1

UNITED STATES

ENVIRONMENTAL PROTECTION AGENCY

SOUTHERN COMPANY’S RESPONSE

TO

EPA’S PLANNED RULEMAKING FOR GHG NSPS FOR FOSSIL FUEL FIRED POWER PLANTS

Docket ID: EPA-HQ-OAR-2011-0090

Southern Company

600 North 18th Street

Birmingham, AL 35203

March 18, 2011
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Southern Company appreciates the opportunity to respond to the U.S. Environmental 

Protection Agency’s (EPA) planned rulemaking for greenhouse gas (GHG) new source 

performance standards (NSPS) for fossil fuel fired power plants. 

Southern Company is one of the largest generators of electricity in the nation; serving both 

regulated and competitive markets across the southeastern U.S. Southern Company

participates in all phases of the electric utility business with more than 42,000 megawatts of 

electric generating capacity and more than 27,000 miles of transmission lines. Southern 

Company provides electric service to over 4.4 million retail customers through its subsidiaries 

Alabama Power, Georgia Power, Gulf Power, and Mississippi Power. In addition, Southern 

Power, the Company’s competitive wholesale generation business, is among the largest 

wholesale energy providers in the Southeast, meeting the electricity needs of municipalities, 

electric cooperatives and investor-owned utilities. Other major subsidiaries include Southern 

Renewable Energy, which develops and invests in renewable energy projects; Southern 

Nuclear, the licensed operator of Southern Company’s three nuclear generating plants; 

SouthernLINC Wireless, a communications network with about 300,000 subscribers; and 

Southern Telecom, a fiber optic wholesaler in the Southeast. 

Southern Company is also a member of the Utility Air Regulatory Group (UARG). Southern 

Company herby endorses and incorporates by reference UARG’s comments in this matter. 

Importantly, Southern Company also endorses the positions taken by UARG and aligned 

petitioners in various litigated matters regarding the regulation of GHGs under the Clean Air Act

(CAA), and these comments are not intended to conflict with the resolution of those legal issues 

as advocated by UARG and aligned petitioners in those matters.

I. Proposed Settlement Agreement Regarding a Rulemaking on Proposed CAA Section 

111 Standards for GHG Emissions from Electric Utility Generating Units

The proposed settlement agreement between the State of New York, et al. and the EPA, notice 

of which EPA provided in the Federal Register on December 30, 2010, requires EPA to issue a 

proposed rule establishing NSPS for GHG emissions from new and modified electric utility 

generating units (EGUs) by July 26, 2011. Additionally, by July 26, 2011, EPA would need to 

issue a proposed rule that would set guidelines for states to develop GHG emission standards 

for existing EGUs. This deadline is a meager 4 months from now. Under the proposed 

settlement agreement, EPA would also be obligated to finalize these rules by May 26, 2012, a 

short 10 months after proposal. 

Southern Company is deeply concerned about the aggressive rulemaking schedule contained in 

the proposed settlement agreement and urges EPA to withdraw or withhold its consent to the 

proposed settlement agreement in order to permit a more reasoned and thorough review of 

these important issues.

EPA needs to look no further than the recent issues surrounding the regulation of hazardous air 

pollutant emissions from industrial boilers to determine that binding itself to short and 
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inflexible timelines through settlement agreements and consent decrees does not bode well for 

achieving an efficient and reasoned rulemaking. Due to stringent deadlines associated with the 

industrial boiler rulemaking, EPA requested a 15 month rulemaking extension by the U.S. 

District Court for the District of Columbia, to enable EPA to re-propose and finalize the rule. 

EPA felt this extension was necessary in order “to develop workable rules that can be 

implemented effectively and that can withstand judicial review.”1The U.S. District Court for 

the District of Columbia denied EPA’s request for an extension and only provided EPA with an 

additional month to finalize the industrial boiler rule. On February 21, 2011 EPA finalized the 

industrial boiler rule and due to the District Court’s denial of the 15 month extension had to 

immediately announce that: “*t+he Agency is in the process of developing a proposed 

reconsideration notice that identifies the specific elements of the rules for which we [EPA] 

believe further comment is appropriate and any provisions that we [EPA] propose to modify 

after fully evaluating the data and comments already received.”2 Given that developing NSPS 

for GHG emissions from new and modified EGUs and guidelines for states to develop GHG 

emission standards for existing EGUs is a complicated and controversial issue that has never 

been done for any source category and given the lack of flexibility EPA likely will be faced with if 

it consents to the proposed settlement agreement, EPA should withdraw or withhold its 

consent. Implementing the aggressive rulemaking timeline found in the proposed settlement 

agreement will not provide EPA the time necessary to adequately develop, collect, and review 

information, such as public comments, vital to the rulemaking process. 

