There are various options and uncertainties in play when it comes to a plan by Indiana Michigan Power to install new emissions controls on the coal-fired Rockport plant, said Cynthia Armstrong, a Senior Utility Analyst in the Electric Division for the Indiana Office of Utility Consumer Counselor (OUCC).
Testimony from Armstrong and other OUCC witnesses was filed July 13 with the Indiana Utility Regulatory Commission in a case begun last year where Indiana Michigan, a unit of American Electric Power (NYSE: AEP), is seeking approval for new controls at the 2,600-MW Rockport plant.
The purpose of Armstrong’s testimony is to discuss the appropriateness of retrofitting a unit at Rockport with dry flue gas desulfurization (DFGD) and selective catalytic reduction (SCR) due to new environmental regulations and a 2007 consent decree that AEP worked out last decade with the federal government.
I&M is seeking a Certificate of Public Convenience and Necessity (CPCN) for multi-pollutant control projects on either Rockport Unit 1 or 2, also referred to as the Rockport Environmental Project (REP). These projects include a DFGD, an SCR, and modifications to the existing plant to accommodate fuel changes and ash handling. I&M is also seeking cost recovery to track a return on capital, depreciation, and operation and maintenance (O&M) costs of the REP via its Clean Coal Technology Rider rate mechanism.
The primary new environmental regulation that is driving the need for the projects in 2015 is the Mercury and Air Toxic Standards (MATS) Rule. However, the Cross State Air Pollution Rule (CSAPR) and the Coal Combustion Residuals (CCR) Rule also add to the costs of keeping the Rockport units operating in compliance with environmental regulations beyond 2015. The Consent Decree that American Electric Power entered into with the EPA to settle alleged New Source Review (NSR) violations occurring at I&M’s and other AEP Eastern Companies coal plants also requires certain pollution control equipment be installed on Rockport Units 1 and 2.
“Rockport Generating Station will not meet all of the MATS emission standards without additional pollution controls,” Armstrong wrote. “The only technology used to determine the MACT emission standard that Rockport currently has installed is ACI [activated carbon injection] for mercury control. However, the Electrostatic Precipitators (‘ESPs’) installed on both Rockport Units 1 and 2 are currently controlling PM [particulate matter] emissions to well below 0.03 lbs/MMBTU. In fact, the only year in the past decade that the Rockport Generating Station went above the impending standard for non-mercury metals was in 2003. As far as mercury is concerned, the Rockport facility almost met the standard in 2010 (average annual emissions of 1.3 lbs/TBTU), which is likely the result of the ACI systems being placed into service at the end of September 2009. I do not have mercury emissions data for 2011, and therefore cannot determine if the emissions in 2011 would fall below the 1.2 lb/TBTU emissions level. It is highly possible that both Rockport Units 1 and 2 could currently meet the MATS for mercury with minimal change to the facility.”
Acid gas emissions the big problem with MATS compliance
Rockport’s main issue with MATS compliance is its acid gas emissions, Armstrong noted. Since neither Unit 1 nor Unit 2 has a flue gas desulfurization (FGD) system, the station’s current hydrochloric acid gas emissions are roughly five to ten times the emission limit dictated in MATS. In 2011, both Rockport Units 1 and 2 experienced an average annual SO2 emission rate of approximately 0.7 lbs/MMBtu. Rockport Units 1 and 2 would need to reduce current SO2 emissions by about 70% in order to meet the SO2 surrogate emission standard in MATS.
I&M will also need to decrease its annual NOx emissions by about 4,000 tons. This means that if I&M plans to completely avoid reliance on the SO2 and NOx CSAPR allowance markets, the company will need to reduce its overall system emissions by more than 61% for SO2 and 16% for NOx by 2014. Armstrong noted that retiring the coal-fired Tanners Creek Units 1-3 in 2015 will reduce annual SO2 emissions for I&M by around 5,700 tons and annual NOx emissions by roughly 1,600 tons per year. This would leave I&M to reduce its overall system annual emissions by more than 53% for SO2 and 9% for NOx by 2015.
Both Rockport Units 1 and 2 will need to install some form of pollution control for SO2 emissions if these units are going to operate at full capacity beyond 2015. One way that I&M can ensure that its Rockport units will be able to operate as baseload units into the future would be to retrofit the facility with a DFGD, as it is requesting approval to do in this case. However, there are also other technologies that could potentially achieve the SO2 removal efficiencies that will be required of Rockport beyond 2014.
