Flue gas desulfurization (scrubber) equipment installed in recent years on the Mountaineer and Amos power plants in West Virginia has allowed Appalachian Power (APCo) to burn cheaper high-sulfur coals at those facilities, letting it keep control of fuel costs.
Jeffery LaFleur, Vice President-Generating Assets for APCo, was one of several utility officials that wrote testimony that was filed April 24 at the Virginia State Corporation Commission in a fuel cost case.
He noted that Mountaineer is a single-unit, pulverized coal-fired power plant with a nominal capacity of 1,300 MW located in New Haven, W.Va., along the Ohio River. The unit was placed in service in 1980. The FGD system at the plant has been operational since 2007, and a selective catalytic reduction (SCR) system for NOx control has been in-service since 2002.
Amos is a three-unit, pulverized coal-fired power plant with a net capacity of 2,900 MW located in Winfield, W.Va., along the Kanawha River. Units 1 and 2 have a nominal capacity of 800 MW each, and Unit 3 has a nominal capacity of 1,300 MW. Units 1, 2, and 3 were placed in service in 1971, 1972, and 1973, respectively. The FGD systems at Amos Units 1, 2, and 3 have been operational since 2011, 2010, and 2009, respectively. The SCR systems for Units 1, 2, and 3 have been in-service since 2005, 2004, and 2002, respectively.
Mountaineer is permitted by the state Department of Environmental Protection to emit SO2 up to a limit of 1.2 lbs/mmBtu. The Amos plant is permitted to emit SO2 up to a limit of 1.6 lbs/mmBtu. Prior to the installation of FGDs at Mountaineer and Amos, the coal used by APCo at these plants was a low-sulfur Central Appalachia (CAPP) coal of less than 1.6 lbs SO2/mmBtu.
“The FGDs that were designed for, and installed at, Mountaineer and Amos allow the plants to meet emission limits, while burning coals with a sulfur content that is higher than the low sulfur CAPP coal that historically has been burned at the plants since the effective dates of the environmental permits I discussed previously,” LaFleur wrote. “Company witness Rusk has advised me that low sulfur CAPP coal is generally higher-priced than coals with higher sulfur contents.”
He added: “During the design phase of Mountaineer’s FGD, it was determined that primarily due to the size of its boiler, but giving due regard to other boiler and plant considerations, the plant could economically and efficiently bum high sulfur Northern Appalachian (NAPP) coal, which I understand from Company witness Rusk has a sulfur content of approximately 7.4 lb. SO2/MMBTU. Consequently, the Mountaineer FGD was designed to remove greater than 95% of the SO2 from the unit’s flue-gas stream while it burned high sulfur NAPP coal with up to maximum sulfur content of approximately 7.4 lb. S02/MMBTU.”
He added: “[T]he Amos plant has two 800 MW units (Amos 1 and 2), and a 1,300 MW unit (Amos 3) that predates the 1,300 MW unit at Mountaineer by about seven years. The size of the boilers on Amos 1 and 2, which are smaller than the boilers on Amos 3 and Mountaineer, was a critical factor that was considered during the design phase of the three FGDs at Amos. As is the case with Mountaineer’s FGD, each FGD at Amos treats 100% of the flue gas emitted by the unit; however, each FGD at Amos is designed to remove greater than 95% of the SO2 from a flue gas stream while the units burn a blend of higher sulfur NAPP coal (approximately 7.4 lb. SO2/MMBTU) and lower sulfur CAPP coal (approximately 1.6 lb. SO2/MMBTU) with up to a maximum sulfur content of 4.5 lb. SO2/MMBTU. As part of the FGD project at Amos, the coal yard was also retrofitted with a state-of-the-art coal blending facility. That facility will allow the blending of various types of coals over the remaining life of the plant.”
Rusk outlines unexpected coal rebound in 2011
Jason Rusk, employed by American Electric Power Service Corp. (AEPSC), another subsidiary of American Electric Power (NYSE: AEP), in the Fuel, Emissions & Logistics Group as Director, Coal Procurement, outlined recent events in the coal markets and APCo’s coal position.
“A strong and robust coal market in 2008 resulted in high market prices for coal,” Rusk reported. “As a result of the economic downturn, which came into play in late 2008 and early 2009, there was a significant reduction in coal prices, as well as lower market prices for electricity. This was followed by a moderate upward trend in coal prices, matched with lower coal market volatility that was present from the fourth quarter of 2009 through the first half of 2011. The market did not experience decreasing coal prices for the majority of 2011 because demand for coal in other countries continued to support the price of coal from the Central Appalachian Basin, the main type of coal consumed by APCo. Starting in the fourth quarter of 2011, Central Appalachian coal prices in the spot market did begin to drop in response to weak domestic demand. However, this recent downward trend in market coal prices has not materially affected APCo’s coal costs as APCo has not had a need to purchase significant amounts of coal in the spot market in recent months.”