Given more time, EPA would be in a position to release an advanced notice of proposed 

rulemaking (ANPR) and complete a thorough and reasoned regulatory impact assessment of all 

aspects of the rulemaking, including the guidelines for states to develop GHG emission 

standards for existing EGUs. Additional time would also provide EPA with a better opportunity 

to consider how the promulgation of NSPS for GHG emissions fits within EPA’s overall 

regulatory scheme. The interaction between NSPS for GHG emissions and the numerous other 

regulatory initiatives that will impact electric generators needs consideration. Impacts of EPA’s 

current regulatory agenda on the ability of the currently affected fossil generator fleet to both 

comply with new environmental rules, that tend to negatively affect efficiency, and any GHG 

rules that would expect improvements in efficiencies, needs detailing. Widespread impacts are 

expected to result from EPA’s cumulative air, coal combustion byproducts, water, and GHG 

regulatory initiatives. As part of its analysis EPA needs to complete a comprehensive regulatory 

impact assessment in order to develop a reasoned rulemaking.

II. GHG NSPS Should Not Include CCS Because It Is Not Adequately Demonstrated

 

1

Sierra Club v. Jackson. Case No. 1:01-cv-01537-PLF, Document 136-2, Filed 12.7.2010.

2

National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and 

Institutional Boilers and Process Heaters; National Emission Standards for Hazardous Air Pollutants for Area 

Sources: Industrial, Commercial, and Institutional Boilers; Standards of Performance for New Stationary Sources 

and Emission Guidelines for Existing Sources: Commercial and Industrial Solid Waste Incineration Units: Notice of 

Reconsideration, 2.21.2011.
4

Any performance standard established by EPA must be based on technologies that are 

adequately demonstrated. Currently, there are no GHG control technologies demonstrated at 

commercial scale. A standard cannot be set based on a technology that may be adequately 

demonstrated at some future time. Carbon capture and storage (CCS) is an example of a 

technology that cannot be used to set a GHG NSPS. CCS is not an adequately demonstrated 

carbon dioxide (CO2) control technology for EGUs. Each piece of the CCS process – capture, 

transport, and storage – has been demonstrated at some capacity, however, CO2 capture, 

transport, and storage have not been integrated at commercial scale on an EGU. The 

integration of these processes on an EGU could result in operational issues and other 

unknowns, which need to be investigated and determined through additional research. 

Southern Company bases this conclusion on its industry leading research activities associated 

with CCS technologies. 

In Session 1 of EPA’s listening sessions on GHG standards for fossil fuel fired power plants and 

petroleum refineries, the EPA Assistant Administrator for Air and Radiation Regina McCarthy 

noted that: NSPS is not a technology forcing standard and is not designed as a dramatic tool. 

The Assistant Administrator also stated that: it is very clear that CCS is not commercially 

available and that there are costs issues regarding the technology. Southern Company agrees 

with and supports this statement. For these reasons and other reasons included in these 

comments, any performance standard established by EPA should be based on technologies that 

are adequately demonstrated and not on technologies that need further development, such as 

CCS. 

Past NSPS revisions for NOx and SO2 prove that EPA’s precedent for establishing a particular 

technology as adequately demonstrated requires a significant level of full scale EGU 

installations. In 1998, EPA revised the performance standards for NOx emissions for both utility 

and industrial steam generating units to reflect the performance of the best demonstrated 

technology. EPA determined that flue gas treatment technologies, particularly selective 

catalytic reduction (SCR), represented the best demonstrated technology for NOx emissions 

reduction. EPA based this determination on the presence of “at least 212 worldwide SCR 

installations on coal-fired units, which cover different types of boilers subjected to varying 

operating conditions and firing a variety of coals.” EPA also noted that “*p+lants in Europe have 

been continuously using SCR for over 10 years” (63 FR 49442 - 49455). 

Additionally, in 1979 EPA revised the 1971 NSPS for SO2 for coal-fired electric generating plants. 

