Post on 11-Feb-2016
description
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United States Greenhouse Gas Regulatory Reporting
Terri Shires, URS Corporation
IPIECA GHG Reporting Workshop
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OverviewStart locally and expand nationally:
• California• Western Climate Initiative• U.S. Environmental Protection Agency
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California’s Climate Plan Global Warming Solutions Act (AB 32)
• Reduce GHG emissions to 1990 levels by 2020– Approximately 15% reduction from 2010 emissions
Began January 1, 2008, first reports due June 1, 2009• Mandatory facility level reporting; optional entity level reporting• CO2, CH4, N2O, SF6, HFCs• Initial process and protocols largely based on CCAR
Who must report? • Any facility emitting >25,000 metric tonnes CO2/year from
stationary combustion • Petroleum refineries, hydrogen plants, cogeneration facilities
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California: Recent ActivityNovember 2010 ballot proposition that would
have suspended that state's recent climate change legislation failed
December 16, 2010, the CARB approved revisions to the California GHG reporting regulation • To support a GHG gas cap-and-trade program• To harmonize with U.S. EPA reporting requirements
– Included reporting requirements for upstream oil and gas operations.
Revised regulation is expected to be effective for reporting in 2012
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California: Cap & Trade
Phase 1: 2012-2014Cap declines 2%/yrElectricity generation
(including imports) and large industrial (including refining)
Phase 2: 2015-2020Fuel distributors
• Transportation fuels, natural gas, other fuels
Cap declines 3%/yr
Cumulative reductions needed between 2012 and 2020: 273 million metric tons CO2e
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Western Climate Initiative
Initiated in 2007Regional GHG
emissions target of 15 percent below 2005 levels by 2020
Cap & Trade: 1st compliance period 2012• 25,000 metric tons CO2e
threshold
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Western Climate Initiative (WCI)Mandatory Reporting beginning 2011 for
2010• July 2009, WCI published the Essential
Requirements for Mandatory GHG Reporting – Initially 10,000 metric tons CO2e threshold
• Harmonized with EPA MRR in fall 2010• Continuing to develop reporting protocols
– Oil and gas production, natural gas processing, and natural gas transmission and distribution
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EPA’s Mandatory Reporting of Greenhouse Gases GHG Mandatory Reporting Rule Program (GHGRP)
40 CFR Part 98• Initially published 10/30/2009; several revisions in 2010• 46 emission source categories• CO2, CH4, N2O, SF6, HFCs, and other fluorinated gases
Purpose: “To Shape Future Climate Change Policy”• Better understand relative emissions of specific industries, and
of individual facilities within those industries• Better understand factors that influence GHG emission rates and
actions facilities could take to reduce emissions Does not require control of GHG
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EPA Applicability and Subparts
Direct Emitters• C – Stationary Fuel
Combustion• W – Petroleum and Natural
Gas Systems• Y – Petroleum refineries
Suppliers• MM – Petroleum Products• NN – Natural Gas and Natural
Gas Liquids • PP – Carbon Dioxide
Other• RR – CO2 Injection and
Sequestration• UU – Injection of CO2
Applicability• Specified facilities (such as refineries) • >25000 MT CO2e per facility
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GHGRP Revisions March 16, 2010 - Minor harmonizing changes to the
general provisions September 22, 2010 - Reporting of corporate parent,
NAICS Code and co-generation information October 28, 2010 – Supplier updates November 30, 2010 – Added new regulated facilities,
including petroleum and natural gas systems December 17, 2010 – Settlement agreement revisions December 27, 2010 – CBI interim final and proposed
amendments
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Facility DefinitionGenerally, a facility is defined as…
• Physical property, plant, building, structure, source, or stationary equipment;
• On contiguous or adjacent properties;• In actual physical contact or separated solely by
public roadway or other public right of way; • Under common ownership or common control
Onshore production – facility is the basinNatural gas distribution – facility is the LDC
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Subpart A - General Provisions
QA/QC requirements • Monitoring plan• Best Available Monitoring Methods (BAMM)
Accuracy requirements for flow measurement
Reporting requirements• Electronic submission format to be specified
by EPA
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Subpart C – Stationary CombustionExclusions:
• Flares (though covered in Subparts W and Y)• Portable equipment (though covered in Subpart W)• Emergency generators and emergency equipment
Calculation methodologies• Tier 4: CEMS• Tier 3: Fuel flow measurement and CC direct
measurement• Tier 2: Company records fuel, measured HHV, default
CO2 EF• Tier 1: Company records fuel, default HHV, default
CO2 EF
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Subpart Y - RefineriesStationary combustion units and each flare Unit specific calculations
• Coke burn-off emissions from each cat cracker, fluid coker, and cat reformer
• Sour gas treatment• Coke Calcining• Asphalt Blowing
Equipment leaks, storage tanks, loading operations, delayed coking units, uncontrolled blowdown systems, and misc. process vents
Non-merchant H2 production
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Subpart W – Petroleum and Natural Gas Systems Offshore petroleum and
natural gas production Onshore petroleum and
natural gas production Onshore natural gas
processing Onshore natural gas
transmission compression
Underground natural gas storage
Liquefied natural gas (LNG) storage
LNG import and export equipment
Natural gas distribution
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Subpart W - Source Types Natural gas pneumatic device
and pneumatic pump venting Well venting for liquids
unloading Gas well venting during well
completions with and w/o hydraulic fracturing
Gas well venting during well workovers with and w/o hydraulic fracturing
Flare stack emissions Storage tanks (production and
transmission) Reciprocating compressor rod
packing venting
Well testing venting and flaring Associated gas venting and
flaring Dehydrator vents Blowdown vent stacks EOR injection pump blowdown Acid gas removal vents EOR hydrocarbon liquids
dissolved CO2 Centrifugal compressor
venting Equipment leaks Combustion equipment
(onshore production and distribution only)
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Suppliers (Subparts MM, NN, PP)Refineries, Importers/Exporters, LDCs,
NGL suppliersSuppliers report annually:
• CO2 emissions that would result from the complete combustion of each product, feedstock used, imports, or exports during the calendar year
• (For Subpart PP) CO2 from complete release of product
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Subparts RR and UUSubpart RR – Geologic Sequestration of CO2
• Complementary to and builds on EPA's Federal Requirements under the Underground Injection Control (UIC) Program for CO2 geologic sequestration wells
• Develop and implement an EPA-approved monitoring, reporting, and verification (MRV) plan
Subpart UU – CO2 Injection (EOR operations)• Reporting CO2 mass balance around injection facility
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Challenges with EPA RuleEPA’s reporting tool is still in development
• Reports are due March 31 for refineriesEPA has not finalized CBI determinations
for reporting data elementsPetition for reconsideration filed for
Subpart W
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Additional Information: Comparison of CA and EPA Programs
CARB AB32 US EPA MRR
Reporting threshold25,000 MTCO2/yr except for electricity generation or cogeneration (2,500 MTCO2/yr)
25,000 MT CO2e /yr except for source categories listed in Subpart A
First reporting year 2008 2010
Reporting deadlines Two tiers: Apr, June March
Verification 3rd party Verifying Bodies trained and approved by ARB
EPA audits
Reporting Via Online Reporting Tool Online Reporting Tool
GHG Monitoring Plan Not required GMP required