1 UNITED STATES

ENVIRONMENTAL PROTECTION AGENCY

SOUTHERN COMPANY’S RE SPO NSE

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 18 th Street Birmingham, AL 35203 March 18, 20112

Southern Company apprec iates 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 acros s the southeastern U.S. Southern Compa ny participate s 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 T elecom, a fiber optic wholesaler in t he 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 petitioner s in those matters.

I. Proposed Settlement Agreement Regarding a Rule making on Proposed CAA Section 111 Standards for GHG Emissions from Electric Utility Generating Units

The proposed settlement agreement betwee n 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. Additionall y, 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

p roposed 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 emission s from industr ial boilers to determine that binding itself to short and3

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.” 1 The U.S. District Court for
the District of Columbia denied EPA ’s request for an extension and only provided EPA with an
additi onal month to finalize the industrial boil er rule. On February 21, 2011 EPA finalized the
industrial boiler rule and d ue to the District Court’s denial of the 15 month extension had to immediately announce that : “*t+he Agency is in the process of developi ng a proposed reconsideration notice that identifies the specific elements of the rules for which we [EPA] believe further comment is appropriate and any provisions th at we [EPA] propose to modify after fully evaluating the data and comments already receiv ed.” 2 Given that d eveloping NSPS
for GHG emissions from new and modi fied EGUs and guidelines for states to develop GHG

emission standards for existing EGU s 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 pr ovide 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 EGU s. Additional time wou ld 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 im pact electric generators needs consideration. Impacts of EPA’s current regulatory agenda on the ability of the current ly affected fossil generator fleet to both comply with new environmental rules, that tend to negatively affect efficiency, and any GHG

ru les 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 in itiatives. As part of its analysis EPA needs to complete a c omprehensive 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 Inc ineration Units: Notice of Reconsideration, 2.21.2011.4

Any performance standard established by EPA must be based on technologies that are adequately d emonstrated. 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

t echnology that cannot be used to set a GHG NSPS. CCS is not a n adequately demonstrated carbon dioxide ( CO 2 ) control technology for EGUs. Each piece of the CCS process

– capt ure, transport, and storage

– has bee n demonstrated at some capacity, h owever, CO 2 captu re, transport, and storage have not been integrated at commercial scale on a n 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 r esearch

. 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 Radia tion Regina McCarthy noted that: NSPS is not a technology forcing standard and is no t designed as a dramatic tool.
The Assistant A dmin istrator also stated that: it i s very clear that CCS is not commercial ly
availa ble 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 technol ogies that are adequately demonstrated and not on technologies that need further development, such as

CCS.

Past NSPS revisions for NOx and SO 2 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 t hat 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 c oal

- 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).

Additio nally, in 1979 EPA revised the 1971 NSPS for SO 2 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 t he 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 SO 2 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 CO 2 from Coal

- Fir ed Power Plants: Challenges for a Comprehensive Strategy.” CRS Report for Congress

– Order Code RL34621. August 15, 2008

.5

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 SO 2 NSPS. Thus, CCS should not be included in EPA’s GHG NSPS.

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

Southern Compa ny is a leading researcher in CCS technologies for EGU s. According to the Interagency Task Force on CCS, “ CCS is a three

- step process that includes the capture and compression of CO 2 from EGUs or industrial sources; transport of the captured CO 2 (usually in pipelines ) ; and storage of that CO 2 in geol ogic forma tion s , such as deep saline formation s , oil and gas reservoirs, and unmineable coal seam s .” 4 Southern Compan y’s research involves each
step o f the CCS process individually and the integration of all three steps

. As noted above, C CS technologies have not been integrated at commercial scale on an EGU. A description of
South ern Company’s CCS research is bel ow. These descriptions highlight the depth to which
Southern Com pany is researching CCS technologies, and they uncover the vital need for additional research and technological deve lopment to move the CCS technology from the
demonstration / pilot scale to th e 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
techn ologies to reduce GHG emissions from coal

- based power generation. It is a neutral test site focused on conducting research and development to advance emerging CO 2 control technologies for effective integration into commercial coal

- fired power plants, including integrated gasi fication combined cycle plants and conven tional pulverized coal plants. It will
test and evaluate CO 2 control technologies including CO 2 capture solvents, mass

- transfer devices, low cost water

- gas shift reactors, scaled

- up membrane technologies, and improv ed
means of CO 2 compression. It is managed and operated by Southern Company and located a t the Power Systems Development Fac ility in Wilsonville, Alabama. In addition to DOE and
Southern Company , partners include American Electric Power, the National Ene rgy Technology Lab, EPRI, Luminant, Peabody Energy, Arch Coal Inc., and Rio Tinto.