The 1979 revision retained the 1971 performance standard but added a requirement for a 70 to 

90 percent reduction in emissions, depending on the sulfur content of the coal. At the time, 

this requirement could be met only through use of a flue gas desulfurization (FGD) system. 

Prior to the 1979 revised NSPS for SO2 and between 1973 and 1978, FGDs were installed on 

about 50 units in the U.S. representing about 20 GWs.

3

 

 

3

Parker, Larry, Peter Folger, and Deborah D. Stine. “Capturing CO2 from Coal-Fired Power Plants: Challenges for a 

Comprehensive Strategy.” CRS Report for Congress – Order Code RL34621. August 15, 2008. 
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Integrated CCS technologies are nowhere near the deployment level of SCRs and FGDs when 

EPA determined those technologies as being an adequately demonstrated technology for NOx 

and SO2 NSPS. Thus, CCS should not be included in EPA’s GHG NSPS.

III. Southern Company is a Leader in Carbon Capture and Storage Technology Research

Southern Company is a leading researcher in CCS technologies for EGUs. According to the 

Interagency Task Force on CCS, “CCS is a three-step process that includes the capture and 

compression of CO2 from EGUs or industrial sources; transport of the captured CO2 (usually in 

pipelines); and storage of that CO2 in geologic formations, such as deep saline formations, oil 

and gas reservoirs, and unmineable coal seams.”4 Southern Company’s research involves each 

step of the CCS process individually and the integration of all three steps. As noted above, CCS

technologies have not been integrated at commercial scale on an EGU. A description of 

Southern Company’s CCS research is below. These descriptions highlight the depth to which 

Southern Company is researching CCS technologies, and they uncover the vital need for 

additional research and technological development to move the CCS technology from the 

demonstration/pilot scale to the commercial scale for EGUs.

Southern Company’s research projects include the National Carbon Capture Center (NCCC)

which is a focal point of the U.S. Department of Energy's (DOE) efforts to develop advanced 

technologies to reduce GHG emissions from coal-based power generation. It is a neutral test 

site focused on conducting research and development to advance emerging CO2 control 

technologies for effective integration into commercial coal-fired power plants, including 

integrated gasification combined cycle plants and conventional pulverized coal plants. It will 

test and evaluate CO2 control technologies including CO2 capture solvents, mass-transfer 

devices, low cost water-gas shift reactors, scaled-up membrane technologies, and improved 

means of CO2 compression. It is managed and operated by Southern Company and located at 

the Power Systems Development Facility in Wilsonville, Alabama. In addition to DOE and 

Southern Company, partners include American Electric Power, the National Energy Technology 

Lab, EPRI, Luminant, Peabody Energy, Arch Coal Inc., and Rio Tinto.

Southern Company also participated in a pilot CO2 injection project undertaken at Mississippi 

Power’s Plant Daniel by the Southeast Regional Carbon Sequestration Partnership (SECARB). 

This project involved drilling an injection well and an observation well into the Tuscaloosa 

Formation in South Mississippi. Approximately 3,000 tons of CO2 were injected into a saline 

formation approximately 8,500 ft underground. The injection was completed in the fall of 2008 

and monitoring completed in 2010. Another one of Southern Company’s research projects is a 

pilot injection project in the Black Warrior Basin coal seam which involves injecting 240 tons of 

CO2 into coal seams at depths ranging from 940 feet to 1,800 feet. The project began in 2009 

with the injection operations finalized in 2010. Monitoring will continue for several years to 

evaluate the methane recovery potential from the injection. 

 

4

“Report in the Interagency Task Force on Carbon Capture and Storage,” August 2010.
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Southern Company is also researching the geologic storage capacity and injectivity of certain 

sites and analyzing seal integrity and containment using laboratory analysis and reservoir 

simulation. Development of protocols for assessment of seal layer integrity and analysis of cap 

rock samples from geologic formulations under consideration for sequestration of CO2 is also 

being researched.

Additionally, Southern Company, in conjunction with EPRI, is researching the impact CO2 has on 

shallow groundwater. The project will evaluate the potential geochemical impacts of CO2 in 

drinking water aquifers. The project will take place at Mississippi Power’s Plant Daniel. Site 

characterization has been performed, and the test is scheduled for 2011.

