A new tax regime will increase the cost of South Korean coal-fired power generation next month and make the use of gas plants cheaper, but coal will retain a price advantage over gas and remain ahead in the merit order for thermal generation in the near term.
The South Korean government said last summer that it would adjust coal and LNG tax rates to better reflect the environmental costs of burning the fuels for power generation, with the change to take effect from 1 April 2019.
The consumption levy due on coal used for power generation will rise by 10,000 won/t, with grades of a calorific value (CV) lower than NAR 5,000 kcal/kg taxed at W43,000/t ($38/t), NAR 5,000-5,499kcal/kg CV coals taxed at W46,000/t and any higher grades taxed at W49,000/t.
The combined tax rate due on the use of LNG in the power sector will drop to W23,000/t from W91,400/t. This includes an import duty of W7,200/t — which is left unchanged — a consumption tax of W12,000/t and a supplementary import tax of W3,800/t. The latter two taxes represent a cut from W60,000/t and W24,200/t, respectively.
The tax change from 1 April will equate to a $3.26/MWh increase in coal-fired generation costs, based on high-CV consumption in a 39pc efficient power plant, and a $7.25/MWh cut to the cost of gas-fired generation for a 55pc-efficient plant.
But the net $10.51/MWh increase in the cost of burning coal compared with gas may not be sufficient to drive a significant switch between the fuels in South Korea's thermal generation mix in the near term.
LNG uncompetitive with coal on average-cost basis
Spot LNG prices in northeast Asia have fallen by more than 60pc to $4.42/mn Btu, from highs of $11.70/mn Btu in September last year. Spot LNG prices are currently theoretically competitive with spot NAR 6,000kcal/kg Newcastle coal prices for power generation, but these do not fully represent South Korean fuel costs, which are affected by blending of coal grades and domestic gas tariffs.
Most generation companies in South Korea — including the five state-owned companies run by Kepco — buy their gas from another state-owned company, Kogas, which accounts for the majority of South Korea's LNG imports.
The gas tariff that Kogas charges domestic power companies has averaged W14,325/GJ — $12.30/mn Btu — over January 2018-February 2019, Kogas data show. This is higher than the $9.45/mn Btu average value of Argus' northeast Asian spot LNG assessment over the same time and the $10.31/mn Btu average value of South Korea's LNG imports, as derived from customs data.
There is no equivalent intermediary to Kogas in the coal sector and the state-owned Kepco subsidiaries are responsible for sourcing their own supplies for power generation. Customs data show that the value of South Korea's bituminous coal imports averaged $89.06/t over January 2018-February 2019. This is below the $118.80/t delivered-cost of premium NAR 6,000kcal/kg Australian coal, based on Argus assessments, as South Korean buyers also import cheaper, lower-CV grades of coal from Indonesia and elsewhere to blend when creating a feedstock for their coal plants. South Korea's three biggest coal plants — Taean, Dangjin and Yeongheung — consumed grades with CVs of 5,500-5,771kcal/kg in 2017, according to Kepco data.
South Korean clean generation costs — including taxes — based on the average import price of bituminous coal and Kogas' domestic gas tariff show that coal-fired plants continue to hold a significant cost advantage over gas units, even in the wake of steep declines in spot LNG prices in recent months.
The generation cost for a 39pc efficient coal plant was around $64/MWh in January-February, based on the average import price of bituminous coal and including taxes and carbon costs. This compared with nearly a $99/MWh cost of running a 55pc-efficient gas plant, based on Kogas' domestic tariff for the power sector. The tax change on 1 April will pare coal's price advantage by $10.51/MWh — assuming flat fuel and carbon prices — but will not close the gap entirely, meaning gas-fired generators reliant on Kogas for their supply will still struggle to displace coal from the thermal stack on a cost basis alone.
The tax change will make spot LNG prices increasingly competitive with coal for thermal generation. Theoretical generation costs for 55pc-efficient gas plants averaged $58/MWh last month, based on Argus' northeast Asian spot LNG price assessment, which was competitive with coal-generation costs based on the average February import price of bituminous coal and the South Korea-delivered spot price of high-grade Australian coal.
There is potential for spot LNG to displace some coal from the thermal fuel mix in South Korea, but this depends on the extent to which Kogas increases spot purchases and passes the cheaper seaborne prices onto its domestic customers, as only a few private companies in South Korea are able to take advantage of low prices in the seaborne market directly.
If Kogas does not significantly increase purchases of cheaper spot LNG and lower domestic gas prices, coal-to-gas fuel switching later in the year will instead depend on the progression of term LNG prices and their relative competitiveness against coal.
Argus' indicative oil-linked LNG prices have tracked the average customs-declared value of South Korea's LNG imports more closely than the prevailing spot price has in recent years, and give some indication of the potential for coal-to-gas fuel switching later in the year.
The implied generation costs for a 55pc efficient South Korean gas plant, based on Argus' indicative forward oil-linked LNG prices outturn at around $73.50/MWh over April-December, including the lower tax rate. This would be down from around $87.50/MWh during the winter and would put gas-generation costs close to parity with coal, based on forward prices for the premium NAR 6,000kcal/kg Newcastle grade to the end of 2019.
But the value of South Korea's bituminous coal imports have averaged more than a $20/t discount to the South Korea-delivered cost of high-CV spot Australian coal, while Kogas' domestic gas tariff has averaged nearly a $2/mn Btu premium to the customs-declared value of the country's LNG imports. Coal therefore looks likely to retain an, albeit diminished, advantage for thermal generation on an average cost basis, barring a significant increase in spot LNG purchases.
Plant restrictions also key
Greater potential price competition between coal and gas in South Korea comes amid an expected rise in nuclear availability, which is likely to weigh on thermal generation in general and pose downside risk to coal and gas demand in the months ahead.
Nuclear availability over April-September was scheduled to average 18.6GW as of 11 March, which could support up to 13.6 TWh/month of output compared with 11.5 TWh/month in the same months last year. The potential increase in nuclear generation this summer is equivalent to nearly 5mn t of 5,700kcal/kg coal burn from a 39pc-efficient plant, or more than 1.5mn t of LNG used in a 55pc gas plant.
South Korea's coal fleet also faced heavy restrictions at times last year, driving an increase in LNG demand to cover the shortfall in nuclear availability. The government has said most coal plants will be partially restricted this spring, although the impact may not be significantly worse than last year. Maintenance schedules for South Korea's two biggest coal plants Taean and Dangjin actually suggest a small rise in capacity availability in 2019.
Greater nuclear availability in 2019 looks likely to limit South Korean demand-growth for coal and LNG, but their relative competitiveness for thermal generation is likely to determine which fuel faces the bigger headwind.
