# Rulemaking **for Greenhouse Gas Emissions** 

**from Electric Utility Steam Generating Units** 
**Ap ril**  **12, 2011 Ar** **iel Rios North**  **Room 1332 POC: Mary Johnson**  

## E.O. **13132 “Federalism”**  **Consultation Meeting** 

# Agenda

► Background ► Power Sector: A Major Share of U.S. GHG Emissions ► Summary of Listening Sessions ► Section 111 Overview ► Section 111 versus Section 112 ► Definition of EGU ► Affected Facilities ► CO 2 Emissions Control Technologies

Emissions Control Technologies ► Key Issues ► State/Local Implementation ► Questions/Comments ► Appendix A ► Wh at are Greenhouse Gases? ► GHG Emissions Across Sectors ► GHG Emissions
– Energy Sector ► GHG Emissions
– Electricity Generation ► Appendix B
– State & Local Governments Potentially Subject to Regulation

**2**

# Background ► 

## On December 15, 2009 (74 FR 66496), EPA published a notice indicating that the EPA Administrator found that the current and projected atmospheric concentrations of GHGs are reasonably anticipated to endanger the public health and welfare of current and future generations (Endangerment Finding).
► 

## On December 23, 2010, EPA announced that it entered into a proposed settlement agreement to issue rules that will address GHG emissions from certain fossil fuel -fired EGUs. ► 

## Rules would establish new source performance standards (NSPS) for new and modified natural gas- , oil - , and coal -fired EGUs and emission guidelines for existing natural gas- , oil - , and coal -fired EGUs. ► 

## Under the agreement, EPA commits to issuing proposed regulations by July 26, 2011 and final regulations by May 26, 2012. ► 

## Agreement addresses, in part, EPA’s September 2007 remand of its February 2006 final decision not to set GHG standards for boilers
. **3**

# Power Sector: **A Major Share of U.S. GHG Emissions**

**2.6 Billion To**  **ns 40%**  

## Carbon Dioxide (CO **2**

## ), 2008 **6.5 Billion T**

**ons**

**Electric Po** **wer Other**  **Sectors**

► 

## See Appendix A for additional details

**4**



### 3.9 Billion **To ns**  **60% Other** 

**Sectors**

Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 -2008 (2010) (CO 2 ) “Other” sources include transportation, other mobile sources, and industrial sources

# Summary of Listening **Sessions**

► 

## Electric Power Industry ► 

### Allow for fleet wide averaging ► 

### Give credit for replacement of older less efficient generation ► 

## Coalition Groups ► 

### Allow for State programs to be deemed equivalent ► 

### Provide market- based flexibility ► 

### Recognize early action ► 

## State and Tribal Representatives ► 

### Allow for State programs to be deemed equivalent ► 

### Reward the very best possible systems available ► 

### Take a multi - pollutant approach ► 

## Environmental and Environmental Justice ► 

### Allow for State programs to be deemed equivalent ► 

### Recognize environmental benefit of non -emitting technologies ► 

### No special considerations for biomass ► 

### Aggressive GHG approach will reduce other pollutants as well **5**

# Section **111 Overview**
► 

## NSPS implement CAA section 111(b) and are issued for categories of sources which cause, or contribute significantly to, air pollution wh ich may reasonably be anticipated to endanger public health or welfare. ► 

### NSPS affect new and modified sources. ► 

### New sources are those for which construction or modification is commenced after the publication of proposed regulations. ► 

### Modification is any physical change in, or change in the method of operation of, a source which increases the amount of any air pollutant emitted by the source or which results in the emission of any air pollutant not previously emitted. Exempt: Routine maintenance, repair, and replacement and increased hours of ► Exempt: Routine maintenance, repair, and replacement and increased operation ► 

### NSPS reflect the degree of emission limitation achievable through application of the best system of emission reduction which, taking into consideration the cost of achieving such reduction, any non -air quality health and environmental impact, and energy requirements, the Administrator determines has been adequately demonstrated. ► 

### Level of control is referred to as best demonstrated technology (BDT). ► 

### NSPS does not require installation and operation of any particular technological system of continuous emission reduction (except as authorized under CAA section 111(h)).

