South Carolina Electric to cut back coal in its power portfolio

South Carolina Electric & Gas has plans to shut or convert six small, old coal units to natural gas, while at the same time pursuing new nuclear and renewable energy projects that will shrink coal as part of its long-term portfolio.

SCE&G, a unit of SCANA Corp. (NYSE: SCG), on May 30 filed its latest integrated resource plan (IRP) with the South Carolina Public Service Commission. SCE&G had earlier this year won delays in filing this IRP, which covers the 2012-2026 period, so it could iron out some issues related to the nuclear plans.

Looking at what it has done lately to keep its larger coal units viable in the face of U.S. Environmental Protection Agency regulations, SCE&G said that in order to reduce NOX emissions and to meet its compliance requirements, it installed selective catalytic reduction (SCR) equipment at its Cope plant in the fall of 2008. The SCR began full time operation in January 2009 and has run well since that time. It is capable of reducing NOX emissions at the Cope by approximately 90%. SCE&G is also utilizing the existing SCRs at Williams and Wateree along with previously installed low NOX burners at the other coal-fired units to meet the Clean Air Interstate Rule (CAIR) requirements for NOX which are in effect while the EPA’s Cross-State Air Pollution Rule (CSAPR) is under a court-ordered stay.

Also, SCE&G has installed flue gas desulfurization (FGD) equipment, commonly known as wet scrubbers, at Wateree and Williams to reduce SO2 emissions. The in-service dates for Williams and Wateree were in 2010. Scrubber performance tests at both stations met the SO2 designed removal rate of 98%.

During 2010, SCE&G worked with a contractor to test a Chem-Mod fuel additive that was expected to reduce SO2, NOX and mercury at Urquhart Unit 3, Canadys and McMeekin. Test results through a third party indicate emissions reductions of more than 30% of mercury, more than 7% of NOX, and a 2%-3% SO2 reduction. SCE&G recently received a state permit for ongoing use of Chem-Mod at McMeekin, Canadys and Urquhart.

Six unscrubbed coal units targeted to shut, fuel switch

There are five new regulations that are either proposed or have been recently finalized, plus one modification, that are affecting the coal units, the utility noted. These are CSAPR, the Mercury and Air Toxics Standards (MATS), Greenhouse Gases, Cooling Water Intake Structures, and Coal Combustion Residuals, and a new 1-hour SO2 National Ambient Air Quality Standard (NAAQS).

SCE&G has six small coal units in its fleet totaling 730 MW that range in age from 45 to 57 years in age. Under the existing environmental regulations, the company does not anticipate that it will be able to continue to operate these six units using coal unless it installs pollution control equipment. These units and their commercialization years are:

  • Canadys Unit 1, 90 MW, April 1962
  • Canadys Unit 2, 115 MW, May 1964
  • Canadys Unit 3, 180 MW, June 1967
  • Urquhart Unit 3, 95 MW, November 1955
  • McMeekin Unit 1, 125 MW, July 1958
  • McMeekin Unit 2, 125 MW, December 1958

For its current resource plan, SCE&G has analyzed its options from long and short run planning horizons. The long run perspective analyzes the value of these plants after the new nuclear capacity is added while the short run identifies economic steps to be taken prior to 2017 which help implement the long range strategy.

SCE&G said it has identified three steps in the future for these six coal units.

STEP 1: SCE&G intends to retire the coal handling facilities at Urquhart and commit to operating Unit 3 at Urquhart exclusively on natural gas by the end of 2012. SCE&G anticipates that operating Unit 3 at Urquhart exclusively on natural gas will reduce both air emissions and coal combustion waste. As a result of operating Unit 3 exclusively on natural gas, over the next five years SCE&G anticipates generating about 317 million kWh more with gas and 359 million kWh less with coal.

STEP 2: SCE&G also intends to retire Unit 1 at Canadys by the end of 2012. As a result of the retirement of this unit, over the next five years SCE&G anticipates generating about 615 million kWh more with gas and 679 million kWh less with coal. The retirement of the 90-MW Canadys Unit 1 will increase a reserve margin deficit prior to the addition of the nuclear V.C. Summer Unit 2; however, filling this capacity deficit should cost much less than the $28.5m in anticipated savings.

STEP 3: The EPA’s MATS rule requires compliance in three years, by April 2015. The rule offers the potential of a one-year waiver which the EPA indicated would be liberally granted. A waiver for a second one-year extension is also available to preserve grid reliability, but the EPA does not expect to grant many of these waivers. Although SCE&G is considering applying for these waivers, it cannot assume that they will be granted and has therefore begun analyzing the possibility of operating Units 2 and 3 at Canadys and Units 1 and 2 at McMeekin exclusively on natural gas by April 2015. The deliverability of natural gas to these units appears to be the most critical uncertainty.

