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Contact Information:
Department of Health and Environmental Control
2600 Bull Street
Columbia, SC 29201
Or view the Department's
Website
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SOUTH CAROLINA
June 24, 2005
South Carolina's Department of Health and Environmental Control recently came out with changes to their Air Pollution Control Regulations and Standards which, are effective June 24, 2005.
These revisions primarily clarify definitions and there are some changes to the standards involving Prevention of Significant Deterioration.
Under the new standards a project is considered to be a major modifciation and triggers NSR if the pollutant causes a significant emissions increase and also a significant net emissions increase. A consecutive 24-month period is used to determine the baseline actual emissions from a facility. For ozone, there is no de minimis exemption. The revised rules are found at
AIR EMISSIONS CONTROL REGULATIONS AND STANDARDS:
DE MINIMIS EXEMPTIONS:
The state has an exemption for boilers that are 1.5 MMBtu/hr or smaller and burning virgin fuel. A letter to
the state is required. There are no other exemptions.
NITROGEN OXIDE (NOx) REGULATIONS:
Regulation 61-62.5.2 Control of Oxides of Nitrogen
A) Any new source that is permitted after the effective date of this regulation
B) Any existing source where a burner assembly is replaced with another assembly after the effective date
of this regulation, regardless of size or age of the burner assembly replaced. (Note: A self-contained chamber such
as is found on a combustion turbine is not a burner assembly for the purposes of this regulation)
C) Any existing source that is removed from its presently permitted facility and moved to another
permitted facility after the effective date of this regulation except process equipment and commercial
or industrial boilers that are transferred between facilities within the state under common ownership.
Exemptions:
A) Any source less than 10 MMBtu/hr rated input capacity that burns a fuel.
B) Emergency power generators of less than 150 kW rated capacity, or those that operate 250 hours per year
or less and have a method to record the actual hours of use such as an hour meter.
C) Any internal combustion engine with a mechanical power output less than 200 bHP
D) Combustion sources that operate at a capacity less than 10% per year.
Natural Gas Fired Boilers
| > 10 MMBtu/hr and < 100 MMBtu/hr |
Low NOx Burners or equivalent technology capable of achieving 30
ppmv @ 3% O2 Dry (0.036 lb/MMBtu) |
| > 100 MMBtu/hr |
Low NOx Burners + Flue Gas Recirculation or equivalent technology capable of achieving 30
ppmv @ 3% O2 Dry (0.036 lb/MMBtu) |
Distillate Oil Fired Boilers
| > 10 MMBtu/hr and < 100 MMBtu/hr |
Low NOx Burners or equivalent technology capable of achieving 0.15
lb/MMBtu |
| > 100 MMBtu/hr |
Low NOx Burners + Flue Gas Recirculation or equivalent technology capable of achieving
0.14 lb/MMBtu |
Residual Oil Fired Boilers
| > 10 MMBtu/hr and < 100 MMBtu/hr |
Low NOx Burners or equivalent technology capable of achieving
0.3 lb/MMBtu |
| > 100 MMBtu/hr |
Low NOx Burners + Flue Gas Recirculation or equivalent technology capable of achieving
0.3 lb/MMBtu |
Internal Combustion Engines
| Compression Ignition |
Timing Retard <4° + Turbocharger w/Intercooler or
equivalent technology capable of achieving 490 ppmv @ 15% O2 (7.64 g/bhp-hr) |
| Spark Ignition |
Lean Burn Technology or equivalent technology capable of achieving
1.0 g/bhp-hr |
| Landfill or Digester Gas Fired |
Lean Burn Technology or equivalent technology capable of achieving
1.25 g/bhp-hr |
Gas Turbines -- Simple Cycle Natural Gas Fired
| < 50 MW |
Combustion Modifications (e.g. dry low NOx combustors)
to minimize NOx emissions or equivalent technology capable of achieving 25
ppmv @ 15% O2 Dry (0.054 lb/MMBtu) |
| > 50 MW |
Combustion Modifications (e.g. dry low NOx combustors)
to minimize NOx emissions or equivalent technology capable of achieving 9.0
ppmv @ 15% O2 Dry (0.033 lb/MMBtu) |
Gas Turbines -- Combined Cycle Natural Gas Fired
| < 50 MW |
Dry low NOx Combustors or equivalent technology
capable of achieving 9.0 ppmv @ 15% O2 Dry (0.033 lb/MMBtu) |
| > 50 MW |
Dry low NOx Combustors + SCR or equivalent technology
capable of achieving 3.0 ppmv @ 15% O2 Dry (0.011 lb/MMBtu) |
Gas Turbines -- Simple Cycle Distillate Oil Fired
| < 50 MW |
Combustion modifications and water injection to minimize
NOx emissions or equivalent technology capable of achieving 42.0 ppmv
@ 15% O2 Dry basis (0.16 lb/MMBtu) |
| > 50 MW |
Combustion modifications and water injection to minimize
NOx emissions or equivalent technology capable of achieving 42.0 ppmv
@ 15% O2 Dry basis (0.16 lb/MMBtu) |
Gas Turbines -- Combined Cycle Distillate Oil Fired
| < 50 MW |
Dry Low NOx Combustors with water injection, or
equivalent technology capable of achieving 42.0 ppmv @ 15% O2 Dry basis
(0.16 lb/MMBtu) |
| > 50 MW |
Dry Low NOx Combustors, water injection, and SCR or
equivalent technology capable of achieving 10.0 ppmv @ 15% O2
(0.038 lb/MMBtu) |
| Landfill Gas Fired |
Water or steam injection or low NOx turbine design or
equivalent technology capable of achieving 25.0 ppmv @ 15% O2 Dry basis
(0.097 lb/MMBtu) |
(***END NOTE***)
MINOR SOURCE PERMITTING:
The state enforces a 20% opacity limit and PM limits based on the unit's production rate. The state is likely to
require ambient impact modeling, however no controls are likely.
