51248 Federal Register / Vol. 75, No. 160 / Thursday, August 19, 2010 / Notices 

770) (the Act). This notice is provided 

in accordance with the Act. 

DATES: Wednesday, September 1, 2010 

8:30 a.m.–5 p.m. 

ADDRESSES: Washington Marriott Hotel, 

1221 22nd Street, NW., Washington, DC. 

FOR FURTHER INFORMATION CONTACT: 

Timothy A. Frazier, Designated Federal 

Officer, U.S. Department of Energy, 

1000 Independence Avenue, SW., 

Washington, DC 20585; telephone (202) 

586–4243 or facsimile (202) 586–0544; 

e-mail 

CommissionDFO@nuclear.energy.gov. 

Additional information will be available 

at http://www.brc.gov. 

SUPPLEMENTARY INFORMATION: 

Background: The President directed that 

the Commission be established to 

conduct a comprehensive review of 

policies for managing the back end of 

the nuclear fuel cycle. The Commission 

will provide advice and make 

recommendations on issues including 

alternatives for the storage, processing, 

and disposal of civilian and defense 

spent nuclear fuel and nuclear waste. 

The Co-chairs of the Commission 

requested the formation of the Disposal 

Subcommittee to answer the question: 

‘‘[h]ow can the U.S. go about 

establishing one or more disposal sites 

for high-level nuclear wastes in a 

manner that is technically, politically 

and socially acceptable?’’ 

Purpose of the Meeting: The meeting 

will focus on standardization and 

regulations for deep geological disposal. 

Topics to be discussed during the 

meeting include essential elements of 

technically credible, workable, and 

publicly acceptable regulations for 

disposal in geologic repositories; as well 

as essential elements of a technically 

credible and publicly acceptable 

institutional system and process for 

regulating the safety of disposal. 

Tentative Agenda: The meeting is 

expected to start at 8:30 a.m. on 

September 1, 2010 with panel 

presentations beginning at 8:45 a.m. and 

ending at 4:15 p.m. with a public 

comment period from 4:15 p.m. through 

5 p.m. 

Public Participation: Subcommittee 

meetings are not required to be open to 

the public; however, the Commission 

has elected to open the presentation 

sessions of the meeting to the public. 

Individuals and representatives of 

organizations who would like to offer 

comments and suggestions may do so at 

the end of the public session on 

Wednesday, September 1, 2010. 

Approximately 45 minutes will be 

reserved for public comments from 4:15 

p.m. to 5 p.m. Time allotted per speaker 

will depend on the number who wish to 

speak but will not exceed 5 minutes. 

The Designated Federal Officer is 

empowered to conduct the meeting in a 

fashion that will facilitate the orderly 

conduct of business. Those wishing to 

speak should register to do so beginning 

at 7:30 a.m. on September 1, 2010, at the 

Washington Marriott. Registration to 

speak will close at noon, September 1, 

2010. 

Those not able to attend the meeting 

or have insufficient time to address the 

subcommittee are invited to send a 

written statement to Timothy A. Frazier, 

U.S. Department of Energy 1000 

Independence Avenue, SW., 

Washington DC 20585, e-mail to 

CommissionDFO@nuclear.energy.gov, or 

post comments on the Commission Web 

site at http://www.brc.gov. 

Additionally, the meeting will be 

available via live video webcast. The 

link will be available at http:// 

www.brc.gov. 

Minutes: The minutes of the meeting 

will be available at http://www.brc.gov 

or by contacting Mr. Frazier. He may be 

reached at the postal address or e-mail 

address above. 

Issued in Washington, DC on August 13, 

2010. 

Rachel Samuel, 

Deputy Committee Management Officer. 

[FR Doc. 2010–20573 Filed 8–18–10; 8:45 am] 

BILLING CODE 6450–01–P 

DEPARTMENT OF ENERGY 

State Energy Advisory Board (STEAB) 

AGENCY: Department of Energy. 

ACTION: Notice of open teleconference. 

SUMMARY: This notice announces a 

meeting of the State Energy Advisory 

Board (STEAB). The Federal Advisory 

Committee Act (Pub. L. 92–463; 86 Stat. 

770) requires that public notice of these 

meetings be announced in the Federal 

Register. 

DATES: Thursday, September 16, 2010 

from 3:30 to 4:30 p.m. EDT. 

FOR FURTHER INFORMATION CONTACT: Gary 

Burch, STEAB Designated Federal 

Officer, Senior Management Technical 

Advisor, Intergovernmental Projects, 

Golden Field Office, U.S. Department of 

Energy, 1617 Cole Boulevard, Golden, 

CO 80401, Telephone 303–275–4801. 

SUPPLEMENTARY INFORMATION: 

Purpose of the Board: To make 

recommendations to the Assistant 

Secretary for the Office of Energy 

Efficiency and Renewable Energy 

regarding goals and objectives, 

programmatic and administrative 

policies, and to otherwise carry out the 

Board’s responsibilities as designated in 

the State Energy Efficiency Programs 

Improvement Act of 1990 (Pub. L. 101– 

440). 

Tentative Agenda: Review and update 

of task force accomplishments, update 

on the status of a meeting with USDA 

to discuss Resolution 10–01, update 

regarding the recent meeting of the 

Energy Efficiency and Conservation 

Block Grant (EECBG) subcommittee, and 

provide an update to the Board on 

routine business matters and other 

topics of interest. 

Public Participation: The meeting is 

open to the public. Written statements 

may be filed with the Board either 

before or after the meeting. Members of 

the public who wish to make oral 

statements pertaining to agenda items 

should contact Gary Burch at the 

address or telephone number listed 

above. Requests to make oral comments 

must be received five days prior to the 

meeting; reasonable provision will be 

made to include requested topic(s) on 

the agenda. The Chair of the Board is 

empowered to conduct the meeting in a 

fashion that will facilitate the orderly 

conduct of business. 

Minutes: The minutes of the meeting 

will be available for public review and 

copying within 60 days on the STEAB 

Web site, http://www.steab.org. 

Issued at Washington, DC, on August 13, 

2010. 

Rachel Samuel, 

Deputy Committee Management Officer. 

[FR Doc. 2010–20566 Filed 8–18–10; 8:45 am] 

BILLING CODE 6450–01–P 

DEPARTMENT OF ENERGY 

Record of Decision and Floodplain 

Statement of Findings; Kemper County 

IGCC Project, Kemper County, MS 

AGENCY: U.S. Department of Energy. 

ACTION: Record of Decision and 

Floodplain Statement of Findings. 

SUMMARY: The Department of Energy 

(DOE) prepared an Environmental 

Impact Statement (EIS) (DOE/EIS–0409) 

to assess the environmental impacts 

associated with a proposed project 

designed, constructed, operated, and 

owned by Mississippi Power, a 

Southern Company subsidiary. The U.S. 

Army Corps of Engineers (USACE) was 

a cooperating agency in the preparation 

of this EIS. The project would 

demonstrate advanced power generation 

systems using Integrated Gasification 

Combined Cycle (IGCC) technology at 

an undeveloped site in Kemper County, 

MS. DOE’s proposed action has two 

components: first, to provide costVerDate Mar<15>2010 17:05 Aug 18, 2010 Jkt 220001 PO 00000 Frm 00011 Fmt 4703 Sfmt 4703 E:\FR\FM\19AUN1.SGM 19AUN1

emcdonald on DSK2BSOYB1PROD with NOTICES
Federal Register / Vol. 75, No. 160 / Thursday, August 19, 2010 / Notices 51249 

shared financial assistance and, second, 

to issue a loan guarantee. After careful 

consideration of the potential 

environmental impacts and other factors 

such as program goals and objectives, 

DOE has decided that it will provide, 

through a cooperative agreement with 

Southern Company Services (SCS), also 

a Southern Company subsidiary, $270 

million in cost-shared funding under 

DOE’s Clean Coal Power Initiative 

(CCPI) program for the project. A 

separate decision would be made 

regarding the loan guarantee; DOE 

would announce that decision in a 

subsequent Record of Decision. 