Southern Company’s affiliate Mississippi Power plans to construct Plant Ratcliffe, an air-blown 

Integrated Gasification Combined Cycle demonstration project that will allow for precombustion capture and storage of 65 percent of the demonstration project’s CO2 emissions. 

Plant Ratcliffe is a DOE Clean Coal Power Initiative demonstration project. The demonstration 

project will utilize a coal-based transport gasifier which has a fuel-flexible design projected to 

have higher efficiency and lower capital and operating costs than the currently available 

oxygen-blown entrained-flow gasifiers. The demonstration project will be built in Kemper 

County, Mississippi and generate electricity using Mississippi lignite.

Southern Company is also constructing a 25 MW slip stream amine post-combustion capture 

demonstration plant at Alabama Power’s Plant Barry. Construction activities are scheduled for 

completion in 2011 with plant start-up to take place shortly thereafter. The project will provide 

CO2 for the DOE regional sequestration partnership SECARB phase 3 large volume sequestration 

demonstration project. The SECARB project includes drilling two injection wells and two 

observation wells into the Paluxy saline formation located geologically above the Citronelle Oil 

Field in South Alabama. The project will inject 100,000-150,000 tons of CO2 per year for up to 

four years with monitoring for an additional four years. The project will also construct and 

operate a twelve mile pipeline that will connect Plant Barry to the injection site. The project 

will evaluate effective monitoring and verification protocols for geologic sequestration, address 

regulatory and permitting issues, and cultivate public education and outreach internally and 

externally. It will also be one of the first projects in the world to study, at demonstration scale,

the integration of CO2 capture operations at a coal-fired power plant with pipeline 

transportation and saline reservoir injection.

Based on Southern Company’s extensive research, CCS is not an adequately demonstrated CO2

control technology for commercial scale EGUs. Each piece of the CCS process – capture, 

transport, and storage – has been demonstrated at some capacity, however, CO2 capture, 

transport, and storage have not been integrated at commercial scale on an EGU. The 

integration of these processes on an EGU could result in operational issues and other 

unknowns. Additionally, there are unresolved legal issues associated with CCS that need to be 

addressed before CCS can be widely deployed. These issues include pore-space ownership and 

long-term liability. Some states have enacted laws governing these issues, but they vary. This 
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is a problem for projects that operate in states without these laws and for projects that cover 

multiple states. 

Also, CCS is different from other control technologies, because it may involve a third party. For 

example, if CO2 storage is going to be done through enhanced oil recovery (EOR), more than 

likely, the power generator will have to enter into a contract with a third party to take the CO2

and responsibility for demonstrating storage. If there are problems with the contract or if the 

third party dissolves after some time, the power generator will be at risk unless it can find 

someone else to take its CO2.

Once again, these descriptions highlight Southern Company’s efforts to research CCS 

technologies, and they demonstrate the vital need for additional research and technological 

development to move the CCS technology from the demonstration/pilot scale to the 

commercial scale for EGUs.

IV. Guidelines for States to Develop GHG Emission Performance Standards for Existing 

EGUs

EPA should provide states with as much flexibility as possible in establishing guidelines for 

developing GHG performance standards for existing EGUs. In developing guidance, EPA should:

Recognize differences in different fuels and combustion technologies;

Recognize differences in unit types, sizes, and system demands;

Recognize natural degradation in efficiency over time in all units;

Recognize the trade-offs between a) decreased unit efficiencies due to traditional 

pollutant controls and the effort to incorporate renewable energy sources to a utility’s 

portfolio and b) the higher unit efficiencies that EPA may seek in the effort to lower GHG 

emissions;

Consider fleet-wide approaches to achieving performance standards;

Address the possibility that GHG efficiency projects can potentially trigger preconstruction permitting requirements under new source review (NSR) and prevention of 

significant deterioration (PSD) programs.

V. Reliability and Affordability Crisis for Electricity in the U.S.

EPA is developing a number of regulatory initiatives that will significantly impact the electric 

utility industry. These potential regulatory initiatives include the proposed settlement 

agreement’s directive to establish NSPS for GHG emissions from new and modified EGUs and 

guidelines for states to develop GHG emission performance standards for existing EGUs. A 

number of studies have been released detailing the impacts these regulatory initiatives may 

have on the reliability and affordability of U.S. electricity. Each study’s scope is different. Some

studies maintain a narrow focus (i.e., analyzing regulatory initiatives individually or only 

analyzing the combined impacts of a couple initiatives) while others take a more 
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comprehensive approach (i.e., analyzing the cumulative impacts of the majority of EPA’s 

regulatory initiatives).