**6**

# Section **111 Overview (cont.)**

► 

## Emission guidelines are established for existing sources under CAA section 111(d) for source categories that emit pollutants not regulated under other parts of the CAA and to which an NSPS would apply if such existing source we re a new

source. ► 

### Guidelines include targets based on demonstrated controls, emission reductions, costs and expected timeframes for installation and compliance. ► 

### Guidelines can be less stringent than the requirements for new sources. ► 

### States use the emission guidelines to develop plans for reducing emissions from existing sources. ► 

### EPA has the authorities to prescribe a plan for a State in cases where the State fails to submit a satisfactory plan and to enforce the provisions of a plan in cases where the State fails to enforce them. ► 

### In applying a standard of performance to any particular source under a State implementation plan or in promulgating a standard of performance under a plan prescribed by EPA, the remaining useful life of the existing source(s) can be considered. ► 

## EPA may distinguish among classes, types, and sizes within categories of sources for the purpose of establishing standards.

**7**

# Section **111 Overview (cont.)**

► 

## If EPA determines that it is not feasible to prescribe or enforce a standard of performance, CAA section 111(h) authorizes promulgation of a design, equipment, work practice, or operational standard, or combination thereof, wh ich reflects the best technological system of continuous emission reduction which (taking into consideration the cost of achieving such emission reduction, and any non -air quality health and environmental impact and energy requirements) EPA determines has been adequately demonstrated. ► 

### “Not feasible to prescribe or enforce a standard of performance” means any situation in which the Administrator determines that: ► 

### a pollutant or pollutants cannot be emitted through a conveyance designed and constructed to emit or capture such pollutant, or that any requirement for, or use of, such a conveyance would be inconsistent with any Federal, State, or local law, or ► 

### the application of measurement methodology to a particular class of sources is not practicable due to technological or economic limitations. ► 

### Believe there wouldn’t be a basis for using this authority in the proposed rulemaking for GHG emissions from EGUs

**8**

# Section **111 versus Section 112**

► 

## Technology basis of standards ► 

## CAA section 111 standards are based on BDT ► 

## CAA section 112 standards are based on maximum achievable control technology (MACT)
– very prescriptive ► 

## Other considerations ► 

## Under CAA section 111, the cost of achieving reductions, any non -air quality health and environmental impacts, and energy requirements are considered in determining BDT ► 

## Under CAA section 112, costs and other impacts can only be considered wh en regulating beyond the minimum MACT level (the MACT floor) ► 

## CAA section 111(d) standards developed by EPA do not directly impact existing sources. States use the standards as guidelines in establishing implementation plans with standards of performance that apply to those sources.

**9**

# Definition **of EGU**

► 

## The regulations would apply to each EGU capable of combusting more than 250 million British thermal units per hour (MMBtu/hr) heat input of fossil fuel. ► 

## Electric utility steam generating unit means any steam electric generating unit that is constructed for the purpose of supplying more than one -third of its potential electric output capacity and more than

of its potential electric capacity and more 25 megawatts electric (MWe) output to any utility power distribution system for sale. ► 

## Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.

**10**

# Affected **Facilities**

Co al, 48%

Nat ural Gas, 21% No n Hydro Renewab les, 3% Hy dr o, 6% Nuc lear, 20% Other, 1% ► 

## Approximately 1,525 EGUs at 605 facilities ► 

## Approximately 1,200 coal -fired boilers at 450 facilities in 44 States and Puerto Rico ► 

## Coal -fired EGUs include units that burn coal, coal refuse, or a synthetic gas derived from coal either exclusively, in any combination together, or in any combination wi th other supplemental fuels (e.g., petroleum coke, tire-derived fuels).
Oil, 1% ► 