Although coal production costs continue to rise, as a result of increased regulation, decreases in the issuance of mining permits, and the difficulties related to mining more challenging reserves, spot market coal prices are currently “suppressed” due to a lack of domestic demand, Rusk added. In general, coal prices are expected to trend upward as supplies of Central Appalachia coal decline. Additional market pressures include the uncertainty regarding future U.S. Environmental Protection Agency rules and how the implementation of those rules may affect future coal consumption.
This uncertainty is reflected in the Circuit Court of Appeals for the D.C. Circuit’s Dec. 30, 2011, decision to stay implementation of the EPA’s Cross-State Air Pollution Rule (CSAPR), less than two days before the rule was to take effect. The stay of CSAPR has not yet had a significant impact on the market price for coal, but future developments regarding CSAPR and the recently-finalized Mercury and Air Toxics Standards (MATS) do have the potential to cause a downward effect on coal prices due to lack of demand if utilities have to shutter non-compliant coal-fired plants, Rusk noted. These rules could also lead to increases in the price for lower sulfur coals, as utilities look to contract for cleaner coals.
During 2011 APCo consumed more tons of coal than during 2010, and the average cost of coal on a per-ton basis was slightly higher than in 2010. In 2010 and 2011, APCo’s total weighted average cost of delivered coal was $62.95 and $63.78 per ton, respectively.
In 2011, APCo saw a slight increase in generation over 2010, which had not been forecast. This increase in generation resulted in APCo consuming more coal in 2011 than in 2010 (particularly low-sulfur coal). Consequently, some spot purchases of low-sulfur coal were necessary to manage the company’s coal supply inventory. These low-sulfur spot purchases were made at prices higher than the price in existing long-term contracts, which increased the average price of coal for APCo in mid to late 2011. However, these spot purchases and those made over the past few years were generally made at or below market price because AEPSC is able to leverage the buying power of multiple operating companies.
Also during 2010 and the first half of 2011, when coal prices rose moderately due to an improving economic outlook that included increased forecasted coal consumption, APCo saw a need to procure more coal under long-term (more than one year) agreements. Along with its purchases of spot coal in 2011, these more recently executed agreements led to an increase in APCo’s coal costs because these contracts were entered into at a time when prices were higher than they had been in recent years, with the exception of the brief period during 2008, when market prices spiked immediately preceding the economic downturn.
Coal price increases center on two plants
An increase in the forecasted delivered cost of coal for APCo plants is primarily driven by changes occurring at Amos and Mountaineer. Together, these two plants account for almost 90% of APCo’s forecasted delivered coal cost and forecasted delivered tonnage. Average coal costs at Amos increased in 2011 due to the need to purchase low-sulfur coal on the spot market in the second and third quarters, and the start of long-term agreements with delivered prices that are higher than recent prices. While the 2011 spot purchases brought the average price up in 2011, the more recent long-term agreements for Amos are primarily responsible for the increased coal costs forecasted to be incurred from June 2012 through August 2013.
Coal prices for Mountaineer stayed relatively flat in 2011, but deliveries to Mountaineer are expected to increase from an average FOB mine price of just under $60 per ton at the beginning of the forecast period to $64 per ton in August 2013. This increase is being driven by factors similar to those at Amos – both have older contracts, which are expiring and being replaced with contracts that were entered into at a time when coal prices were higher than when the expiring contacts were negotiated, Rusk noted
APCo currently has 16 long-term contracts with 13 vendors that will be in effect as of June 1, 2012, or are forecast to begin delivering coal within the forecast period. These contracts have various expiration dates, tonnages and prices. Of these sixteen long-term agreements, six are scheduled to expire by the end of the fifteen-month forecast period ending Aug. 31, 2013.
Attached to the filing was a list of the coal contracts, with key data, like tonnages and expiration dates, not included. The contracts are with parties like American Energy, Arch Coal Sales, Bowie Resources LLC, Patriot Coal Sales and Peabody COALTRADE.
Testimony from Rusk similar to the Virginia testimony was filed March 30 by APCo at the West Virginia Public Service Commission as part of an annual Expanded Net Energy Cost (ENEC) review case.
That West Virginia testimony had more detail about the coal contracts than the Virginia filing. For example, the West Virginia testimony made it clear that APCo has signed a big new contract with the Consolidation Coal unit of CONSOL Energy (NYSE: CNX). This contract expires in December 2021, is for 1.25 million tons in 2012 and then 2.1 million tons in every contract year thereafter, and is to be used at Amos and Mountaineer, with a range of 5.96 to 6.68 lbs/MMBtu of SO2 content. This is a major new contract that only began on Jan. 1 of this year.