Record of Decision and Floodplain Statement of Findings; Kemper County IGCC Project, Kemper County, MS, 51248-51256 [2010-20565]
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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 https://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
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recommendations on issues including
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and disposal of civilian and defense
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The Co-chairs of the Commission
requested the formation of the Disposal
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Purpose of the Meeting: The meeting
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Tentative Agenda: The meeting is
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September 1, 2010 with panel
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Public Participation: Subcommittee
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speak but will not exceed 5 minutes.
The Designated Federal Officer is
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Minutes: The minutes of the meeting
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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
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
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topics of interest.
Public Participation: The meeting is
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the public who wish to make oral
statements pertaining to agenda items
should contact Gary Burch at the
address or telephone number listed
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Minutes: The minutes of the meeting
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copying within 60 days on the STEAB
Web site, https://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]
State Energy Advisory Board (STEAB)
BILLING CODE 6450–01–P
Department of Energy.
ACTION: Notice of open teleconference.
DEPARTMENT OF ENERGY
AGENCY:
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
SUMMARY:
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Record of Decision and Floodplain
Statement of Findings; Kemper County
IGCC Project, Kemper County, MS
U.S. Department of Energy.
Record of Decision and
Floodplain Statement of Findings.
AGENCY:
ACTION:
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 cost-
SUMMARY:
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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.
The Final EIS is available
on the DOE National Environmental
Policy Act (NEPA) Web site at https://
www.nepa.energy.gov/1445.htm and on
the DOE National Energy Technology
Laboratory (NETL) Web site at https://
www.netl.doe.gov/technologies/
coalpower/cctc/ccpi/bibliography/
demonstration/adv-gen/ccpi_285mw.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.
ADDRESSES:
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.
FOR FURTHER INFORMATION CONTACT:
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.
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SUPPLEMENTARY INFORMATION:
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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
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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.
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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.
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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
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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
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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 https://
www.netl.doe.gov/technologies/
coalpower/cctc/ccpi/bibliography/
demonstration/adv-gen/ccpi_285mw.html. Once the selection process
complete, the reasonable alternatives are
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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 25percent 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 50percent capture. Air quality impacts
vary slightly between the 50- and 67percent 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
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‘‘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
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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
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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
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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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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.
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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’’).
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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
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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
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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
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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
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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.
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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
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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
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51255
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
1 The NO standard is currently under judicial
2
review. See American Petroleum Inst. v. EPA, No.
10–1079 (D.C. Cir. Apr. 13, 2010).
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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
2 One converts tons of carbon to tons of carbon
dioxide using the ratio of the molecular weights of
the two substances (44/12).
VerDate Mar<15>2010
17:05 Aug 18, 2010
Jkt 220001
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
PO 00000
Frm 00019
Fmt 4703
Sfmt 9990
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
E:\FR\FM\19AUN1.SGM
19AUN1
Agencies
[Federal Register Volume 75, Number 160 (Thursday, August 19, 2010)]
[Notices]
[Pages 51248-51256]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2010-20565]
-----------------------------------------------------------------------
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
cost-
[[Page 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 https://www.nepa.energy.gov/1445.htm and
on the DOE National Energy Technology Laboratory (NETL) Web site at
https://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 e-mail: 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
non-governmental 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)
[[Page 51250]]
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 cost-effective 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 TRIG\TM\
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
[[Page 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 https://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 no-action 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
[[Page 51252]]
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 coal-mining 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 short-term 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
[[Page 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, non-
impacted, 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 ac-ft 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 pre-application
consultations with the USACE, the North American Coal Company responded
to DOE and
[[Page 51254]]
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.
Long-term 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 shrub- and 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
[[Page 51255]]
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
[[Page 51256]]
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.
---------------------------------------------------------------------------
\1\ The NO2 standard is currently under judicial
review. See American Petroleum Inst. v. EPA, No. 10-1079 (D.C. Cir.
Apr. 13, 2010).
---------------------------------------------------------------------------
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).
---------------------------------------------------------------------------
\2\ One converts tons of carbon to tons of carbon dioxide using
the ratio of the molecular weights of the two substances (44/12).
---------------------------------------------------------------------------
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