### Bituminous coal ~ 50% of coal generation ► 

### Subbituminous ~45% of coal generation ► 

### Lignite ~ 5% of coal generation ► 

## Approximately 48 percent of nationwide net generation ► 

## Approximately 150 oil -fired boilers at 75 facilities, mostly in Northeast, Midwest, California, Florida, and Hawaii ► 

## Approximately 1 percent of nationwide net generation **11**

# Affected **Facilities (cont.)** ► 

## Approximately 175 gas -fired boilers at 80 facilities, mostly in Midwest, California, Louisiana, and Texas ► 

## Approximately 21 percent of nationwide net generation ► 

## Are not subject to the NESHAP for EGUs ► 

## The regulations would apply to integrated gasification combined cycle (IGCC, i.e , “coal gasification”) EGUs. ► 

## Coal is “gasified” in a high - pressure, high -temperature gasifier wi th a limited supply of either oxygen or air to produce synthetic gas (syngas ). ► 

## The syngas is cooled, cleaned, and fired in a gas (combustion) turbine. ► 

## The hot exhaust from the combustion turbine passes through a heat recovery steam generator (HRSG, i.e., boiler) where it produces steam that drives a steam turbine. ► 

## Electric power is produced from both the combustion and steam turbinegenerators. ► 

## There are two IGCC plants currently operating in the U.S. ► 

### Duke Energy Wabash River Power Station in Indiana (operation began in 1995) ► 

### Tampa Electric Company Polk Power Station in Florida (operation began in 1996) **12**

# Affected **Facilities (cont.)** ► 

## The regulations would not apply to stationary combustion turbines (combined cycle gas turbines or simple cycle gas turbines). ► 

## In a combined cycle gas turbine plant, a gas turbine generates electricity and the waste heat is used to make steam to generate additional electricity via a steam turbine. ► 

### More efficient method of generating electricity ► 

### Used by most new gas power plants in North America and Europe ► 

## In a simple cycle gas turbine plant, there is no heat recovery. ► 

### Have the ability to be turned on and off within minutes ► 

### Usually used as peaking power plants because they are less efficient ► 

## Industry includes investor- owned, publicly-owned and rural cooperative EGUs. ► 

## State/local jurisdictions identified as potentially impacted by the Toxics Rule would also be potentially impacted by the GHG rulemaking. ► 

## Jurisdictions with gas-fired EGUs also would be potentially impacted. ► 

## 123 State/local jurisdictions are estimated to own EGUs that may be affected by this action. ► 

## See Appendix B for list of potentially impacted State/local jurisdictions

**13**

# Power **Plants Likely Covered by the EGU**  **GHG Rule** 

**Source:** National Electric Energy Data System (NEEDS 4.10) (EPA, December 2010) **Note:** This map displays facilities that are included in the NEEDS 4.10 data base and that contain at least one coal, oil or gas
-fired steam generating unit that generates more than 25 megawatts of power. This includes coal
-fired units that burn petroleum coke and that turn coal into gas before burning (using integrated gasification combined cycle or IGCC). NEEDS reflects available capacity on
line by the end of 2011; this includes committed new builds and committed retirements of old units. Only steam boilers are covered by this rule. In areas with a dense concentration of facilities, the facilities on the map may overlap and some may be impossible to see. American Indian Reservations / Federally Recognized Tribal Entities shown were provided by the US DOI, BIA, and GDSC; they are not a legal representation of reservation boundaries. **14**

# CO **2** 

# Emissions Control Technologies

► 

## General types of control measures for CO 2 

## emissions:
► 

## Energy efficiency ► 

### Reduce the amount of fuel used by improving the efficiency of the electrical generation process ► 

## Post-combustion ► 

### Separate the CO 2 

### for long -term storage using carbon capture technology ► 

## Other measures ► 

### Co-firing ► 

### Fuel switching ► 

### Combined heat and power

**15**

# Efficiency**I mprovements**  **for Existing EGUs**
**Efficiency**

**Improvement Te**  **chnology Description**  **Efficiency Increase**  Replace/Upgrade Burners Replacement or upgrade of older, incorrectly sized, or mechanically deteriorated burners and inoperable dampers, broken registers, or clogged nozzles Up to ~5% Improved combustion Tu ning of combustion system to optimum settings and use/adjustment of instrumentation (e.g., temperature sensor, oxygen monitor, excess air setting, CO monitor) ~0.5 to 3% Heat recovery Use of heat from boiler exhaust to preheat incoming Up to ~6%