The Edison Electric Institute’s (EEI) analysis prepared by ICF International, titled “Potential 

Impacts of Environmental Regulation in the U.S. Generation Fleet,” is the most comprehensive 

analysis of EPA’s regulatory initiatives to date. ICF International modeled the combined impacts 

of EPA’s potential air, coal combustion byproducts, water, and GHG regulations.5The study is 

the culmination of a year-long effort and represents a collaborative attempt to synthesize 

alternative approaches suggested by EEI’s membership for the selection of modeling inputs. 

These inputs include expected natural gas prices and the costs for new technology; scenarios 

about the potential regulations themselves (i.e., what regulation will apply, and the timing and 

stringency of those regulations); and sensitivities for modeling, including variation in natural gas 

prices, technology choices, and regulatory requirements. The report summarizes the potential 

impact for unit retirements, capacity additions, pollution control installations, and capital 

expenditures at the national and regional levels under a variety of potential scenarios.

The EEI analysis shows that when the combined impact of EPA’s regulatory initiatives are 

analyzed, over 150 GWs of coal, half of the U.S. coal fleet, are at risk of being unavailable in 

2015 for needed energy and required reliability due to insufficient time to install controls or 

replacement generation. Under this analysis, nearly 80 GWs of coal would retire by 2015 and 

the remaining coal would be subject to an unachievable retrofit schedule. These retirements 

and retrofits create the need to spend about $300 billion in the next five years, over two-thirds 

of which is for replacement generation. These circumstances lead to generation shortages and 

a rapid run-up in prices creating a reliability and affordability crisis. Careful consideration needs

to be given to these impacts if EPA decides to proceed in developing NSPS for GHG emissions 

from new and modified EGUs and guidelines for states to develop GHG emission performance 

standards for existing EGUs.

VI. Conclusion

As discussed above, it is clear that EPA does not have sufficient time to develop an efficient and 

reasoned proposal by July 26, 2011 on very complex issues that could have far reaching and 

long-term impacts on how entities generate electricity in the U.S. EPA needs to pursue a more 

reasoned and thorough rulemaking approach that pursuant to a rulemaking schedule will allow 

EPA to appropriately consider the complexities of establishing an NSPS for GHG emissions from 

EGUs. At a minimum, EPA should allow time to conduct an ANPR to assist in gathering the 

necessary data needed to develop a proposal for such a rulemaking. An ANPR would also allow 

EPA more time to comply with Executive Order No. 13563 Improving Regulation and Regulatory 

 

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Air regulations include: EGU MACT, Air Quality Standards (Clean Air Transport Rule, Ozone, Particulates, SO2, NO2) 

and Regional Haze. Coal Combustion Residuals include consideration of the currently proposed rules. Water 

includes consideration for the water intake structure (316(b)) regulations being developed. GHGs include

consideration for the regulatory requirements currently under development and the uncertainty of the future of 

legislative requirements. 
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Review, other obligations under the Regulatory Flexibility Act, and to better align interactions 

with other pending rulemakings affecting EGUs.

Further, any performance standard established by EPA must be based on technologies that are 

adequately demonstrated. A standard cannot be set based on a technology that may be 

adequately demonstrated at some future time. CCS is an example of a technology that cannot 

be used to set a GHG NSPS. CCS is not an adequately demonstrated CO2 control technology for 

EGUs. Southern Company bases this conclusion on its industry leading research activities 

associated with CCS technologies. EPA must also consider the impact their current regulatory 

agenda has on the ability of the currently affected fossil generator fleet to both comply with 

new environmental rules that tend to negatively affect efficiency and any GHG rules that would 

expect improvement in efficiencies. Additionally, when establishing guidelines for developing 

GHG performance standards for existing EGUs, EPA should provide states with as much 

flexibility as possible. Finally, EPA should consider and minimize the cumulative effects of EPA’s 

regulatory initiatives affecting EGUs. If appropriate consideration is not given to the cumulative 

impacts of these initiatives, generation shortages and a rapid run-up in prices creating a 

reliability and affordability crisis are likely to result.