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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