## Efficiency Improv**ements for Existing EGUs** 

**16** Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Industrial, Commercial, and Institutional Boilers, October 2010 Heat recovery Use of heat from boiler exhaust to preheat incoming

combustion air or to preheat boiler feedwater Up to ~6% Reduce air leakages Maintenance of boiler system to minimize air leakage through routine maintenance procedures and monitoring of indicators of air leakage (e.g., oxygen level, fuel consumption, gas temperature) ~1.5 to 3% Capture energy from boiler blowdown Recovery of waste heat (low- pressure steam) from

blowdown ~1 to 2% Reduce slagging & fouling of heat transfer surfaces Operation within boiler ’sd esign parameters (including fuel quality), use of cleaning system (soot blower - air or steam is used to periodically remove deposition on boiler walls and tubes), and/or fuel treatment (modifies ash characteristics) 1% to 3%

# Efficiency**I mprovements**  **for Existing EGUs ( cont.)** 

**Efficiency**

**Improvement Te**  **chnology Description**  **Reported Efficiency**  **Increase** Combustion Control Optimization Adjustment of coal and air flow to optimize steam

production for the generator 0.15 to 0.84% Cooling System Heat Loss Recovery Recovery of a portion of the heat loss from cooling water

exiting the steam condenser 0.2 to 1% 

## Efficiency Improv**ements for Existing Coal**  **- Fired EGUs** 

**17** Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal

-Fired Electric Generating Units, October 2010 Recovery exiting the steam condenser Flue Gas Heat Recovery Recovery of the heat lost when flue gas is sprayed with flue gas desulfurization (FGD) reagent slurry and cools 0.3 to 1.5% Low- rank Coal Drying Drying of subbituminous and lignite coals using waste heat from flue gas and/or cooling water systems 0.1 to 1.7% Sootblower Optimization I ntermittent injection of high velocity gets of steam or air to clean coal ash deposits from boiler tube surfaces to maintain adequate heat transfer 0.1 to 0.65% Steam Tu rbine Design M aintain mechanical and physical condition of steam turbine through use of efficiently designed turbine blades and steam seals 0.84 to 2.6%

# Efficiency**I mprovements**  **for New EGUs**

► 

## Efficiency improvements for new coal -fired EGUs ► 

### Use of supercritical boilers ► 

### Operate at higher pressures and temperatures ► 

### Start- up times are quicker ► 

### National Energy Technology Laboratory (NETL) analysis shows that supercritical boilers are approximately 2.3% more efficient than subcritical boilers ► 

### Application currently limited to facilities of approximately 200 MWe gross output or more due to the availability of steam turbines that are designed for supercritical steam conditions ► 

### Use of ultra -supercritical boilers ► 

### Operate at even higher pressures and temperatures ► 

### Can potentially operate at efficiencies approaching 50% ► 

### Material degradation can be an issue when firing high -sulfur coal ► 

### Use is prevalent in Denmark, Germany, and Japan ► 

### First ultra -supercritical EGU in U.S.
– Southwest Electric Power Company’s John W. Turk, Jr. Power Station near Texarkana, AR ► 

### 600 MWe pulverized coal -fired EGU ► 

### Will burn Powder River Basin subbituminous coal ► 

### Scheduled to begin operation in late 2012 **18** Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal -Fired Electric Generating Units, October 2010

# Efficiency**I mprovements**  **for New EGUs (cont.)** 

► 

### Use of IGCC technology ► 

### Electric output is generated by both the combustion turbine and the steam turbine ► 

### NETL analysis of three coal gasification processes shows net efficiencies of 38.2% to 41.1% ► 

### Coal drying ► 

### Several advanced pre -combustion coal drying technologies are or nearly are Several advanced pre combustion coal drying technologies are or nearly commercially available ► 

