EEA Database on Distributed Generation

WHAT'S NEW:

No recent state activity has been identified.

The state has an exemption for boilers that are 1.5 MMBtu/hr or smaller and burning liquid virgin fuel and 10 MMBtu/hr for sources burning gaseous virgin fuel. A letter to the state is required. Sources with actual uncontrolled emissions of less than 1 lb/hr each of SO2, NOx, and CO and 1000 lb/mo of VOC are exempt from permitting.

NITROGEN OXIDE (NO x) REGULATIONS:

Regulation 61-62.5.2 Control of Oxides of Nitrogen: This rule may be applicable to certain DG units. It requires control of sources that have NOT gone through state BACT review and that meet the following additional criteria.

Any new source that is permitted after the effective date of this regulation (June 25, 2004).
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)
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 to this rule:

Any source less than 10 MMBtu/hr rated input capacity that burns a fuel.
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.
Any internal combustion engine with a mechanical power output less than 200 bhp
Combustion sources that operate at a capacity less than 10% per year.

A summary of the NOx standards and associated control technology follows:

Natural Gas Fired Boilers

> 10 MMBtu/hr and < 100 MMBtu/hr	Low NO x Burners or equivalent technology capable of achieving 30 ppmv @ 3% O 2 Dry (0.036 lb/MMBtu)
> 100 MMBtu/hr	Low NO x Burners + Flue Gas Recirculation or equivalent technology capable of achieving 30 ppmv @ 3% O 2 Dry (0.036 lb/MMBtu)

Distillate Oil Fired Boilers

> 10 MMBtu/hr and < 100 MMBtu/hr	Low NO x Burners or equivalent technology capable of achieving 0.15 lb/MMBtu
> 100 MMBtu/hr	Low NO x 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 NO x Burners or equivalent technology capable of achieving 0.3 lb/MMBtu
> 100 MMBtu/hr	Low NO x 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% O 2 (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 NO x combustors) to minimize NO x emissions or equivalent technology capable of achieving 25 ppmv @ 15% O 2 Dry (0.054 lb/MMBtu)
> 50 MW	Combustion Modifications (e.g. dry low NO x combustors) to minimize NO x emissions or equivalent technology capable of achieving 9.0 ppmv @ 15% O 2 Dry (0.033 lb/MMBtu)

Gas Turbines -- Combined Cycle Natural Gas Fired

< 50 MW	Dry low NO x Combustors or equivalent technology capable of achieving 9.0 ppmv @ 15% O 2 Dry (0.033 lb/MMBtu)
> 50 MW	Dry low NO x Combustors + SCR or equivalent technology capable of achieving 3.0 ppmv @ 15% O 2 Dry (0.011 lb/MMBtu)

Gas Turbines -- Simple Cycle Distillate Oil Fired

< 50 MW	Combustion modifications and water injection to minimize NO x emissions or equivalent technology capable of achieving 42.0 ppmv @ 15% O 2 Dry basis (0.16 lb/MMBtu)
> 50 MW	Combustion modifications and water injection to minimize NO x emissions or equivalent technology capable of achieving 42.0 ppmv @ 15% O 2 Dry basis (0.16 lb/MMBtu)

Gas Turbines -- Combined Cycle Distillate Oil Fired

< 50 MW	Dry Low NO x Combustors with water injection, or equivalent technology capable of achieving 42.0 ppmv @ 15% O 2 Dry basis (0.16 lb/MMBtu)
> 50 MW	Dry Low NO x Combustors, water injection, and SCR or equivalent technology capable of achieving 10.0 ppmv @ 15% O 2 (0.038 lb/MMBtu)
Landfill Gas Fired	Water or steam injection or low NO x turbine design or equivalent technology capable of achieving 25.0 ppmv @ 15% O 2 Dry basis (0.097 lb/MMBtu)

MINOR SOURCE PERMITTING

The state enforces a 20% opacity limit and PM limits based on the unit's production rate. The state may require ambient impact modeling, however no controls are likely. SO2 emissions limits vary by location; in the Charleston area, sources < 10 MMBtu/hr have a limit of 3.5 lb/hr and sources > 10 MMBtu/hr have a limit of 2.3 lb/hr; in Aileen and Anderson counties, sources < 1000 MMBtu/hr have limits of 3.5 lb/hr and sources > 1000 MMBtu/hr have limits of 2.3 lb/hr. All other areas have limits of 3.5 lb/hr.