Southern Company also participated in a pilot CO 2 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 in to the Tuscaloosa Formation in South Mississippi

. Approximately 3,000 tons of CO 2 were injected into a saline formation approximately 8

, 500 ft underground. The injection was completed in the fall of 20 08 and monitoring c om pleted 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

CO 2 into coal seam s at depths ranging fr om 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 2010.6

Southe rn Company is a lso research ing the geologic storage capacity and injectiv ity of certain sites and analyzing seal integrity and containment using laboratory analysis and reservoir
simulation. D evelopment of protocols for assessment of seal layer integrity and analysis of cap rock samples from geologic formulations under consideration for sequestration of CO 2 is also being researched

.

Additionally, Southern Company , in conjunction with EPRI, is researching the impact CO 2 has on shallow groundwater. The proj ect will evalu ate the potential geochemical impacts of CO 2 in drinking water aquifers. The project will take place at Mississippi Power’s Plant Daniel. Site characterization has been performed, an d the test is scheduled for 2011.

Southern Company’s affiliate Mis sissi ppi Power plans to construct Plant Ratcliffe, an air

- blown Integrated Gasification Combined Cycle d emonstration project that will allow for pre

combustion capture and storage of 65 percent of the demonstration project ’s CO 2 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 there after. The project will provide

CO 2 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 CO 2 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 conne ct 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. I t will also be one of the first projects in the world to study

, at demonstration scale

, the integration of CO 2 capture operations at a coal

- fired power plant with pipeline transportation and saline reservoir injection.

Based on Southern Company’ s extensiv e research, CCS is not a n adequately demonstrated CO 2 control technology for commercial scale EGUs. Each piece o f the CCS process

– capt ure, transport, and storage

– has bee n demonstrated at some capacity, h owever, CO 2 captu re, transport, and storage have not been integrated at commercial scale on a n 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 b ef ore 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. This7

is a problem for project s that operate in states without these laws and for proj ects that cover multiple states.

Also, CCS is different from other control technologies, because it may involve a third party. For example, if CO 2 storage is going to be done through enhanced oil recovery (EOR) , more than likely, the power generator wi ll have to enter into a contract with a third party to take the CO 2 and responsibility for demonstrating storage. If there a re problems with the contract or if the third party dissolves after some time, the power generator will be at risk unless it can fi nd
someone else to take its CO 2
.

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

t echnologies, and they demonstrate the vital need for additional research and technological development to move the CCS technology from th e demonstration/pilot scale to the
commercial scale for EGUs.

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

EGU s

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 portfol io 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 project s can potentially trigger pre

construction 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 EGU s and guidelines for states to develop GHG emission performance standards for existing EGU s. A number of studies have been released detailing the impacts these regulatory initiatives may have on the reliability and affordability of U.S. elect ricity. 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 more8

comprehensive approach (i.e., anal yzing the cumulative impacts of the majority of EPA’s regulatory initiatives).

The E dison Electric Institute ’s (EEI ) analysis prepared by ICF International, titled “ Potential Impacts of Environmental Regulation in the U.S. Generation Fleet,” is the most c omprehensive 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. 5 The study is the culmination of a year

- long effort and represen ts 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 GW s 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 b y 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 ye ars, 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 need s to be given to these impacts if EPA decides to proceed in developin g NSPS for GHG emissions
from new and modified EGU s and guidelines for states to develop GHG emission performance standards for existing EGU s.

VI. Conclusion

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

r easoned 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 rulema king approach that pursuant to a rulemaki ng 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

5 Air regulations include: EGU MACT, Air Quality Standards (Clean Air Transpo rt Rule, Ozone, Particulates, SO 2 , NO 2 ) and Regional Haze. Coal Combustion Residuals includ e consideration of the currently proposed rules. Water includes consideration for the water intake structure (316(b)) regulation s being developed. GHGs include consideration for the regulatory requirements currently under development and the uncertainty of the future of legislative requirements.9

Review, other obligations under the Regulatory Flexibility Act, and to better align interactions with other pending rulemaki ngs affecting EGUs.

Further, a ny 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 cann ot be used to set a GHG NSPS. CCS is not a n adequately demonstrated CO 2 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 t heir current regulatory agenda has on the ability of the currently affected fossil generator fleet to both comply with
new environmental rule s that tend to negatively affect efficiency and any GHG rules that would expect improvement in efficiencies. Addit ionally, w hen 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 initiati ves 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.