### Reported net gains in overall efficiency of 2% to 4% ► 

### Boiler feedwater heating ► 

### Use of heat sources other than the steam turbine to heat feedwater ► 

### Increases the output of the steam cycle and potentially lowers GHG emissions

**19** Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal - Fired Electric Generating Units, October 2010

# Technology**assessment** 

# Carbon Capture & Storage

► 

## There are no insurmountable technological, legal, institutional, or other barriers that prevent carbon capture and storage (CCS) from playing a role in reducing GHG emissions. ► 

### Current technologies could be used to capture CO 2 

### from new and existing fossil energy power plants; however they are not ready for widespread implementation primarily because they have not been demonstrated at the scale necessary to establish confidence for power plant application. ► 

### CCS retrofits could face challenges at some existing plants due to space and configurational limitations or proximity to a CO 2 

### pipeline or geologic storage. ► 

## Existing Federal programs are being used to deploy at least five to ten largescale integrated CCS projects expected to be online by 2016. ► 

## Federal research, development and demonstration efforts are focused on reducing costs of CCS to facilitate widespread cost-effective deployment after 2020. ► 

### Approximately 70
–90% of CCS cost is associated with capture and compression. ► 

### The cost and performance of CCS technologies will evolve with longer-term testing.
**20** Source: Report of the Interagency Task Force on Carbon Capture and Storage, August 2010

# Key **Questions**

► 

## What should emission limits for new sources be based on?
► 

## What should emission limits for modified sources be based on?
► 

## What should emission limits for existing sources be based on?
► 

## What regulatory mechanisms should be used to get reductions?
► 

## How should State equivalency with guidelines be addressed?

**21**

# State/Local Implementation

► 

## Envision implementation of the guidelines as similar to what State/local jurisdictions are already used to under the SIP process
► 

## This includes: ► 

## Development of a State plan consistent with the emissions guidelines ► 

## Implementation of that plan, including permitting and enforcement

**22**

# Questions?

**Project Lead: Christian**  **Fellner**

**919 -** **541 -** **4003 fellner** **.christian@epa.gov Federalism**  **Contacts: Mary**  **J ohnson**  **919 -** **541 -** **5025 johnson.mary@epa.gov**  **An drew** **Hanson Project Ov** **ersight: Bob W** **ay land** 

**919 -** **541 -**  **1045 wa** **yl and.robertj@epa.gov** 

**23** 

### An **drew Hanson**  **202 -** **564 -** **3664 Hanson.andrew** **@epa.gov**

**Kev in**  **Culligan 202**  **- 564**  **- 061**  **1 culligan.kev** **in@epa.gov**

# Appendix A

# What **are Greenhouse Gases?** 

► 

## GHGs are chemical compounds found in the Earth’s atmosphere ► 

## They allow s unlight to enter the atmosphere freely. ► 

## When sunlight strikes the Earth’s surface, some of it is re- radiated back towards space as heat (infrared radiation). ► 

## GHGs absorb the infrared radiation and trap the heat in the atmosphere. ► 

## Over time, if atmospheric concentrations of GHGs remain relatively stable, the amount of energy sent from the sun to the Earth’s surface should be about the same as the amount of energy radiated back into space, leaving the temperature of the Earth’s surface roughly constant. ► 

## Some GHGs occur naturally and are emitted to the atmosphere through natural processes and human activities (e.g., carbon dioxide, methane, and nitrous oxide). ► 

## Other GHGs are created and emitted solely through human activities (e.g., fluorinated gases).

**A -**  **1**

# What **are Greenhouse Gases? (cont.)** 

► 

## Principal GHGs that enter the atmosphere due to human activities: ► 

### Carbon Dioxide (CO2) ► Burning of fossil fuels (oil, natural gas, and coal), solid waste, trees and wood products ► Chemical reactions (e.g., manufacture of cement, steel, aluminum) ► 