There is a 30-day public comment period for sources with a potential to emit greater than 100 tons per year
of a criteria pollutant. The entire permitting process takes up to 90 days to complete.
MAJOR NSR/PSD PERMITTING:
A potential to emit 250 tons per year of a criteria pollutant triggers PSD.
TREATMENT OF EMERGENCY ENGINES:
If a unit is either less than 150 kW or operating less than 250 hr/year for maintenance AND only operating
during emergencies then the unit is exempt from permitting. There is no limit on emergency operation, however the
unit must keep records of operation. An exemption is obtained by submitting a request to the state and receiving
an approval.
The Utility Facility Siting and Environmental Protection Act states that all major utility facilities, defined
as all electric generating plants of 75 MW or greater require a certificate issued by the Public Service
Commission. Although the original design did not specifically mention utility versus non-utility facilities and
appears to have been designed for utility facilities, the Act was written in such a way that it is applicable to
both utility and non-utility electrical generation facilities.
South Carolina Building Codes Council
In the state of South Carolina, the Building Codes Council is responsible for adopting and enforcing the state's
building and fire codes.
Local jurisdictions are restricted from promulgating their own building codes, in whole or in part or
adopting building codes not authorized by the Council.
Building Codes are required by law to be reviewed by the Building Codes Council before they may be adopted
for use at the local level. The building codes that must be adopted and used in all jurisdictions in the
State of South Carolina are listed below:
The 2006 Edition of the International Building Code
The 2006 Edition of the International Fire Code
The 2006 Edition of the International Plumbing Code
The 2006 Edition of the International Mechanical Code
The 2006 Edition of the International Fuel Gas Code
The 2000 Edition of the International Energy Conservation Code
The 2006 Edition of the International Residential Code
The 2005 Edition of the National Electrical Code to be adopted by local jurisdictions no later than July 1,
2007.
The Building Energy Efficiency Standards Act is adopted by statute and mandatory for use in all
jurisdictions within the state.
Notice of Intent to adopt the 2006
International Building Code
International Code Council State Adoption Information Page
Provides an easy to use US map to locate state and local adoption of the International Code Council's model codes.
US DOE's Office of Building Technology, State and Community Programs, Building Codes Database
The US DOE's database provides a comprehensive look at a state's building code implementation and enforcement
process.
Duke Energy
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Schedule PG (SC) Parallel Generation
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| Interconnected To |
Transmission System |
Distribution System |
| Customer Charge |
$53.76 per month |
$53.76 per month |
| On-Peak Demand Charge per On-peak month |
$13.24 per kW |
$15.77 per kW |
| Energy Charge |
All On-Peak Energy per month:
2.4960 cents per kWh
All Off-Peak Energy per month:
2.3025 cents per kWh
|
All On-Peak Energy per month:
2.5673 cents per kWh
All Off-Peak Energy per month:
2.3740 cents per kWh
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| Standby Charge per month |
$0.95 per kW |
$0.95 per kW |
**Rate only available to non-residential establishments, which have generating facilities not in excess of (80) megawatts
which are interconnected with the Company's system.
****Special Note: These are the Standby Rates in effect at the time of the creation of this database. For the most
current utility standby rates, click on the utility's name in the box named "Major Utilities" in the upper left-hand corner of this page.
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