As far as NOx emissions are concerned, Rockport Unit 1 will have to reduce its annual NOx emissions by more than 1,500 tons by 2014, or about 16.5% of current emissions, and Rockport Unit 2 will need to reduce its annual NOx emissions by more than 2,600 tons by 2014, or around 26% of its current emissions. While it is true that SCR technology will reduce Rockport Unit 1’s NOx emissions below this level, selective non-catalytic reduction (SNCR) is also capable of achieving a removal efficiency of 35%-50% at a much lower cost than SCR. “In my opinion, the Rockport facility can comply with the CSAPR NOx requirements with other low-cost alternatives to the SCR, including, but not limited to, installation of an SNCR or purchasing additional emission allowances,” Armstrong wrote.
Consent decree requires SCR, which OUCC doesn’t think is necessary
The 2007 NSR Consent Decree requires Rockport Unit 1 to install and to continuously operate an FGD system and SCR by Dec. 31, 2017. Rockport Unit 2 must also have an FGD and SCR by no later than Dec. 31, 2019. The Consent Decree does not specify what type of FGD must be installed, Armstrong noted. As long as the AEP Eastern System is able to achieve the annual SO2 caps in the Consent Decree, the proposed DFGD will meet the SO2 requirements for Rockport. With regard to NOx control, the Consent Decree is very specific that Rockport Units 1 and 2 must have SCR. As the law currently stands, the Consent Decree is the only reason that Rockport Units 1 and 2 would need SCR controls to operate beyond the next five years, Armstrong said. The OUCC’s position is that I&M should not be able to recover the costs of the Rockport SCR project through its Environmental Cost Recovery Mechanism.
Going the existing emissions control route is not a given, Armstrong noted. AEP’s Kentucky Power (KPCo) unit has recently withdrawn an application for a DFGD on Big Sandy Unit 2 at the Kentucky Public Service Commission in order to consider alternatives. Consumer parties objected to the project, stating that KPCo had not selected the lowest cost compliance plan. “Since AEP evaluates its environmental compliance options at the parent company level for all of its subsidiaries, the OUCC has concerns that some alternatives or options to the REP may not have been considered in its analysis,” said Armstrong.
Alternatives to DFGD include switching to low sulfur coal, coal washing, DSI, circulating dry scrubbers (CDS) and wet FGD systems (WFGD). Rockport Units 1 and 2 have been using a low sulfur blend of coal for several years. “I understand that I&M has already evaluated the possibility of installing a wet FGD over the DFGD, and the Company’s current plan is to utilize a DFGD because it will cost less and result in the needed SO2 reductions for compliance with future environmental regulations,” Armstrong wrote. “Furthermore, WFGDs generally have higher capital and operating costs than DFGDs.”
There are multiple technologies to reduce NOx emissions such as low NOx burners, Overfire Air (OFA) systems and SNCRs. Rockport Units 1 and 2 already have low NOx burners and OFA systems installed. There is also another multi-pollutant removal technology that has gained attention in the industry recently known as Regenerative Activated Coke Technology (ReACT), Armstrong pointed out.
Gas-fired replacement for a Rockport unit considered
It is also possible to replace Rockport with a different type of generation technology altogether. A new baseload natural gas combined cycle (NGCC) facility will meet the greenhouse gas New Source Performance Standards without needing to install carbon capture and storage, Armstrong wrote.
Brendon Baatz, a Utility Analyst in the Resource Planning and Communications Division at the OUCC, noted in July 13 testimony that I&M outlined three options for Rockport.
- Option #1 – Retrofit a single unit at Rockport with FGD and SCR as required by the Consent Decree;
- Option #2 – Retire a single unit at Rockport by Jan. 1, 2016, and replace it with a similar sized new build NGCC unit; and
- Option #3 – Retire a single unit at Rockport by Jan. 1, 2016, and replace with purchased energy and capacity through 2025. Option #3A assumes replacement of capacity through the existing AEP Power Pool and Option #3B assumes replacement of capacity through PJM markets.
I&M has not issued a formal request for proposals (RFP) to determine whether generation currently exists to replace the power needs of Rockport, Baatz noted. Although each Rockport unit is big at 1,300 MW, there may be existing units on the market offering a purchase power agreement sufficient to meet I&M’s needs, Baatz added. The January 2012 dispatch order for the AEP East Pool showed the new Dresden NGCC unit dispatched ahead of both units at Rockport. This means that the Dresden NGCC unit has a lower variable cost per MWh to operate than the Rockport units.
“Following the installation of environmental controls at Rockport, the units would experience higher variable O&M costs, which may alter the dispatch levels of the units further,” Baatz wrote. OUCC wants AEP to model other control technologies and options for Rockport to see if there are cheaper alternatives currently available, he added.