### Methane (CH4) ► Production and transport of coal, natural gas, and oil ► Livestock and other agricultural practices ► Decay of organic waste in municipal solid waste landfills ► 

### Nitrous Oxide (N2O) ► Combustion of fossil fuels and solid waste ► Agricultural and industrial activities ► 

### Fluorinated Gases ► Hydrofluorocarbon (HFC), perfluorocarbon (PFC), and sulfur hexafluoride (SF6) ► Typically emitted in smaller quantities, but are potent GHGs ► Synthetic GHGs emitted from a variety of industrial processes ► Sometimes used as substitutes for ozone-depleting substances ► Chlorofluorocarbons (CFCs) - used as refrigerants, solvents, and foam blowing agents ► Hydrochlorofluorocarbons **(** HCFCs) - used to replace CFCs due to lower ozone depleting potential ► Halons - used as fire extinguishing agent **A -** **2**

# GHG **Emissions Across Sectors**

**Gas/Sour ce**  **Ty pe**  **1990 2000**  **2009 CO**  **2 5100.2**  **5976.2 5508.1**  Fossil Fuel Combustion 4741.2 5597.7 5212.0 Non - Energy Use of Fuels 116.2 142.5 122.1 Iron and Steel Production & Metallurgical Coke Production 99.5 85.9 42.6 Natural Gas Systems 37.6 29.9 32.2 Cement Production 33.3 41.2 29.4 Incineration of Waste 8 11.1 12.3 

## GHG Emissions in U.S. (million metric tons of CO 2 equivalent)

**A -** **3** Incineration of Waste 8 11.1 12.3 Amonia Production and Urea Consumption 16.8 16.4 11.8 Lime Production 11.5 14.1 11.2 Cropland remaining Cropland 7.1 7.5 7.8 Limestone and Dolomite Use 5.1 5.1 7.6 Soda Ash Production and Consumption 4.1 4.2 4.3 Aluminum Production 6.8 6.1 3.0 Petrochemical Production 3.3 4.5 2.7 Carbon Dioxide Consumption 1.4 1.4 1.8 Ferroalloy Production 2.2 1.9 1.6 Titanium Dioxide Production 1.2 1.8 1.5 Wetlands remaining Wetlands 1 1.2 1.1 Phosphoric Acid Production 1.5 1.4 1 Source: Table ES -2 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990 -2009, February 1 5, 2011

# GHG **Emissions Across Sectors (cont.)**

**Gas/Sour ce**  **Ty pe**  **1990 2000**  **2009 CH**  **4 674.9**  **659.9 686.5**  Natural Gas Systems 189.8 209.3 221.2 Enteric Fermentation 132.1 136.5 139.8 Landfills 147.4 111.7 117.5 Coal Mining 84.1 60.4 71.0 Manure Management 31.7 42.4 49.5 

## GHG Emissions in U.S. (cont.) (million metric tons of CO 2 equivalent)

**A -** **4** Manure Management 31.7 42.4 49.5 Petroleum Systems 35.4 31.5 30.9 Wa stewater Treatment 23.5 25.2 24.5 Forest Land remaining Forest Land 3.2 14.3 7.8 Rice Cultivation 7.1 7.5 7.3 Stationary Combustion 7.4 6.6 6.2 Abandoned Underground Coal Mines 6.0 7.4 5.5 Mobile Combustion 4.7 3.4 2.2 Iron and Steel Production & Metallurgical Coke Production 1.0 0.9 0.4 Source: Table ES -2 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990 -2009, February 1 5, 2011

# GHG **Emissions Across Sectors (cont.)**
**Gas/Sour ce**  **Ty pe**  **1990 2000**  **2009 N**  **2 O**  **315.2 341.0**  **299.5** Agricultural Soil Management 197.8 206.8 204.6 Mobile Combustion 43.9 53.2 27.8 Manure Management 14.5 17.1 17.9 Nitric Acid Production 17.7 19.4 14.6 Stationary Combustion 12.8 14.6 12.8 Forest Land remaining Forest Land 2.7 12.1 6.7 Wa stewater Treatment 3.7 4.5 5.0 N2O from Product Uses 4.4 4.9 4.4 