ADDRESSES: The Final EIS is available 

on the DOE National Environmental 

Policy Act (NEPA) Web site at http:// 

www.nepa.energy.gov/1445.htm and on 

the DOE National Energy Technology 

Laboratory (NETL) Web site at http:// 

www.netl.doe.gov/technologies/ 

coalpower/cctc/ccpi/bibliography/ 

demonstration/adv-gen/ccpi_285- 

mw.html. The Record of Decision (ROD) 

will be available on both Web sites 

soon. Copies of the Final EIS and this 

ROD may be obtained by contacting Mr. 

Richard A. Hargis, Jr., National 

Environmental Policy Act (NEPA) 

Document Manager, U.S. Department of 

Energy, National Energy Technology 

Laboratory, 626 Cochrans Mill Road, 

P.O. Box 10940, Pittsburgh, PA 15236– 

0940; telephone: 412–386–6065; or email: Kemper-EIS@netl.doe.gov. 

FOR FURTHER INFORMATION CONTACT: To 

obtain additional information about the 

project or the EIS, contact Mr. Richard 

A. Hargis, Jr. at the addresses provided 

above. For general information on the 

DOE NEPA process, contact Ms. Carol 

M. Borgstrom, Director, Office of NEPA 

Policy and Compliance (GC–54), U.S. 

Department of Energy, 1000 

Independence Avenue, SW., 

Washington, DC 20585; telephone: 202– 

586–4600; or leave a toll-free message at 

1–800–472–2756. 

SUPPLEMENTARY INFORMATION: DOE 

prepared this ROD and Floodplain 

Statement of Findings pursuant to 

Council on Environmental Quality 

(CEQ) regulations for implementing the 

procedural provisions of NEPA [40 Code 

of Federal Regulations (CFR) Parts 

1500–1508], DOE NEPA regulations (10 

CFR part 1021) and DOE’s Compliance 

with Floodplain and Wetland 

Environmental Review Requirements 

(10 CFR part 1022). This ROD is based 

on DOE’s Final EIS for the Kemper 

County IGCC Project (DOE/EIS–0409, 

May 2010) and other program 

considerations. 

Background and Purpose and Need for 

Agency Action 

Public Law 107–63, enacted in 

November 2001, first provided funding 

for the Clean Coal Power Initiative 

(CCPI) program, a Federal program to 

accelerate the commercial readiness of 

advanced technologies in existing and 

new coal-based power plants. The 

program encompasses a broad spectrum 

of commercial-scale demonstrations that 

target today’s most pressing 

environmental challenges, including 

reducing mercury and greenhouse gas 

(GHG) emissions by boosting the 

efficiency at which coal is converted to 

electricity or other energy forms. When 

integrated with other DOE initiatives, 

the program will help the nation 

successfully commercialize advanced 

power systems that will produce 

electricity at greater efficiencies, release 

almost no emissions, create clean fuels, 

and employ carbon dioxide (CO2) 

management capabilities. 

The purpose of DOE’s proposed 

action under the CCPI program is to 

demonstrate the feasibility of the 

Transport Integrated Gasification 

(TRIGTM) IGCC technology at a size that 

would be attractive to utilities for 

commercial operation. DOE, Southern 

Company, Kellogg Brown & Root LLC, 

and other industrial proponents have 

been developing this technology since 

1996. It is cost-effective when using 

low-heat content, high moisture, or 

high-ash content coals, including 

lignite. These coals constitute 

approximately one-half of proven coal 

reserves. A successful demonstration 

would generate technical, 

environmental, and financial data to 

confirm that the technology can be 

implemented at a commercial scale. 

Financial assistance from DOE would 

reduce the cost and financial risk in 

demonstrating that the technology is 

ready for commercialization. 

The purpose of DOE’s proposed 

action with regard to the Federal loan 

guarantee is to encourage early 

commercial use in the United States of 

new or significantly improved energy 

technology and to reduce or eliminate 

emissions of GHGs and other air 

pollutants pursuant to Title XVII of the 

Energy Policy Act of 2005 (EPAct). 

Two principal needs are addressed by 

DOE’s proposed actions. First, the 

project would satisfy the responsibility 

Congress imposed on DOE to 

demonstrate advanced coal-based 

technologies that can generate clean, 

reliable, and affordable electricity in the 

United States. Second, with regard to 

the Federal loan guarantee, this project 

would fulfill EPAct’s objective of 

assisting projects that ‘‘avoid, reduce, or 

sequester air pollutants or 

anthropogenic emissions of GHGs’’ and 

‘‘employ new or significantly improved 

technologies as compared to 

technologies in service in the United 

States.’’ 

EIS Process 

On September 22, 2008, DOE 

published a Notice of Intent (NOI) (73 

FR 54569) to prepare the EIS and hold 

a public scoping meeting. DOE held a 

public scoping meeting in DeKalb, 

Mississippi, on October 14, 2008. The 

Department received oral responses at 

the meeting and other responses by 

comment card, mail, e-mail, and 

telephone from individuals, interested 

groups, and Federal, State, and local 

officials. On November 5, 2009, DOE 

published in the Federal Register (74 

FR 57297) a Notice of Availability 

(NOA) for the Kemper County IGCC 

Project Draft EIS. The NOA invited 

comments on the Draft EIS. As part of 

the review process, DOE conducted a 

public hearing on December 1, 2009, in 

DeKalb, Mississippi. The public was 

encouraged to provide oral comments at 

the hearing and to submit written 

comments to DOE during a 45-day 

comment period that ended December 

21, 2009. DOE received numerous 

comments; many resulted from e-mail 

campaign efforts of two nongovernmental organizations. 

DOE issued the Final EIS and the 

Environmental Protection Agency (EPA) 

published a NOA in the Federal 

Register on May 21, 2010 (75 FR 28612). 

In the Final EIS, DOE responded to 

comments on the Draft EIS. Among the 

issues raised in these comments were 

concerns about (1) DOE’s statement of 

purpose and need; (2) the range of 

alternatives considered; (3) air pollutant 

emissions, emissions controls, and air 

quality impacts; (4) emissions of GHG 

and climate change effects; (5) surface 

water quality and downstream effects on 

the Pascagoula River and Gulf of 

Mexico; (6) stream restoration following 

mining; (7) increases in flood elevations 

and effects on floodplains; (8) wetlands 

impacts and mitigation; (9) hydrologic 

impacts, especially on Okatibbee Lake; 

(10) groundwater impacts and effects on 

drinking water supplies; (11) noise 

impacts; (12) mining impacts, including 

soils, and land reclamation; (13) wildlife 

impacts, including threatened and 

endangered species; (14) risks to human 

health from criteria and hazardous air 

pollutants, including mercury 

deposition and bioaccumulation; (15) 

socioeconomic and environmental 

justice impacts; (16) traffic impacts; (17) 


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land and right-of-way acquisition; and 

(18) effects on community resources. 

Decision 

DOE has decided to provide 

Mississippi Power with cost-shared 

funding of $270 million through a 

cooperative agreement with Southern 

Company Services to design, construct, 

and demonstrate the Kemper County 

IGCC Project. 

Basis of Decision 

DOE’s decision is based on the 

importance of achieving the objectives 

of the Clean Coal Power Initiative and 

a careful review of the potential 

environmental impacts presented in the 

EIS. The project provides a significant 

opportunity to demonstrate a 

technology that can use the nation’s 

abundant coal resources in a costeffective and clean manner while 

reducing GHG emissions. The effective 

and clean use of domestic energy 

resources allows the United States to 

reduce its reliance on world markets for 

its energy supplies—reliance on these 

markets decreases national security. 

