In November 2011, Dynegy Inc. (NYSE:DYN) permanently retired the coal-fired, 176-MW Vermilion power plant in Illinois, while at the same time seeing tougher economics at its coal segment in Illinois, Dynegy reported in its March 8 annual Form 10-K report.
The coal segment is comprised of four operating coal-fired plants and two operating natural gas-fired peaker facilities in Illinois with a total capacity of 3,132 MW. The coal facilities are: Baldwin, 1,800 MW; Havana, 441 MW; Hennepin, 293 MW; and Wood River, 446 MW.
The Havana MW figure represents Unit 6 generating capacity. Havana Units 1-5, with a combined net generating capacity of 228 MW, are retired and out of operation. The Wood River MW figure represents Units 4 and 5. Units 1-3 at Wood River, with a combined net generating capacity of 119 MW, are currently in mothball status and out of operation.
In order to ensure continued compliance with the Clean Air Act and related rules and regulations, including ozone-related requirements, Dynegy has installed, is in the process of installing, or has plans to install additional emission reduction technology at the coal segment facilities. Two coal-fired units at Baldwin and the coal-fired unit at Havana have had installed and are operating dry flue gas desulphurization (FGD) systems for the control of SO2 emissions, and electrostatic precipitators and baghouses for the control of particulate emissions. A third unit at Baldwin (Unit 2) currently utilizes an electrostatic precipitator and is scheduled to complete installation of a dry FGD system and baghouse by the end of 2012.
The coal-fired units at the Hennepin facility have electrostatic precipitators and baghouses for the control of particulate matter. The baghouses at the coal segment facilities also control hazardous air pollutants in particulate form, such as most metals.
Activated carbon injection or mercury oxidation systems for the control of mercury emissions have been installed and are operating on approximately 97% of the coal segment’s coal-fired capacity, and Dynegy will install controls on the final unit (Wood River Unit 4) by 2013. Selective catalytic reduction (SCR) technology to control NOx emissions has been installed and has been operating at Baldwin Units 1-2 and at Havana for several years, while the remaining coal segment units use low-NOx burners and overfire air to lower NOx emissions.
Given the air emission controls already employed or planned for installation on the coal segment facilities, Dynegy said in the Form 10-K that it expects the coal units in Illinois will be in compliance with emission limits due to go into effect in April 2015 under the U.S. Environmental Protection Agency’s new Mercury and Air Toxics Standards (MATS) rule, also known as the EGU MACT rule.
Dynegy wrapping up consent decree work at Baldwin
In 2005, Dynegy settled a lawsuit filed by the EPA and the U.S. Department of Justice that alleged violations of the CAA and related federal and Illinois regulations concerning certain maintenance, repair and replacement activities at Baldwin. A consent decree was finalized in July 2005 that would prohibit operation of certain power generating facilities after certain dates unless specified emission control equipment is installed. Dynegy has achieved all emission reductions scheduled to date under the consent decree. As of Dec. 31, 2011, only Baldwin Unit 2 has material outstanding consent decree work yet to be performed, which is scheduled for completion by the end of 2012. Dynegy expects its costs associated with the remaining consent decree projects to be around $71m and $5m in 2012 and 2013, respectively.
Profitable operation of Dynegy’s coal-fired facilities is highly dependent on coal prices and coal transportation rates, the Form 10-K pointed out. “Power generators in the midwest and the northeast have experienced significant pressures on available coal supplies that are either transportation or supply related,” it said. “We have entered into term contracts for PRB coal, which we use for our coal facilities in the midwest. Our expected coal requirements are 100 percent contracted and priced for 2012. Our forecast coal requirements for 2013 are 62 percent committed. Those volumes are unpriced but are subject to a price collar structure. Our coal transportation requirements are 100 percent contracted and priced through 2013. Coal transportation rates will be renewed in 2014 at levels higher than our current rates. The low sulfur content coal used at our facilities in order to meet the requirements of our air permits limits our coal supply options, creating risks in terms of our ability to procure firm coal supplies for periods and prices we believe are favorable.”
Gross margin down in 2011 at coal segment
In 2011, gross margin from the coal segment decreased by $161m, to $320m, from $481m for 2010. This decrease was driven by the following:
- Mark-to-market revenue decreased by $112m due to a net change from mark-to-market revenue from $21m in 2010 to a mark-to-market loss of $91m in 2011. This decrease was driven by prices falling more sharply in 2010 as compared to 2011.
- Settlements revenue decreased by $39m due to fewer volumes hedged in 2011 compared to 2010. Settlements revenue also decreased due to the average value of Dynegy’s hedging positions being lower in 2011 compared to 2010.
- Capacity revenue decreased by $8m due to lower capacity prices in the MISO capacity market in 2011 compared to 2010.
- Energy revenue and the corresponding cost of sales decreased by $20m and $17m, respectively, for a net decrease in energy margin of $3m. Energy revenue and cost of sales decreased due to lower on-peak power prices in the MISO market and lower coal pricing as well as slightly lower generation.
- The average coal price decreased primarily due to the mothballing and subsequent retirement of the Vermilion facility as Vermilion had a higher delivered fuel cost. Delivered coal prices declined in late 2010 as a result of competing requirements under a higher priced contract prior to the end of the year. This also impacted the weighted average cost of coal in 2011 and resulted in lower burn expense during the early portion of 2011. While net volumes burned remained relatively flat, costs per ton declined in 2011.
- Generation volumes decreased slightly year over year. Volumes were reduced due to the mothballing and subsequent retirement of Vermilion. The decrease in volumes caused by the Vermilion retirement was largely offset by an increase in volumes at Baldwin caused by fewer outages in 2011 compared to 2010. In early 2010, Baldwin experienced a three-month outage that reduced burns for 2010. While Baldwin did experience outages in 2011, they were not as significant as those in 2010.