### GHG Emissions in U.S. (cont.) (million metric tons of CO 2 equivalent)

**A -** **5** N2O from Product Uses 4.4 4.9 4.4 Adipic Acid Production 15.8 5.5 1.9 **HFCs 36.9**  **103.2 125.0**  Substitution of Ozone Depleting Substances 0.3 74.3 119.3 HCFC- 22 Production 36.4 28.6 5.4 Semiconductor Manufacture 0.2 0.3 0.3 **PFCs 20.8**  **13.5 5.6**  Semiconductor Manufacture 18.5 8.6 1.6 Aluminum Production **SF 6**  **34.4 20.1**  **14.8** Electrical Transmission and Distribution 28.4 16 12.8 Magnesium Production and Processing 5.4 3.0 1.1 Semiconductor Manufacture 0.5 1.1 1.0 Source: Table ES -2 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990 -2009, February 1 5, 2011

# GHG **Emissions -**  **Energy Sector Energy Sector GHG Emissions**  (million metric tons of CO 2 equivalent) **Gas/Source Ty** **pe 1990**  **2000 2009**  **CO 2**  **4903.6 5781.7**  **5379.0** Fo ssil Fuel Combustion 4741.2 5597.7 5212.0 Electricity Generation 1820.8 2296.9 2154.0 Transportation 1485.9 1809.5 1718.9 Industrial 849.3 853.9 738.4

Source: Table 2 -4 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990 -2009, February 1 5, 2011

**A -** **6** Industrial 849.3 853.9 738.4 Residential 338.3 370.7 340.2 Commercial 219.0 230.8 218.8 U. S. T erritories 27.9 35.9 41.7 Non - Energy Use of Fuels 116.2 142.5 122.1 Natural Gas Systems 37.6 29.9 32.2 Incineration of Waste 8.0 11.1 12.3 Petroleum Systems 0.6 0.5 0.5

# GHG Emissions **- Energy Sector (cont.)**  **Energy Sector GHG Emissions (cont.)** (million metric tons of CO 2 equivalent) **Gas/Source Ty** **pe 1990**  **2000 2009**  **CH 4**  **327.4 318.6**  **337.0** Natural Gas Systems 189.8 209.3 221.2 Coal Mining 84.1 60.4 71.0 Petroleum Systems 35.4 31.5 30.9 Stationary Combustion 7.4 6.6 6.2

Source: Table 2 -4 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990 -2009, February 1 5, 2011

**A -** **7** Stationary Combustion 7.4 6.6 6.2 Abandoned Underground Coal Mines 6.0 7.4 5.5 Mobile Combustion 4.7 3.4 2.2 Incineration of Waste <0.05 <0.05 <0.05 **N 2** **O 57.2**  **68.1 41.0**  Mobile Combustion 43.9 53.2 27.8 Stationary Combustion 12.8 14.6 12.8 Incineration of Waste 0.5 0.4 0.4

# GHG Emissions **– Electricity Generation** 

**Gas/Source Ty** **pe 1990**  **2000 2009**  **CO 2**  Fo ssil Fuel Combustion 1820.8 2296.9 2154 Coal 1547.6 1927.4 1747.6 Natural Gas 175.3 280.8 373.1 Petroleum 97.5 88.4 32.9 

## Electricity Generation **- Related GHG Emissions** 

(million metric tons of CO 2 equivalent)

Source: Table 2 - 13 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990 -2009, February 1 5, 2011
► CO 2 emissions from fossil fuel combustion are ~99.5% of total GHG emissions from fossil fuel combustion (2009) ► CO 2 emissions from coal -fired combustion are ~81% of total CO 2 emissions from fossil fuel combustion (2009)

**A -** **8**

Petroleum 97.5 88.4 32.9 **CH 4**  Stationary Combustion 0.6 0.7 0.7 **N 2** **O** Stationary Combustion 8.1 10.0 9.0