This technology also addresses concerns 

about the consequences of continuing to 

use fossil fuels without effectively 

managing their carbon emissions. The 

project incorporates controls that make 

its carbon emissions essentially equal to 

natural gas-based power generation. The 

key feature of the TRIGTM technology is 

its cost-effective use of low-rank coals, 

like Mississippi lignite, which 

constitutes nearly 50% of our nation’s 

coal resource. DOE has reviewed and 

participated in the technology’s 

development and believes that it is 

ready for commercial demonstration. 

Without this project, DOE would not 

have the opportunity to demonstrate 

this technology and make it available for 

the cost-effective and clean use of low 

rank coals. 

The project would also have 

economic benefits to the region. Beyond 

the estimated combined construction 

payroll for the plant and mine of $145 

million, there would be an estimated 

additional indirect benefit of $82 

million and 186 additional jobs due to 

construction activities. The operation of 

the plant and mine would result in an 

estimated $25 million annual payroll, 

an indirect annual economic benefit of 

about $11.4 million, and approximately 

97 new jobs. 

This decision incorporates all 

practicable means to avoid or minimize 

environmental harm. DOE plans to 

verify the environmental impacts 

predicted in the EIS and the 

implementation of appropriate 

avoidance and mitigation measures. 

Mitigation 

DOE’s decision incorporates measures 

to avoid or minimize adverse 

environmental impacts during the 

design, construction and demonstration 

of the project. DOE requires that the 

participants comply with all applicable 

Federal, State, and local environmental 

laws, orders, and regulations. Mitigation 

measures beyond those specified in 

permit conditions will be addressed in 

a Mitigation Action Plan (MAP). DOE 

will prepare the MAP, consistent with 

10 CFR 1021.331, which will explain 

how the mitigation measures will be 

planned, implemented and monitored. 

The MAP is an adaptive management 

tool; mitigation conditions in it would 

be removed if equivalent conditions are 

otherwise established by permit, 

license, or law, as compliance with 

permit, license or regulatory 

requirements are not considered 

mitigation activities subject to DOE 

control and are therefore not included 

in MAPs. 

DOE will ensure that commitments in 

the MAP are met through management 

of the cooperative agreement, which 

requires that Southern Company 

Services fulfills the monitoring and 

mitigation requirements specified in 

this ROD. DOE will make copies of the 

MAP available for inspection in the 

appropriate locations for a reasonable 

time. Copies of the MAP and any annual 

reports required under the MAP will 

also be available upon written request. 

Project Description and Location 

The power plant would be located on 

an approximately 1,650-acre site in 

southwestern Kemper County. The mine 

and linear facilities (e.g., pipelines) 

would extend into several other 

counties. The power plant site and mine 

area are rural and sparsely populated. 

The electrical transmission lines and 

pipelines would also traverse mostly 

rural areas. Mississippi Power plans to 

acquire additional properties adjacent to 

the proposed power plant site for buffer 

areas. Approximately 1,400 acres of 

buffer areas immediately north and east 

of the site have been acquired, optioned, 

or identified for acquisition. 

The IGCC plant consists of two major 

systems: Lignite coal gasification and 

combined-cycle power generation. The 

gasification systems consist primarily of 

lignite handling, gasification, and 

syngas processing and cleanup. There 

are two lignite gasifiers. At full capacity, 

the gasifiers would convert an average 

of 13,800 tons per day of lignite into 

syngas (synthesis gas). The principal 

combined-cycle components include 

two combustion turbines (CTs), two heat 

recovery steam generators (HRSG), and 

a steam turbine. In a combined-cycle 

unit, fuel gas is combusted in CTs, and 

its hot exhaust gas is then used to heat 

water to drive a steam turbine. The 

reuse of the CTs’ exhaust heat to power 

a steam turbine constitutes the 

combined-cycle approach, which 

increases the amount of electricity that 

can be generated from a given amount 

of fuel. 

The proposed project would reduce 

sulfur dioxide (SO2), nitrogen oxides 

(NOx), mercury, and particulate 

emissions by removing them from the 

syngas. The removal of nearly 100 

percent of the fuel-bound nitrogen from 

the syngas prior to combustion in the 

gas CTs would result in appreciably 

lower NOx emissions compared to 

conventional coal-fired plants. The 

facility would have carbon capture 

systems sufficient to reduce CO2

emissions by approximately 67 percent 

by removing carbon from the syngas. 

The CO2 would be compressed and 

piped offsite where it would be sold for 

beneficial use and geologic storage via 

enhanced oil recovery (EOR). 

Connected actions are actions that are 

closely related to the proposed action 

and therefore are evaluated in the same 

EIS. The project’s connected actions 

consist of construction and operation of 

a cooling water supply (i.e., reclaimed 

effluent from municipal wastewater 

treatment) pipeline, a natural gas 

pipeline, associated transmission lines 

and substations, CO2 pipelines, and a 

lignite mine. North American Coal 

Company would construct and operate 

the mine. The mine would be located 

next to the power plant site. The mine 

would be the primary source of 

feedstock for the IGCC project. 

Approximately 4.3 million tons per year 

of lignite would be mined for up to 40 

years. As many as 12,275 acres would 

be disturbed over the life of the mine. 

Actual mining—the uncovering and 

extraction of lignite—would disturb 

between 135 and 340 acres per year. 

After the first 3 to 5 years of mining, 

approximately the same acreage would 

be reclaimed each year as that newly 

disturbed. 

Construction of the power plant 

would begin in 2010 and continue for 

3.5 years. During construction, an 

average of 500 workers would be on the 

site, with approximately 1,150 workers 

required during the peak construction 

period. The plant’s operational 

workforce would be approximately 90– 

105 employees. 

Proposed Actions 

DOE’s proposed actions are to provide 

financial assistance and to issue a loan 


emcdonald on DSK2BSOYB1PROD with NOTICES
Federal Register / Vol. 75, No. 160 / Thursday, August 19, 2010 / Notices 51251 

guarantee. The Congress established the 

CCPI program to accelerate commercial 

deployment of advanced technologies 

for generating clean, reliable, and 

affordable electricity in the United 

States using abundant domestic reserves 

of coal. EPAct established the Federal 

Loan Guarantee Program to assist energy 

projects that employ innovative 

technologies. 

DOE proposed providing an 

additional $270 million in financial 

assistance to the Kemper County 

project. It has already provided some 

funding ($23.5 million) to Southern 

Company Services for the preliminary 

design and definition of this project at 

a previous location. DOE’s proposed 

action encompasses those activities that 

are eligible for this funding, including 

the construction of power plant 

components such as the gasification 

island, the combined-cycle power 

generation unit, and its auxiliary 

facilities. 

In addition to providing financial 

assistance, DOE is considering issuing a 

loan guarantee. A separate ROD would 

be issued regarding the loan guarantee. 

If approved for a guarantee, a loan from 

the Federal Financing Bank would fund 

a portion of the plant’s construction 

costs. 

Alternatives 

Congress directed DOE to pursue the 

goals of the CCPI Program by means of 

partial funding of projects owned and 

controlled by non-Federal sponsors. 

This statutory requirement places DOE 

in a much more limited role than if it 

were the owner and operator of the 

project. Here, the purpose of and need 

for DOE action is defined by the CCPI 

program (and enabling legislation, 

Public Law 107–63) and the Federal 

Loan Guarantee Program (and enabling 

legislation, EPAct). Given these 

programmatic purposes and needs, 

reasonable alternatives available to DOE 

prior to the selection of this project 

under the CCPI and Loan Guarantee 

Programs were other projects that 

applied to these programs and met their 

eligibility requirements. Other 

applications (and their potential 

environmental, safety and health 

impacts) were considered during the 

evaluation and selection process. 

