N2OOnce in always inIncludes:

Offshore production facilities

Onshore gas processing facilities

Onshore gas transmission compressor facilities

Gas storage facilities

LNG storage facilities and import/export facilities

**Notable exclusions (for now): Onshore petroleum and natural gas production and pipeline segments for NG and crude, NG distribution, crude oil distribution

The Nuts and Bolts:Applicable Subparts

W - Oil and NG Systems (fugitives)A - General ProvisionsC - Combustion SourcesNN - Suppliers of NG and NGLsPP - Suppliers of CO2

And Others…

Key Definition:

Fugitive Emissions (IPCC 2006) –“Unintentional equipment emissions and intentional or designed releases of CH4 and/or CO2-containing NG or hydrocarbon gas from emission sources including but not limited to:

Open ended linesEquipment connections or seals to the atmosphereCombustion of NG in flares”

Subpart W: Oil and Natural Gas Systems

Fugitive and process emissions only (24 identified emission source types)

Required to detect emissionsRequired to calculate emissions:

Using direct measurementEngineering measurements

(AGR, NG driven pneumatic pumps, NG driven pneumatic manual valve actuator devices, NG driven pneumatic valve bleed devices, blowdown vent stacks, dehydrator vent stacks)

Engineering/direct measurement (flare stacks, storage tanks, compressor wet seal degassing vents)

Subpart W: Detection and Calculation

Annual “leak detection” for all sources – must be comprehensive

Detection: Optical (infrared or laser), or OVA/TVA type analyzers allowed

Quantification: Leak measurement required for subset of components – generally all “traditional” fugitives

“High-flow sampler required unless they cannot capture the total leak

Calibrated bags (required in some instances) – 3 runs required

Route to stack/pipe and use velocity meter

Subpart W: Reporting

Fugitive emissions aggregated for each source type (ex. emissions from all pumps combined)Quantity of CO2 captured for use and the end use, if knownFugitive emissions from standby sources would be separately identifiedActivity data for each aggregate source type level

Subpart C: Combustion Sources

Stationary fuel combustion sources are devices that combust any solid, liquid, or gaseous fuel to:

Produce electricity, steam, useful heat, or energy for industrial, commercial, or institutional useReduce the volume of waste by removing combustible matter Includes: boilers, combustion turbines, engines, incinerators, and process heaters, etc. (units)

Excludes: portable equipment or generating units that have been designated as emergency generators (based on permit), and flares

Report total CO2, CH4, and N2O emissions from each fuel combustion unit and for each type of fuel combusted

Report CO2 emissions from sorbent use in air pollution control equipment

Subpart C:Calculation and Monitoring Methodology

Calculation methodology - a four-tiered approach (subject to restrictions based on unit size and fuel).

Tier 1: Emission factor that is multiplied by annual fuel use and a default HHV/LHV Tier 2: An emission factor that is multiplied by annual fuel use and a measured HHV/LHVTier 3: Annual fuel use and measured carbon contentTier 4: Continuous emissions monitoring systems (CEMS)

Subpart C: Calculation Hierarchy

Is the fuel’s HHV determined on a ≥ monthly basis? Note: Data

may be provided by a fuel provider?

DATA REQUIREMENTS

- Tier 1 + measured carbon content

Is the max. rated heat input capacity > 250 MMBtu/hr or

does the unit have a max. rated input capacity of 250 tons/day of municipal solid waste (MSW)?

Does the unit have both stack gas volumetric flow rate and CO2

concentration monitors?

Are default HHV and CO2 emissions factors available in

Table C-1 fro the fuel combusted?

Does the unit have a CEMS that is required, certified, and undergoes

periodic quality assurance testing?

Are solid fossil fuel or MSW the primary or secondary fuel

sources and has the unit operated more than 1000

hrs/year since 2005?

Is a default CO2 emission factor available in Tables

C-1 or C-2 for the fuel combusted?

Tier 1

Tier 3

Tier 3

Tier 2

Tier 4

NO

NO

NO

NO

NO

NO

YES

YES

YES

YES YES YES

NO

YES

Tier 1

Tier 4

Tier 2

Tier 3

- Annual Fuel Consumption

- Tier 1 + measured HHV

- CO2 CEMS data

Subpart C: Reporting

Annual mass emissions for each GHG for each unitSome emissions can be aggregated:

Small units that have a combined max. heat input capacity of ≤ 250 MMBTU/hr Units that share a common stack and use CEMSUnits that combust the same fuel and is metered through the same pipe

Measured inputs Certification tests and major QA tests for CEMS

Subpart NN: Suppliers of NG and NGLs

“suppliers of natural gas and natural gas liquids would report the emissions that would result from the complete combustion or oxidation of the products that they place in commerce.”

Suppliers include: NG processing plants: CO2 emissions from the complete combustion or oxidation of the annual quantities of propane, butane, ethane, isobutene, and bulk NGLs sold or delivered for use off site

Local distribution companies: Report CO2 emissions from the complete combustion or oxidation of the annual volume of natural gas provided

Calculations: Uses either a measured or default CO2 emissions factor

Reporting: Annual volume of natural gas received for delivery to various end users and the associated GHG emissions.

Subpart PP: Suppliers of CO2

Facilities with production process units that capture and supply CO2 for commercial applications Facilities with CO2 production wells Importers of bulk CO2, if total combined imports of CO2 and other GHGs exceed 25,000 tonnes of CO2e/year Exporters of bulk CO2, if total combined exports of CO2 and other GHGs exceed 25,000 tonnes CO2e/year

Exclusions: entities that store CO2 through geologic sequestration or above ground storage; use CO2 in enhanced oil and gas recovery; transport or distribute CO2; purify, compress, or process CO2; or import or export CO2 in equipment.

Subpart PP: Reporting and Monitoring

Monitoring: Suppliers would calculate emissions quarterly by measuring the mass flow of gas and multiplying by the CO2composition of the gas

Reporting: Total annual mass of CO2

The weighted average composition of the CO2 stream captured, extracted, or transferredAnnual amounts of CO2transferred to the appropriate end-use applications

Missing Data (all subparts)

Subpart C: Allows for averaging, other methodology outlined in the ruleSubpart W: If data is lost or there is an error, data must be collected againSubpart NN: Allows for substitution of data using the methodology outlined in the ruleSubpart PP: Allows for substitution of data using the methodology outlined in the rule

Record Keeping (5 years) (all subparts)List of units, operations, processes, and activitiesThe data used to calculate GHG from each emission source for each subpartDocumentation of data collection processGHG methodology and calculationsName of personnelANNUAL GHG emissions reportMissing data computationA written QAPPLog book documenting procedural instrumentation and/or instrumentation readingsAdditional information applicable to each subpart

Topics Suggested for Commenting….

3rd party verification vs. self-certificationTime frames alternatives for 2010/2011 reporting option:

2011 on “best available data” basis2012 for 2011

Reporting of “indirect” emissions (scope 2)

“Source specific” CH4 and N2O factors for combustion sources

Use of a “basin” approach for onshore petroleum and NG production

Methodology for measuring and quantifying fugitive emissions

Confidential Business Information

Definition of facility and fugitives

Summary: GHG Reporting Rule

Massive Rule (~285 pages in Federal Register and 42 subparts)Does not trump state and/or regional rules already in placeFinal rule likely in November 2009 –Effective January 1, 2010First annual report is due March 2011Comment period is open until June 9, 2009Applicable subparts: W, A, C, PP, NN, and othersSubmit report and supporting documentation to EPA – All will be publicMore to come…..Most likely first step in mandatory regulation of GHG. Ex. Cap and trade? Carbon tax?