# Appendix B

# State & Local Governments Potentially **Subject to Regulation** 

**tings Utilities (NE)** Alexandria, LA (City of) Conway Corp Hastings Utilities (NE) Algona Municipal Utilities Coon Rapids, IA (City of) Heartland Consumers Power District Alta, IA (City of) CPS Energy Henderson Municipal Power & Light American Municipal Power Inc Dalton, GA (City of) Holland Board of Public W orks Ames Municipal Electric System Detroit Public Lighting Holyoke Gas & Electric Dept Anaheim, CA (City of) Dover, DE (City of) Illinois Municipal Electric Agency Atlantic Municipal Utilities Eldridge, IA (City of) Imperial Irrigation District Austin Energy Farmington, NM (City of) Indiana Municipal Power Agency Austin Utilities Florida Municipal Power Agency Intermountain Power Agency Azusa, CA (City of) Fremont Dept of Public Utilities JEA

(City of) Fremont of Public Utilities Bancroft Municipal Utilities Gainesville Regional Utilities Jonesboro Water & Light Banning Electric Division Garland Power & Light Kansas City Board Public Utilities Brownsville Public Utility Board Geneseo Municipal Utilities Kissimmee Utility Authority Bryan Texas Utilities Glendale Water & Power Lafayette Public Power Authority Burbank Water & Power Graettinger Municipal Light Plant Lafayette Utilities System California Dept W ater Resources Grand Haven Light & Power Lakeland Dept of Electric W ater Utilities Cedar Falls (IA) Utilities Grand Island Utilities Lansing Board of Water & Light Coffeyville Municipal Light & Power Grand River Dam Authority Laurens, IA (City of) Colorado Springs Utilities Greenville Electric Utility System Lincoln Electric System Colton Electric Utility Dept Harlan Municipal Utilities Littleton, MA (Town of)

**B -**  **1**

# State & Local Governments Potentially **Subject to Regulation**  **(cont.)**

Los Alamos County New York Power Authority Southern Minnesota Municipal Power Agency Los Angeles Dept of W ater & Power North Attleborough Electric Dept Spencer Municipal Utilities Louisiana Energy & Power Authority North Carolina Eastern Municipal Power Agency Springfield, MO (City of) Lower Colorado River Authority Northern Municipal Power Agency Springfield (IL) W ater Light & Power Dept Lubbock Power & Light Dept Oklahoma Municipal Power Authority Sumner Municipal Light Plant Lyndonville Electric Dept Omaha Public Power District Tallahassee, FL (City of) Manitowoc Public Utilities Orlando Utilities Commission Taunton Municipal Lighting Plant Marquette Board of Light & Power Osceola AR (City of) Terrebonne Parish Consolidated Massachusetts Municipal W holesale Electric Owensboro Municipal Utilities Texas Municipal Power Agency Michigan Public Power Agency Pasadena Water & Power Dept Tipton, IA (City of) Michigan Public Power Agency Pasadena & Power Dept Tipton, IA (City of) Michigan South Central Power Agency Pella Municipal Light & Power Utah Associated Municipal Power System Milford Municipal Utilities Platte River Power Authority Utah Municipal Power Agency Missouri River Energy Services Ponca City, OK (City of) Vero Beach Municipal Utilities Modesto Irrigation District Provo City Corp Waverly Light & Power Montezuma Municipal Utilities Redding Electric Utility Webster City, IA (City of) Morgan City, LA (City of) Richmond Power & Light West Bend, IA (City of) Municipal Electric Authority of Georgia Rochester Dept Public Utilities West Memphis Utility Dept Municipal Energy Agency of Nebraska Salt River Project Winfield, KS (City of) Muscatine Power & W ater Santa Clara, CA (City of) WPPI Energy Nebraska Public Power District Santee Cooper Wyandotte Dept of Municipal Service New Hampton Municipal Light Plant Sikeston Utilities Wyoming Municipal Power Agency

**B -** **2**

# Regulatory **Compliance Obligations for**  **the Utility Industry**

**B -** **3**