Two new nuclear units a key for SCE&G’s planning

On the nuclear front, on March 30 the U.S. Nuclear Regulatory Commission issued a combined Construction and Operation License (COL) to SCE&G for each planned V.C. Summer unit. Both units will have the Westinghouse AP1000 design and use passive safety systems to enhance the safety of the units. The first unit is expected to come online in 2017 and the second in 2018. SCE&G will own 55% of the units (614 MWs each) while Santee Cooper will own 45%. These two new units are each 1,117 MW (net) facilities.

SCE&G owns and operates 10 coal units (2,434 MW), eight combined cycle gas turbine/steam generator units (gas/oil fired, 1,327 MW), 16 peaking turbine units (355 MW), three hydroelectric generating plants (218 MW), and one Pumped Storage Facility (576 MW). In addition, SCE&G receives an output of 85 MW from a cogeneration facility. The total net non-nuclear summer generating capability rating of these facilities is 4,995 MW. When SCE&G’s nuclear capacity (644 MW), a long-term capacity purchase (25 MW) and additional capacity (22 MW) provided through a contract with the Southeastern Power Administration are added, SCE&G’s total supply capacity is 5,686 MW.

SCE&G currently generates nearly 30% of its retail sales from clean energy sources and by 2019 expects to generate about 72%. The SCE&G-owned electric generator located at the KapStone Charleston Kraft LLC facility, generates electricity using a mixture of coal and biomass. Also on the renewable front, in 2011 SCE&G installed about 10 acres of thin-film laminate panels (18,095 individual panels) on the roof of Boeing’s North Charleston assembly plant. The PV system, having an alternating current peak output of more than 2 MW, began generating in October 2011. At the time of completion this was the largest roof-top solar generator in the Southeast U.S.

SCE&G looks at offshore wind, biomass cofiring options

SCE&G said it is involved with off-shore wind activities in the state and cofiring with biomass fuels.

SCE&G currently participates in the Regulatory Task Force for Coastal Clean Energy. This task force was established with a 2008 grant from the U.S. Department of Energy. The goal is to identify and overcome barriers for coastal clean energy development for wind, wave and tidal energy in South Carolina. Efforts include various studies and creation of a regulatory task force.

In 2010, SCE&G began a project to investigate and evaluate the cofiring of biomass and other engineered waste products in its existing coal burning facilities. The goal of the project is to determine the operational practicality as well as the economic and fuel supply implications.

“Co-firing of biomass fuel in our existing units represents an opportunity to include additional renewable fuels in our production mix without having to build new facilities or spend significant capital on existing facilities,” the IRP noted. “The Company has purchased and set up mobile fuel handling equipment to facilitate testing of different types of biomass and other waste materials at multiple facilities. Tests with different forms of biomass material are ongoing and the results are being evaluated by the Fossil Hydro department to determine a future course of action.”

SCE&G said it has met with several companies that are considering developing renewable facilities in South Carolina and who wish to sell power to SCE&G through a long term agreement. The company will continue to evaluate opportunities in the renewable sector, but the power must be economical for its customers. SCE&G also continues to monitor state and federal bills that, if enacted, would mandate a federal or state renewable portfolio standard (RPS). The bills proposed, but not passed, in 2010 required 15%-20% of utilities’ retail sales to come from renewable sources by year 2020. Qualified renewable sources include wind, solar, geothermal, biomass, qualified hydro-power, and marine and hydrokinetic renewable energy. The most viable renewable energy source in South Carolina is woody biomass. Offshore wind energy and solar energy are available but are uneconomic today, SCE&G wrote.

“While there is considerable uncertainty in the future, SCE&G is in the enviable position of having a robust resource plan to serve its electric customers,” said the IRP. “Having made the commitment to a nuclear strategy several years ago, the Company has significantly mitigated the environmental and cost risks associated with a reliance on fossil fuels. With two new nuclear units in its fleet of generators, SCE&G will lower its emissions of CO2, SOX, NOX and particulates as well as avoid the creation of a significant amount of coal ash. If the U.S. Congress passes a Clean Energy Bill, then the Company’s resource plan is most likely already in compliance. However, the Company’s resource plan will not meet a Renewable Portfolio Standard (‘RPS’) that excludes nuclear power. Currently, renewable power is more costly than conventional alternatives so an RPS would result in higher costs for our customers.”

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.