Pursuant to 10 CFR 1021.216, a synopsis 

of the environmental review and 

critique completed for the evaluation 

and selection process will be posted on 

the DOE NETL Web site at http:// 

www.netl.doe.gov/technologies/ 

coalpower/cctc/ccpi/bibliography/ 

demonstration/adv-gen/ccpi_285- 

mw.html. Once the selection process 

complete, the reasonable alternatives are 

limited to alternatives still under 

consideration by the proponents of a 

selected project and the no-action 

alternative. 

The site for the Kemper County 

project was chosen by Mississippi 

Power based on a site selection process 

it had completed prior to seeking DOE 

funding for the project. It found that the 

only reasonable site was the Kemper 

County site based on the location of 

accessible lignite reserves near 

Mississippi Power’s service territory, 

proximity to infrastructure, topography, 

environmental considerations, and 

available open space. 

With regard to alternative power 

generation technologies, DOE 

considered other coal-based 

technologies in evaluating the proposals 

received under the CCPI solicitation. 

Other technologies (e.g., natural gas, 

wind power, solar energy, and 

conservation) would not achieve the 

CCPI program’s goal of accelerating 

commercial deployment of advanced 

coal-based technologies. Other 

alternatives, such as reducing the size of 

the proposed project, were dismissed as 

unreasonable, since the size of the 

proposed project is related to 

Mississippi Power’s projected need for 

power. 

Under the proposed action 

alternative, DOE assessed the impacts of 

alternative water sources, alternative 

linear facility routes, and alternative 

levels of CO2 capture. Route selection 

procedures were applied to all proposed 

linear facilities. These procedures 

considered various route selection 

factors, such as making use of (or 

paralleling) existing rights-of-way and 

avoiding developed or sensitive areas. 

The EIS evaluated a range of 

alternative levels of percentage CO2

capture: 25, 50, 67, and greater than 67. 

After initially basing the design on 25- 

percent capture, designs were updated 

to target 50- and then 67-percent 

capture. The project DOE has decided to 

fund includes a capture rate of 67 

percent. This higher rate will require 

more fuel to achieve the same net power 

output relative to a plant with 50- 

percent capture. Air quality impacts 

vary slightly between the 50- and 67- 

percent rates and some other differences 

would result (e.g., there would be small 

variations in outputs of by-products). 

No-Action Alternative 

Under the no-action alternative, DOE 

would not provide cost-shared funding 

for the design, construction, and 

demonstration of the proposed Kemper 

County IGCC Project, nor issue a loan 

guarantee. DOE considered the noaction alternative to be the same as the 

‘‘no-build’’ alternative. However, 

without DOE participation, Southern 

Company and Mississippi Power could 

pursue two options. First, Mississippi 

Power could continue with the project 

without Federal participation. DOE 

believes that option is unlikely, because 

the financial risks and costs of 

deploying a new type of IGCC power 

system are significant. In any event, if 

the proponents were to proceed with the 

project without DOE participation, the 

direct, indirect, and cumulative impacts 

would be essentially the same as DOE’s 

proposed action. Second, the 

proponents could abandon the IGCC 

project and, instead, meet future energy 

and capacity needs from other sources. 

Under this scenario, the proposed IGCC 

facility would not be built. It is also 

likely that the lignite mine would not be 

built nor the linear facilities. As a 

consequence, none of the direct impacts 

associated with the project would occur, 

whether adverse or beneficial. In 

addition, the opportunities for more 

rapid commercialization of the 

gasification technologies (alone or 

integrated with the combined-cycle 

facilities) would diminish, because 

utilities and industries tend to prefer 

known and demonstrated technologies. 

This outcome would not achieve the 

CCPI program’s goal of accelerating 

commercial deployment of advanced 

coal-based technologies that can 

generate clean, reliable, and affordable 

electricity in the United States. 

Potential Environmental Impacts and 

Mitigation Measures 

In making its decision, DOE 

considered the environmental impacts 

of the proposed action and the no-action 

alternative on potentially affected 

environmental resource areas. These 

include: Air quality; greenhouse gas 

emissions; geology and soils; surface 

waters; ground water; terrestrial 

ecology; aquatic ecology; floodplains; 

wetlands; land use; socioeconomics; 

environmental justice; transportation; 

waste management; recreation; 

aesthetics and visual resources; cultural 

and historic resources; noise; and 

human health and safety. The EIS also 

considered the impacts from these 

facilities combined with those from 

other past, present and reasonably 

foreseeable future actions (i.e., 

cumulative impacts). The following 

sections discuss the potential impacts in 

these areas. 

Air Quality 

Construction of the power plant 

would generate fugitive dust, engine 

emissions, and other emissions that 

would result in localized air quality 


emcdonald on DSK2BSOYB1PROD with NOTICES
51252 Federal Register / Vol. 75, No. 160 / Thursday, August 19, 2010 / Notices 

impacts. Projected emissions from 

power plant operations are up to 590 

tons per year (tpy) SO2, 1,900 tpy NOX, 

470 tpy particulate matter less than or 

equal to 10 micrometers in aerodynamic 

diameter (PM10), 980 tpy carbon 

monoxide (CO), and lesser amounts of 

other pollutants. These emissions would 

potentially contribute to an increase in 

pollutant concentrations ranging from 

approximately 3 to 15 percent of the 

National Ambient Air Quality Standards 

(NAAQS) and from 12 to 71 percent of 

Prevention of Significant Deterioration 

(PSD) Class II increments. Plant 

emissions would have insignificant 

impacts on the closest PSD Class I area, 

which is 225 km (140 miles) away. For 

estimation of ambient impacts, all PM10

from combustion sources was assumed 

to be less than 2.5 micrometers (i.e., 

PM2.5). The power plant would also emit 

an estimated 1.8 to 2.6 million tpy of 

CO2 annually, as well as small amounts 

of other pollutants (e.g., 55 tpy of 

sulfuric acid mist and less than 0.1 tpy 

of mercury). In addition to CO2, much 

smaller emissions of other GHGs (e.g., 

nitrous oxide and methane) would be 

emitted from the IGCC plant and mine. 

Construction and operation of the 

lignite mine would generate fugitive 

dust emissions from areas cleared to 

facilitate mining; fugitive dust 

emissions from clearing, mining, and 

grading an average of 275 acres per year 

for as many as 40 years; fugitive dust 

emissions from off-road trucks and other 

vehicles traveling on internal, unpaved 

roads; point source emissions of 

particulate matter from transfer points at 

the lignite handling facilities; and 

criteria and hazardous air pollutant 

emissions from combustion of gasoline 

and diesel fuel in construction and 

operating equipment. These emissions 

would have localized impacts. 

During construction, use of modern, 

well-maintained machinery and 

vehicles meeting applicable emission 

performance standards would minimize 

emissions. Use of dust abatement 

techniques such as wetting soils, 

covering storage piles, and limiting 

operations during windy periods on 

unpaved, unvegetated surfaces would 

reduce airborne dust and resulting 

impacts. The distances of most 

construction-related activities from the 

nearest property boundary and 

residences would mitigate most 

potential impacts. EPA recommended, 

and DOE requires as a condition of its 

decision to provide financial assistance, 

measures to minimize diesel exhaust 

emissions from construction and 

operating equipment. These measures 

include using low-sulfur diesel fuel, 

properly equipping and maintaining 

diesel-fueled equipment, properly 

training operators, and employing safe 

work practices. 

Greenhouse Gas Emissions 

Mississippi Power will design the 

IGCC facility to capture approximately 

67 percent of the CO2 that would 

otherwise be emitted. The captured CO2

will be sent by pipeline for use in EOR. 