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 (100 tons for listed sources) per year of a criteria pollutant triggers PSD in attainment areas; 100 tons triggers NSR in nonattainment areas.

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.

SITING REQUIREMENTS FOR NON-UTILITY GENERATORS:

The Utility Facility Siting and Environmental Protection Act governs siting of major utility facilities. Electric generating plants of 75 MW or greater require a certificate issued by the Public Service Commission. Co-ops, municipalities, and self-supplying generators (i.e. not for sale or public use) are excluded from these requirements as well.

BUILDING, ZONING AND FIRE CODES:

Building Codes: South Carolina has adopted the 2007 South Carolina Building Code, a statewide mandatory code. It is based on the 2006 IBC and includes state-specific amendments. Local jurisdictions must use these codes but can amend them to be stricter.

Building Codes Council

Energy Codes : South Carolina has adopted the 2006 IECC with no amendments. [1]

State Energy Office

Fire Codes: South Carolina has adopted the 2007 South Carolina Fire Code, which is based on the 2006 IFC and includes state-specific amendments. [2]

Office of the State Fire Marshal

Zoning: Zoning and planning happens at the local level. Check with each jurisdiction regarding their zoning codes.

Resources (information may not be as current as provided above)

A general overview of each state’s enacted codes can be found HERE.

The International Code Council Adoption page gives state-by-state adoption status of specific ICC codes, as well as information about code adoption by some municipal governments within that state.

Information about energy codes can be found at the DOE’s Building Codes for Energy Efficiency page or at the Building Codes Assistance Project.

INTERCONNECTION REQUIREMENTS:

In December 2006 the South Carolina Public Service Commission (PSC) adopted simplified interconnection standards for DG systems up to 20 kW in capacity for residential systems and 100 kW for non-residential. The standard does not include provisions for three-phase generators. The state’s model interconnection standard is identical to North Carolina’s, and applies to the state’s investor-owned utilities - Progress Energy, Duke Energy, South Carolina Electric and Gas, and Lockhart Power.

There is a $100 application fee for residential systems and $250 for non-residential. Residential customers may not be required by utilities to carry more insurance above standard homeowner’s - $100,000 minimum. Non-residential generators must carry comprehensive liability insurance, with a minimum of $300,000 coverage. A redundant external disconnect switch is required. The capacity of interconnected systems cannot exceed 0.2% of rated circuit capacity. Applications for systems that exceed this can be reviewed on a case-by-case basis.

The PSC has a vague directive requiring utilities to provide net-metering for customers. This has resulted in many widely varying forms of net-metering and net-billing. Net-billing is a financial arrangement that is less desirable for customers. The PSC has asked the following utilities to provide a flat-rate and time-of-use option for their customers. More information can be found on their websites: Progress Energy, Duke Energy, and SCE&G. Santee Cooper has had a net billing pilot program.

For more information contact your electricity generation and transmission utility, or the PSC.

Public Service Commission of South Carolina
101 Executive Center Drive
Columbia, SC 29210

Philip Riley

Phone: (803) 896-5154
E-Mail:philip.riley@psc.sc.gov

EXIT FEES:

No statewide exit fee policy has been identified. Please check with the Public Service Commission of South Carolina or local utility district for more information.

UTILITY STANDBY RATES:

South Carolina does not have a statewide policy on standby rates. Relevant policies for South Carolina utilities are summarized below.

Santee Cooper (South Carolina Public Service Authority) - Rider L-96-SB: Standby service is provided to customers that contract for a specified amount of demand capacity with the utility. A demand-based reservation charge is assessed each month. A standby demand charge is assessed on usage above the contract demand. Actual usage is billed through a regular tariff with a demand and energy charge. Billing demand is based on the higher of the maximum demand of the month or 80% of the contract demand. Rate information is available at: https://www.santeecooper.com/portal/page/portal/SanteeCooper/MyBusiness/Industrial%20Rates

Duke Energy Corporation - Schedule PG: Standby service is provided to customers with parallel generation equipment at a very high demand based rate. A reservation fee based on contract demand must be paid every month with actual usage being charged under a high demand rate for parallel generation. Billing demand is based on the higher of the maximum 30 minute demand of the month or 75% of the contract demand. Rate information is available at: http://www.duke-energy.com/rates/south-carolina.asp

South Carolina

WHAT'S NEW:

AIR EMISSIONS REGULATIONS:

BUILDING, ZONING AND FIRE CODES:

EXIT FEES: