South Carolina Electric slashing coal use, to shut unit at year end

With 250 MW of previously-committed capacity at a gas plant available as of the end of 2012, and new nuclear on the horizon, South Carolina Electric & Gas has its unscrubbed coal capacity in the cross-hairs.

This is among the highlights from testimony filed by officials with the SCANA (NYSE: SCG) subsidiary in South Carolina.

In 2011, SCE&G took delivery of about 3.1 million tons of coal under long-term agreements and 545,000 tons of spot purchases. For 2012, the company has term contracts with ten suppliers totaling 2.8 million tons of coal and representing about 82% of expected total receipts, said Stephen Byrne, President for Generation and Transmission and Chief Operating Officer of South Carolina Electric & Gas, in Oct. 2 testimony filed at the South Carolina Public Service Commission.

Byrne and others testified in support of an application for increases and adjustments in electric rate schedules and tariffs, and a request for a mid-period reduction in base rates for fuel.

“In 2010 and 2011 the use of coal has declined compared to past periods in favor of the consumption of cheaper natural gas,” Byrne noted. “These lower natural gas prices mean that SCE&G’s combined cycle natural gas plants displace a significant amount of coal generation for extended periods during the Test Year, resulting in much less coal being consumed from inventory. Due to commitments in the current CSX [rail] contract, the Company has continued to purchase coal on a spot basis and to take advantage of lower priced spot coal compared to existing contracts. Consequently, coal inventories remain at elevated levels.”

The Over-the-Counter coal market f.o.b. prices for coal averaged $73.79/ton in 2011 and averaged $57.43/ton for the year-to-date through Aug. 6. Currently the market stands at $62/ton, Byrne wrote.

“As combined cycle natural gas plants continue to come online in the southeast, the demand for Central Appalachia (‘CAPP’) coal will continue to decline as long as natural gas prices stay competitive,” Byrne reported. “Also the effects of government regulation and coal exports will influence prices. It is estimated that the production cost of CAPP producers is in the $60 to $65/ton range, leaving their costs above market for the first half of the year. Since 2009, millions of tons of CAPP production have come off line with a significant number of miners now unemployed.”

SCE&G has gone as far as it’s going to go on scrubbers, SCR

Byrne also addressed SCE&G’s SO2 scrubber build program, needed to meet new air emissions rules. A Wateree scrubber was one of three principal environmental upgrades made to SCE&G’s coal units between 2007 and 2010. During that time, SCE&G installed scrubbers and associated facilities at Wateree and Williams and a selective catalytic reactor (SCR) for NOx control at Cope. The total cost of these two scrubbers and the SCR was $613m.

Williams is a single-unit, 605-MW coal plant located in Berkeley County, S.C. Wateree is a dual-unit, 684 MW coal plant located in Richland County, S.C. Cope is a single-unit, 415 MW coal plant in Orangeburg County, S.C. These three plants have the largest and most modern coal units on the company’s system. They are the only coal units that are large enough to make it economical to retrofit with emissions upgrades. For that reason, they are the only coal units that SCE&G is currently planning to operate on coal after the new “VCSNS Units” come on line, Byrne noted. That is a reference to two new nuclear units now in initial construction at the V.C. Summer plant.

There was no need to install a scrubber at Cope because it included a scrubber as initially constructed, Byrne added. There was no need to install SCRs at Wateree and Williams because the company retrofitted them with SCRs in 2003 and 2004.

SCE&G to get back 250 MW at Jasper gas plant

In 2002, SCE&G requested commission approval to site the Jasper Generation Station as an 875-MW combined-cycle natural gas-fired facility. The design of the plant called for three combustion turbines (CT) with supplementary duct-firing and a single steam turbine as the heat recovery unit. SCE&G had considered building a smaller two-CT configuration. It would have had a much lower generating capacity, but would have been sufficient to meet immediate needs at the time. However, because of construction and design efficiencies, the larger three-CT configuration with supplementary duct-firing was much cheaper to build per MW than the smaller design.

With the commission’s approval, SCE&G opted to build the larger design and to sell 250 MW of excess capacity off-system. That off-system sales contract will expire on Dec. 31, 2012. That expiration will make 250 MW of efficient, low fuel-cost generation available to serve SCE&G’s customers exclusively, Byrne noted.

The availability of this capacity will allow SCE&G to begin retiring older coal-fired units. On Jan. 1, 2013, simultaneously with the expiration of the wholesale power contract, SCE&G will retire the 90-MW, coal-fired Canadys Unit 1. The company will also switch the 95-MW, coal-fired Urquhart Unit 3 to gas-fired operation only. In 2015, SCE&G plans to switch its McMeekin coal-fired units and Canadys Units 2 and 3 to natural gas-fired status only, and plans to retire those units entirely in 2018 when Summer Unit 3 is brought into service.

“I would emphasize that this plan is subject to review during each annual resource planning cycle and could change,” Byrne cautioned. “SCE&G will decide how to proceed with these units long-term based on the needs of the system at that time and our assessment of the approach that provides the greatest benefits at the least cost to our customers.”

Unanticipated load growth, changes in environmental regulations, major industrial demand growth, restrictions in gas delivery capacity, or problems with existing plants in the region could create a need for the capacity that these targeted plants represent, Byrne testified.

Coal to shrink sharply in SCE&G generation mix by 2019

By 2019, the utility plans to have an additional 1,229 MW of efficient and non-emitting nuclear on line at V.C. Summer. It projects that in 2019, its generation mix on a capacity basis will be 27% coal, 28% natural gas, 31% nuclear and 14% hydro/biomass. In 2019, based on how it expects to dispatch its plants, SCE&G projects that 60% of its energy will come from nuclear and hydro/biomass and only 24% will be generated using coal. The current plan indicates that by 2015, the only plants at which it burns coal will be those that have scrubbers and SCRs.

SCE&G owns and/or operates ten coal-fired fossil fuel units (2,434 MW), one biomass cogenerator (85 MW), one solar facility (2 MW); eight combined cycle gas turbine/steam generator units (gas/oil fired, 1,327 MW), 16 peaking turbines (355 MW), four hydroelectric plants (218 MW), and one pump storage facility (576 MW). The total net non-nuclear summer capability of these facilities is 4,997 MW.

In addition, SCE&G operates V.C. Summer Unit 1 (644 MW available to SCE&G), which is called the VCSNS or Summer. SCE&G owns this nuclear plant jointly with the South Carolina Public Service Authority (Santee Cooper).

The current total net capability available to SCE&G from all of these generating facilities is 5,641 MW. In 2011, coal plants generated about 49% of the electricity produced, the combined-cycle units generated about 28%, the gas peaking turbines and hydro facilities kicked in about 3%, the nuclear plant generated about 19%, and the biomass/solar generation facilities generated around 1%.

Site work ongoing at Summer, equipment on the way

In March, the utility received the Combined Operating License for the new VCSNS Units 2 and 3 from the Nuclear Regulatory Commission. The other major permits needed to construct and operate the units are in hand, with the exception of a water permit Byrne expects to be issued shortly. The amendments to the design control documents for the AP1000 units are fully approved.

As of August, site specific design for the units was approaching 90% complete and Standard Plant Issued for Construction drawings were nearly 50% complete. Initial procurement for the major equipment and components for Unit 2 is largely complete. Establishing effective quality assurance/quality control (QA/QC) systems for contractors and suppliers has been a matter of focus during the early years of the project, Byrne noted. Major components and equipment for Unit 2 either are in production or are being shipped to the site.

Jimmy Addison, Executive Vice President and CFO of SCE&G and also an official of parent SCANA Corp. (NYSE: SCG), testified that the time between now and the end of 2014 represents the period of greatest investment in the new Summer units and a need for SCE&G to be able to access capital on reasonable terms. From 2007 to the end of 2012, it will have paid about $2bn, or 34%, of the cost of the units. Two years later, plans show that approximately $4bn, or 70%, of the cost of the units will have been paid.

SCE&G owns 55% of the new Summer units (614 MW each) while Santee Cooper will own 45%. The two new units, one of them to come online in 2017 and the other in 2018, are each 1,117 MW (net) facilities.

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.