The project, operating at an 85-percent 

capacity factor (i.e., at full capacity), 

will emit approximately 1.8 million tpy 

of CO2 while burning lignite coal and 

firing natural gas in the duct burners. It 

will also emit small amounts 

(approximately 91,000 tpy of CO2

equivalents) of other GHGs. 

Based on a study of life cycle GHG 

emissions from IGCC power systems 

DOE estimates that plant support 

operations, maintenance, and lignite 

mining could increase annual GHG 

emissions attributable to the operation 

of the generating station by 

approximately 130,000 tons (for a total 

of approximately 2.0 to 2.8 million tons 

annually). Total emissions of GHGs 

from construction activities will be 

approximately 430,000 tons of CO2

equivalents (approximately 15 to 22 

percent of 1 year’s operating emissions). 

During its initial 6 months of operation, 

the plant may use coal delivered by 

truck from the Red Hills Mine. These 

temporary deliveries may result in an 

additional 4,400 tons of CO2 emissions. 

Most of the GHG emissions from coalmining operations will result from 

combustion of diesel fuel in mining 

equipment and off-road vehicles. The 

annual emissions of CO2 from mining 

operations were estimated at 

approximately 45,000 tons. These 

emissions represent less than 2 percent 

of the annual project’s emissions. DOE 

requires as a condition of its decision 

that the plant be designed and built to 

achieve 67 percent carbon capture and 

that the project proponents use best 

efforts to achieve 67 percent carbon 

capture during the demonstration 

period. 

Surface Waters 

No new process wastewater 

discharges are anticipated from the 

power plant. The plant will use 

reclaimed effluent from two publicly 

owned treatment works in Meridian, 

Mississippi, which will reduce flows in 

Sowashee Creek but also remove a 

source of pollutants that contribute to 

the creek’s impaired status. As many as 

32 miles of perennial stream channels 

and 24 miles of intermittent stream 

channels will be removed temporarily 

by construction and lignite extraction at 

the adjacent mine. The USACE 

maintains the avoidance, minimization 

and mitigation process in accordance 

with Section 404 of the CWA which 

includes the permit application 

evaluation process. This process 

includes implementation of the USACE 

stream evaluation process including an 

adverse impact analysis. If authorized 

by the USACE and upon completion of 

all mining and reclamation, the existing 

drainage patterns will be restored. The 

USACE will determine through its 

minimization evaluation process the 

number and length of streams, if any, to 

be mined and diverted. Aquatic 

communities in streams in Kemper 

County not physically disturbed by the 

mining operations would not be 

adversely affected based on the data 

collected at the Red Hills Mine. The 

water budget of Okatibbee Lake would 

not change significantly, meaning that 

the total volume of water flowing 

through the lake should remain within 

its historical range. The use of 

sedimentation ponds for water quality 

treatment will result in decreased peak 

flows following storm events. Water 

quality standards are not expected to be 

exceeded due to mine discharges. 

DOE requires, as a condition of its 

decision, that upstream and 

downstream water quality monitoring 

be conducted at appropriate locations in 

the mine area and in Okatibbee Lake to 

assess actual impacts. The monitoring 

parameters and details will be described 

in the MAP. In addition, DOE requires 

that the project proponents develop an 

adaptive environmental management 

plan in consultation with the USACE 

and MDEQ that establishes thresholds 

for implementing corrective measures in 

the event this monitoring detects 

adverse impacts. This plan would 

require the participants to mitigate 

adverse impacts to Okatibbee Lake and 

surrounding environments. 

Ground Water 

The power plant would use up to 1 

million gallons per day (mgd) of saline 

ground water from the Massive Sand 

aquifer. No adverse impacts to other 

users of the Massive Sand or other 

aquifers are anticipated from the 

drawdown caused by this use, because 

predicted drawdowns at a distance of 

0.5 mile from the supply well would be 

less than one foot for both peak shortterm and average long-term use. 

Construction and operation of the 

lignite mine would require ongoing pit 

water control. These operations could 

cause drawdown in the shallow Middle 

Wilcox aquifer and could adversely 

impact some local ground water wells 

depending on site-specific drawdown 

experienced and the specific 


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Federal Register / Vol. 75, No. 160 / Thursday, August 19, 2010 / Notices 51253 

circumstances of a given well (e.g., well 

depth, pump setting, etc.). It is possible 

that the amount of drawdown at a given 

well could cause diminution of supply. 

If an existing supply becomes unusable, 

alternative supplies will be provided by 

the North American Coal Company, the 

mine operator, as required by the 

surface mining regulations. No adverse 

effects on the Lower Wilcox aquifer are 

expected. 

Post-mining ground water quality in 

the reclaimed areas cannot be predicted 

with certainty. Based on experience at 

similar mines, ground water would 

likely have higher TDS than before 

mining. Therefore, development of 

future shallow freshwater wells in mine 

spoil deposits might not be feasible. 

However, sufficient fresh water would 

be available from the Lower Wilcox 

aquifer and public water systems during 

and after mining. 

Terrestrial Ecology 

As many as 1,085 acres of terrestrial 

ecological resources would be altered on 

the power plant site by construction of 

the plant and some mine-related 

facilities. Of this, approximately 419 

acres are currently in agricultural 

production, mostly in pine plantations, 

pasture, and hay fields. Most wildlife 

located within the construction area 

would relocate to suitable onsite or 

adjacent habitats; small, less mobile or 

burrowing animals might be lost. No 

federally listed plants or animals were 

observed on the site, nor are any known 

to occur there, although records exist for 

a few listed species in the surrounding 

region. Two State listed species, the 

sharp-shinned hawk and the barred owl, 

were observed on the sites of the power 

plant, mine or both, but adverse effects 

are not expected due to these birds’ 

mobility and the abundance of suitable 

habitat in the area. Construction and 

operation of the facilities on the power 

plant site are not expected to adversely 

affect either listed or migratory species. 

Mine site preparation and 

construction activities will result in 

sequential vegetation removal from most 

of the construction areas. 

Approximately 1,455 acres will be 

affected during the initial construction 

phase. Thereafter, existing terrestrial 

habitat will be cleared and reclaimed at 

an average rate of 275 acres per year. 

After mining, mine pits will be 

reclaimed and revegetated. As with the 

power plant site, mobile wildlife would 

likely relocate to adjacent, nonimpacted, or restored portions of the 

mine study area or to suitable offsite 

habitats. After reclamation, various 

wildlife species could return to 

reclaimed lands relatively quickly. 

Individuals of less mobile or burrowing 

species could be lost. No federally listed 

plants were observed in the mine study 

area, although Price’s potato bean may 

occur in the region. It is unlikely that 

regional populations of listed or 

migratory species will be adversely 

affected by mining. 

The primary impact to terrestrial 

resources from linear facility 

construction or upgrades will result 

from vegetation clearing; smaller 

temporary impacts will occur due to 

pipeline trenching. Construction of the 

linear facilities is not expected to 

adversely affect any endangered or 

threatened plant or wildlife 

populations, including migratory birds. 

With site clearing activities, there is 

the potential for introduction of 

invasive species. DOE requires as a 

condition of its decision that monitoring 

be conducted to determine whether 

invasive, exotic, or nuisance species 

occurrences are increasing as a result of 

project activities. If such occurrences 

are increasing as a result of the project, 

control and management steps will be 

required as specified in a Mitigation 

Action Plan (see ‘‘Mitigation’’). 

Aquatic Ecology 

The power plant is expected to have 

direct impact on only one surface water 

body. The diversion of effluent to the 

power plant currently being discharged 

from two publicly owned treatment 

works (POTWs) in Meridian to 

Sowashee Creek would reduce flows in 

the creek. But it would also remove a 

source of pollutants to the creek. 

Biological communities downstream of 

POTWs are commonly suppressed or 

altered due to water quality changes. A 

reduction of effluent discharge may 

mitigate the impacts of these changes on 

the aquatic communities. 

The lignite mine will displace aquatic 

habitat during active mining until 

habitat reclamation is completed. 

Diversion canals will temporarily 

replace the displaced aquatic habitat 

and provide habitat similar to existing 

streams and support similar biological 

communities. 

DOE requires, as a condition of its 

decision, that fish and 

macroinvertebrate sampling, as 

specified in the MAP, is conducted 

using appropriate EPA- or Mississippi 

Department of Environmental Quality 

(MDEQ)-approved bioassessment 

protocols to determine whether adverse 

effects on the aquatic ecosystem are 

resulting from the project. If significant 

adverse effects are detected, additional 

mitigation will be implemented to 

minimize these effects, as specified in 

the MAP (see ‘‘Mitigation’’). 

Floodplain Statement of Findings 

In accordance with 10 CFR part 1022 

(DOE regulations on Compliance with 

Floodplain and Wetland Environmental 

Review Requirements), DOE considered 

the potential impacts of the proposed 

project and its connected actions on 

floodplains. The portion of the IGCC site 

that will be used for permanent facilities 

is wholly located above the base and 

critical action floodplain. Construction 

and operation of the plant are expected 

to have no direct or indirect effect on 

floodplains. For the construction of 

linear facilities associated with the 

power plant, direct impacts to 

floodplains will result from clearing 

vegetation, particularly shrubs and 

trees, from the floodplain areas and 

stream banks. 

Also, depending upon final designs, 

electrical transmission tower supports 

could be constructed within the base 

floodplains and construction of the 

reclaimed effluent, natural gas, and CO2

pipelines may cause temporary direct 

impacts to the streams that are crossed. 

DOE has found no practicable 

alternative to locating these linear 

facilities in floodplain areas. It requires, 

as a condition of its decision, that 

floodplain impacts be minimized 

through construction methods and 

timing to the extent practicable. 

In addition to the potential floodplain 

impacts of the linear facilities, the 

connected action of developing the 

lignite mine will divert the flow in the 

Chickasawhay Creek during the initial 

years of mining within Mine Block A, 

which will disconnect the existing 

floodplain from the flow channel. Total 

storm-event runoff volumes could 

increase by up to 637 acre-feet (ac-ft). 

Okatibbee Lake, a multipurpose 

reservoir operated by the USACE and 

located approximately 5 miles 

downstream, has a summer flood 

storage capacity of 42,590 ac-ft and a 

winter flood storage capacity of 59,490 

ac-ft. The projected increase of 637 acft would be less than 1.2 percent of the 

winter flood storage capacity; also, peak 

flow rates are projected to decrease, 

minimizing the effect of the potential 

volume increase. Between 2038 and 

2055—well after DOE’s involvement— 

the mine developer may construct 

levees that could further affect 

floodplains. Conditions for avoidance, 

minimization, and mitigation during the 

period after DOE’s involvement would 

be established by the USACE and 

MDEQ. During the preparation of the 

Final EIS and as a result of preapplication consultations with the 

USACE, the North American Coal 

Company responded to DOE and 


emcdonald on DSK2BSOYB1PROD with NOTICES
51254 Federal Register / Vol. 75, No. 160 / Thursday, August 19, 2010 / Notices 

USACE comments by revising the mine 

development plan. Four separate mine 

plans were analyzed and the alternative 

finally selected should minimize 

potential wetland and floodplain 

impacts compared to the other 

practicable mine plans. However, this 

avoidance and minimization would 

result in approximately 10.0 million 

tons of lignite remaining in the ground. 

Also, long-term operational costs would 

increase as a result of having to mine 

lignite from higher ratio (overburden to 

lignite) reserves with less favorable 

recovery economics. DOE has found no 

practicable alternative to mine 

development that would further avoid 

or minimize impacts to floodplains. 

Wetlands 

There could be impacts to as many as 

2,971 acres of wetlands if the USACE 

authorizes the activities that would 

affect wetlands: 104 acres for power 

plant facilities on the power plant site; 

25 acres for mine facilities on the power 

plant site; 2,375 acres in proposed 

mining blocks; and 467 acres within the 

linear facility corridors. The linear 

facility impacts would most likely be 

temporary, as they would result from 

construction or other short-term 

conversions of habitat. The remaining 

impacts may be permanent. 

Approximately 129 acres of wetlands 

and streams could be lost or altered by 

construction activities associated with 

the power plant and mining facilities 

located on the power plant site. All of 

these impacts could be permanent. If 

authorized by the USACE, impacts will 

require mitigation in accordance with 

the Clean Water Act (CWA) under 

Section 404 permit requirements such 

that existing functional values of 

impacted wetlands are replaced. 

Adverse impacts to as many as 2,375 

acres of wetlands that lie within the 

anticipated life-of-mine area are 

expected over the 40-year life-of-mine. 

Any wetland impacts will require CWA 

Section 404 permit authorization, which 

could require onsite mitigation (both on 

reclaimed mined lands and in adjoining 

upland areas not disturbed by mining), 

offsite mitigation, or a combination of 

both. Based on mitigation at other mine 

sites in the region, wetland functions 

would, after reclamation, be expected to 

return over time, as natural revegetation 

(or planting) and succession occur and 

wetland hydrology is restored. Longterm monitoring of this process is 

required by both the USACE and MDEQ. 

Within the linear facilities corridors, 

wetlands will be impacted primarily by 

conversion (partial clearing) of forested 

and some shrub-dominated wetlands for 

construction of linear facilities. As 

many as 400 acres of wetlands and 67 

acres of other waters (streams, ditches, 

and ponds) could potentially be 

impacted by linear facilities 

construction. Most impacts will be 

conversion of forested and possibly 

shrub-dominated wetlands to shruband herbaceous-dominated wetland 

systems and all impacts would most 

likely be temporary. DOE has found no 

practicable alternative to these impacts 

on wetlands and it requires as a 

condition of its decision that any 

wetland impacts be avoided until the 

USACE finalizes its permit application 

evaluation process in accordance with 

Section 404 of the CWA. If a permit is 

authorized by the USACE, mitigation 

plans must be consistent with 33 CFR 

part 332, Compensatory Mitigation for 

Losses of Aquatic Resources. The 

USACE will determine the specifics of 

the mitigation requirements during the 

Department of the Army permit 

application evaluation process in 

accordance with 33 CFR 325. 

Socioeconomics and Environmental 

Justice 

Project development is expected to 

result in positive direct and indirect 

effects through ad valorem taxes, sales 

tax proceeds from employee spending, 

and sales tax proceeds for purchases of 

equipment and services. Beyond the 

estimated combined construction 

payroll for the plant and mine of $145 

million, there is an estimated additional 

indirect benefit of $82 million and 186 

additional jobs due to construction 

activities. The corresponding numbers 

for the operation of the plant and mine 

are an estimated $25 million combined 

annual payroll, an indirect annual 

benefit of about $11.4 million, and 

approximately 97 additional jobs. 

Project development may impact 

housing availability during 

construction, but sufficient housing is 

likely to be available. 

The power plant and mine are located 

in census tracts that have a higher 

percentage of minorities and a higher 

percentage of population below the 

poverty level than other census tracts 

within a 7-mile radius around the plant 

and in the State as a whole. Therefore, 

DOE has concluded that an 

environmental justice population exists, 

and has examined the potential for 

‘‘disproportionately high and adverse’’ 

health or environmental effects 

consistent with Executive Order 12898. 

The potential effects analyzed included 

health impacts from air emissions and 

accidental releases, displacement of 

landowners due to the development of 

the mine, effects on ground water wells, 

transportation impacts, housing 

availability, aesthetics, and noise levels 

in sensitive areas. Based on an analysis 

of these potential effects, DOE has 

determined that construction and 

operation of the facilities are not likely 

to result in disproportionately high and 

adverse impacts and burdens on an 

environmental justice community. 

Transportation 

The area roadways connecting to the 

existing population centers are adequate 

to accommodate the anticipated traffic 

during construction and operation. 

Local roads in proximity to the power 

plant will experience impact in the form 

of degraded level of service during both 

construction and operation. Heavy haul 

routes in proximity to the plant will 

require evaluation for weight and other 

limitations. The initial coal hauling 

route from the Red Hills Mine to the 

plant site may experience as many as 80 

trucks per day spread over a 16-hour 

day for a period of approximately six 

months. There will be an increase in 

traffic on area roadways resulting in a 

potential increase in accidents and 

injuries. The increase in truck traffic 

during the operations involving 

transport of lignite from the Red Hills 

Mine would be especially severe. DOE 

requires, as a condition of its decision, 

mitigation to minimize these impacts as 

described in the MAP. 

Cultural and Historic Resources 

Construction of the proposed power 

plant could impact one onsite historic 

resource (a house dating from 

approximately 1900). Mining could 

impact cultural resources which have 

yet to be evaluated in terms of value. 

Mining of future mine blocks and 

construction of linear facilities would 

likely impact several sites that have 

been assessed as potentially eligible for 

listing. Cultural resources will be 

avoided to the extent practicable when 

siting facilities. Evaluation and 

appropriate resource recovery will be 

guided by the terms of a project-specific 

programmatic agreement, which has 

been developed to satisfy Section 106 of 

the National Historic Preservation Act. 

The agreement has been signed by DOE, 

the USACE, the Mississippi Department 

of Archives and History, MDEQ, the 

Mississippi Band of Choctaw Indians, 

the Choctaw Nation of Oklahoma, 

Mississippi Power Company, North 

American Coal Company, and Southern 

Company Services. The programmatic 

agreement is a condition of DOE’s 

decision to provide financial assistance. 

Noise 

Power plant construction noise would 

be temporary but noticeable at several 


emcdonald on DSK2BSOYB1PROD with NOTICES
Federal Register / Vol. 75, No. 160 / Thursday, August 19, 2010 / Notices 51255 

1The NO2 standard is currently under judicial 

review. See American Petroleum Inst. v. EPA, No. 

10–1079 (D.C. Cir. Apr. 13, 2010). 

nearby residences. With one exception, 

the highest levels experienced by 

residents would be no louder than 

maximum levels from passing vehicular 

traffic. Steam blows that will be 

necessary over several days near the end 

of plant construction could potentially 

reach levels of annoyance to persons 

outdoors at the closest residences. DOE 

requires as a condition of its decision 

that Mississippi Power Company notify 

affected residents prior to the steam 

blow operation. 

Noise associated with power plant 

operation is expected to result in an 

impact of 57 A-weighted decibels (dBA) 

at one adjacent residence, exceeding the 

U.S. Environmental Protection Agency 

residential guideline of 55 dBA but less 

than the Department of Housing and 

Urban Development residential 

guideline of 65 dBA. Mississippi Power 

is pursuing acquisition of most of the 

residential properties near the plant site, 

including the property where the 

highest noise impacts have been 

predicted. Mining would also result in 

localized noise impacts, primarily in the 

area surrounding the active mine block. 

An appropriate level of sound control 

will be designed into facility equipment 

to limit operational noise levels. In 

addition, DOE requires as a condition of 

its decision that noise from the loudest 

pieces of equipment be reasonably 

controlled to mitigate impacts as 

specified in the MAP. 

Human Health and Safety 

Construction of all of the facilities 

poses hazards typical of any large 

industrial construction project. Health 

and safety risks will accompany the 

construction efforts and could affect 

local residents as well as construction 

workers. Some injuries to construction 

workers are likely, as indicated by 

industry statistics. Operations of the 

project facilities entail risks as well, 

given the nature of the facilities and 

based on industry statistics. 

The IGCC power plant would emit a 

maximum of 18.5 tpy of hazardous air 

pollutants (HAPs). Modeling studies 

found that these HAPs should not result 

in or contribute significantly to 

inhalation health risks. The total cancer 

risk was predicted to be less than one 

in a million (the level below which 

exposures are generally considered to be 

acceptable). The noncancer risks are 

estimated to be below levels considered 

to have adverse health effects. Similarly, 

health risks from mercury emitted from 

the IGCC stacks are expected to be 

below levels of concern. DOE requires 

as a condition of its decision that the 

project proponents characterize IGCC 

stack emissions of HAPs as specified in 

the MAP. 

The emissions of criteria pollutants 

could affect the overall mortality and 

morbidity of the surrounding 

population. The possible effects were 

estimated at less than one additional 

death per year and the lost days of life 

per person were predicted to be much 

less than one. The annual increase in 

hospital admissions, incidence of adult 

bronchitis, asthma hospital admissions, 

and asthma emergency room visits were 

all predicted to be less than one per 

year. The average annual number of 

asthma attacks among asthmatics, work 

loss days, and restricted activity days 

for the entire population were 

conservatively predicted to increase by 

26, 56, and 298 occurrences, 

respectively. 

Additional health and safety risks 

could result from the handling, storage, 

and transport of hazardous materials, 

including ammonia and CO2, due to an 

accidental release or intentional act of 

sabotage or terrorism. A catastrophic 

rupture of an ammonia storage tank or 

tanker truck could potentially cause 

severe health effects up to 1.7 and 1.2 

miles from the accident, respectively. A 

complete rupture of the CO2 pipeline 

would potentially result in adverse 

health effects to exposed persons within 

0.7 mile of the accident. Population 

levels along the pipeline corridor are 

low, and given the limited extent of the 

affected area, it is unlikely that an 

accident would result in injuries. All of 

these results were based on the most 

severe reasonably foreseeable scenarios. 

Potential Environmental Impacts of the 

No-Action Alternative 

Under the no-action alternative, DOE 

assumed there would be no 

development at the site, since there are 

no other reasonably foreseeable plans 

for development. Therefore, the impacts 

under the no-action alternative (i.e., no 

development) were evaluated in the EIS 

and compared to the proposed action. 

There would be no new sources of air 

emissions affecting air quality; there 

would be no changes in existing 

hydrologic conditions and no alterations 

of stream flow, path, and water quality; 

existing impaired habitats and low 

diversity aquatic communities would 

remain; and there would be no 

alteration or loss of existing floodplains, 

floodplain storage, or flood conveyance 

capacity. There would be no change in 

existing socioeconomic conditions, no 

potential for economic stimulus from 

proposed project, and no change in 

existing conditions relative to 

community services; no change in 

existing conditions relative to 

environmental justice populations and 

no potential for adverse impacts or 

economic benefits from the proposed 

project. There would be no change in 

existing vehicular traffic and level of 

service conditions would remain the 

same; potentially affected cultural 

resources would remain in place and 

not be recovered; no new sources of 

noise would be built and operated; and 

there would be no added health and 

safety risks. Increased emissions of 

greenhouse gases would likely still 

occur, but these increases would 

depend on the technology that would be 

used to generate the power that would 

have been provided by the project. 

Environmentally Preferred Alternative 

The no-action alternative is 

environmentally preferable because it 

would result in no change to the 

existing environmental conditions. 

Comments Received on the Final EIS 

DOE received comments on the Final 

EIS from two Federal agencies: EPA’s 

Region 4 (EPA) and the Department of 

the Interior (DOI). DOE did not receive 

any other comments on the Final EIS. 

EPA’s comments supported selection of 

the IGCC technology but noted there are 

environmental concerns inherent to any 

power plant and mining operations. The 

specific concerns in EPA’s comments 

involved air quality impacts, climate 

change issues, impacts to waters of the 

United States, bioaccumulation of 

mercury, effluent discharges, impacts to 

drinking water supplies, effects on 

housing availability and cost for 

environmental justice populations, and 

mitigation of the effects of increased 

traffic. DOI’s comments focused on 

impacts to aquatic resources. 

EPA’s comments on air quality 

impacts were related to the new 1-hour 

National Ambient Air Quality Standards 

(NAAQSs) for NO2 (100 parts per 

billion, or ppb) and SO2 (75 ppb). Due 

to the timing of the issuance of these 

new standards and of the Final EIS, it 

was not possible to address these new 

standards in the EIS. The conclusion in 

the Final EIS that NAAQSs would not 

be exceeded was based on modeling 

done for MDEQ’s air permitting process, 

a process that was completed before the 

new NO2 standard became effective on 

April 12, 2010.1 The SO2 standard will 

not become effective until August 23, 

2010. In response to EPA’s comment 

that information on the project’s 

impacts as to these new standards 

should be provided, DOE conducted a 


emcdonald on DSK2BSOYB1PROD with NOTICES
51256 Federal Register / Vol. 75, No. 160 / Thursday, August 19, 2010 / Notices 

2One converts tons of carbon to tons of carbon 

dioxide using the ratio of the molecular weights of 

the two substances (44/12). 

conservative screening-level analysis 

and found that the project would have 

a maximum impact of 41 ppb (1-hour 

average) of NO2 and 36 ppb (1-hour 

average) of SO2. These new standards 

for NO2 and SO2 are likely to result in 

revisions to Mississippi’s State 

Implementation Plan under the Clean 

Air Act. The State would assess air 

quality levels within the State and 

identify any areas that fail to comply 

with these standards. Mississippi would 

need to design and implement control 

strategies for these ‘‘nonattainment 

areas’’ that would bring them into 

compliance with the new NAAQSs for 

NO2 and SO2. This statutory process for 

State implementation of new NAAQSs 

would include any monitoring or more 

refined modeling that MDEQ determines 

is needed to ensure compliance with 

these standards. 

As to climate change issues, EPA 

questioned the use of 0.3 to 2.1 metric 

tons of carbon per acre per year for 

estimating lost sequestration potential 

and suggested using a value of 1.1 to 7.7 

tons of carbon dioxide. In fact, 2.1 

metric tons of carbon per year is 

equivalent to 7.7 tons of carbon dioxide 

per year.2 EPA also requested a 

reference for the 1 metric ton 

sequestration potential difference 

between forest and grassland. That 

figure was obtained from ‘‘Greenhouse 

Gas Mitigation Potential in U.S. Forestry 

and Agriculture’’ (EPA 430–R–05–006). 

EPA expressed concern about impacts 

to waters of the United States, in 

particular impacts to perennial streams, 

adjacent wetlands, and their buffers that 

have the potential to negatively impact 

Okatibbee Lake. DOE agrees that, to the 

extent practicable, ‘‘avoidance and 

minimization of impacts should be fully 

realized’’ in the permitting process 

under Section 404 of the Clean Water 

Act and the regulations that implement 

it (40 CFR part 230). However, complete 

avoidance, as suggested in EPA’s 

comment, of all such impacts may not 

be practicable. Monitoring of the mine’s 

downstream water quality and volume 

effects on the lake, as recommended by 

EPA, as well as development of an 

adaptive management plan in 

consultation with the USACE, are 

conditions of DOE’s decision and will 

be included in the MAP. EPA also 

expressed its views on Section 404 

permit conditions (e.g. conditioning 

subsequent permits on the success of 

mitigation, appropriate use of site 

protection instruments, use of 

mitigation banks or establishment of a 

single user bank, and compliance with 

the USACE and EPA Mitigation Rule). 

However, these concerns are more 

appropriately addressed to the USACE, 

the agency responsible for 

implementing Section 404 of the Clean 

Water Act, rather than to DOE. With 

regard to bioaccumulation of mercury, 

EPA appreciated DOE’s responses to its 

comments on the Draft EIS and 

recommended that DOE coordinate with 

MDEQ on updated fish tissue sampling 

data. DOE concluded in the Final EIS 

that the incremental contribution to 

health hazards associated with mercury 

uptake from the project was small 

compared to ambient conditions. As 

requested by EPA, DOE consulted with 

MDEQ and has determined that, 

although more recent laboratory data 

have been collected by MDEQ, no 

additional analysis is necessary to 

support DOE’s conclusion. 

EPA also stated that impacts of the 

project should be monitored as the 

project progresses, specifically noting 

that effluent discharges will be 

regulated under the National Pollutant 

Discharge Elimination System and the 

MDEQ Surface Mine Control and 

Reclamation Act permit. DOE requires 

as a condition of its decision that the 

project comply with all permit 

requirements, including monitoring 

requirements. Also, with respect to 

monitoring, EPA recommended that 

monitoring of impacts to drinking water 

sources be conducted and that DOE’s 

ROD include measures to ensure the 

quality of drinking water supplies. DOE 

requires the participants to conduct 

such monitoring and mitigation as a 

condition of its decision. The required 

measures will be described in the MAP. 

With regard to environmental justice, 

EPA requested that the potential 

impacts on housing and transportation 

be acknowledged and that potential 

mitigation measures (i.e. housing or 

rental assistance) be identified in the 

ROD. DOE’s analysis of potential 

impacts to environmental justice 

populations concluded that there would 

not be disproportionately high and 

adverse impacts. However, DOE 

acknowledges that there is always the 

possibility of unanticipated or 

unforeseeable impacts. Therefore, DOE 

requires as a condition of its decision 

that housing availability be monitored 

and information on its availability, cost, 

utility costs, and potential sources of 

assistance be provided as described in 

Mississippi Power’s Kemper County 

Community Plan. EPA commended this 

Community Plan and encouraged 

Mississippi Power to continue to 

provide opportunities for community 

engagement and to pursue a strategy of 

employment and training opportunities 

for the local population. DOE agrees and 

also encourages Mississippi Power to 

continue and expand its community 

outreach activities. 

Regarding transportation impacts, 

EPA recommended that DOE consult 

with the Mississippi Department of 

Transportation and the Federal Highway 

Administration on the development of 

mitigation measures. DOE has contacted 

both agencies and has identified 

mitigation measures that it will include 

in the Mitigation Action Plan. 

DOI expressed its views on the 

impacts to aquatic resources from the 

power plant and mine, noting that there 

are two separate Section 404 permit 

applications before the USACE. DOI 

stated that, for the power plant, impacts 

to wetlands and streams have been 

minimized and adequate compensatory 

mitigation has been proposed. DOI also 

restated its determination in a letter 

dated January 14, 2010, to the USACE 

that the lignite mine would have 

substantial and unacceptable impacts on 

aquatic resources of national importance 

and recommended that all lost wetland 

functions and values be mitigated at a 

suitable offsite area within the 

watershed. DOE recognizes that DOI 

considers the current mitigation plan 

proposed by the North American Coal 

Company for the mine to be inadequate. 

DOE expects that additional avoidance 

and minimization, as well as 

appropriate mitigation consistent with 

the applicable Mitigation Rule, will be 

developed through USACE’s Section 

404 permit application evaluation 

process, in consultation with the U.S. 

Fish and Wildlife Service, EPA and 

MDEQ. Compliance with the 

requirements of the Section 404 permit 

(if authorized), as well as all other 

applicable permits, is a condition of 

DOE’s decision. 

Issued in Washington, DC, on this 12th day 

of August 2010. 

James J. Markowsky, 

Assistant Secretary, Office of Fossil Energy. 

[FR Doc. 2010–20565 Filed 8–18–10; 8:45 am] 

BILLING CODE 6450–01–P 


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