Duke Energy Indiana runs into opposition to new coal projects

The Indiana Office of Utility Consumer Counselor (OUCC) has come out against some of a sweeping series of new air emissions retrofit projects that Duke Energy Indiana (DEI) requested in a June 28 filing with the Indiana Utility Regulatory Commission.

DEI, a unit of Duke Energy (NYSE: DUK), is seeking a Certificate of Public Convenience and Necessity (CPCN) for multi-pollution control projects on its coal-fired Cayuga, Gallagher, and Gibson plants. These projects include:

  • selective catalytic reduction (SCR) for NOx control, SO3 mitigation systems, mercury re-emissions chemical systems, and activated carbon injection (ACI) systems on Cayuga Units 1 and 2;
  • ACI systems on Gallagher Units 2 and 4; and
  • mercury re-emission chemical systems and ACI systems on Gibson Units 1-5.

DEI is also seeking cost recovery to track capital, depreciation, and operation and maintenance (O&M) costs of the Phase II Environmental Compliance projects through its Standard Contract Rider Nos. 62, 63, and 71.

“The OUCC has concluded that the Cayuga Units 1 and 2 SCRs and SO3 mitigation systems and the Gibson Units 1-4 ACI systems are not necessary to meet environmental regulations at this time,” wrote OUCC official Cynthia Armstrong in Nov. 29 testimony filed at the commission in this case. “As discussed below, this conclusion is based on the OUCC’s review of impending environmental regulations, the effectiveness and cost of mercury control technologies, DEI’s historical emissions, and the results of DEI’s recent emission tests on its coal-fired generating units. The OUCC has also concluded that it is too speculative at this time to determine whether the Cayuga SCRs would eventually be required by changes to the 8-hour Ozone National Ambient Air Quality Standards (‘NAAQS’).”

Armstrong provided a long list of U.S. Environmental Protection Agency rules impacting the coal plants, but the primary regulations she focused on are the Mercury and Air Toxics Standards (MATS), Cross-State Air Pollution Rule (CSAPR), Clean Air Interstate Rule (CAIR, left in place by federal court that vacated CSAPR), and 8-hour Ozone NAAQS, as these have the most impact on DEI’s proposed environmental projects.

“While there are some measures that DEI will need to take in order to ensure its coal-fired units comply with MATS, not all of the projects that DEI has proposed for its Phase II Environmental Compliance Plan are necessary to meet the new mercury, acid gas, and non-mercury metal emission limits under MATS,” Armstrong wrote. “Specifically, the Cayuga Units 1 and 2 SCRs and SO3 mitigation systems and the Gibson Units 1-4 Activated Carbon Injection Systems are unnecessary to comply with MATS and other existing and pending air regulations at this time. Upon looking at the historical emissions of DEI’s coal-fired units, the Gallagher Units 2 and 4 ACI systems, the Gibson Unit 5 ACI system, and the Gibson mercury re-emission chemical systems also appear that they may be unnecessary, but as explained below, the OUCC does not oppose the approval of these systems.”

Armstrong said data given to the OUCC by the utility doesn’t paint a clear enough picture. “With conflicting data, the OUCC is challenged in determining which environmental projects are necessary for DEI’s units to continue operating and serving the needs of DEI’s ratepayers. All of the projects requested by Duke in this case target mercury emissions from its generating units. Based on the data DEI itself has provided in responses to data requests, the only facility that would need any additional equipment is Wabash River, which DEI is planning to retire in 2015. This data set also shows that Gallagher would not meet the new PM standard, when it already has a baghouse – the most effective control technology for controlling PM emissions. Even with these inconsistencies, the OUCC does not want to discount this information if it represents actual measured emissions from DEI’s [electricity generating units] over a length of time that would be similar to the MATS averaging period.”

Armstrong says Duke building in too much costly redundancy

At another point, Armstrong wrote: “DEI’s proposed MATS compliance plan for Cayuga Units 1 and 2 is more than what is necessary for Cayuga to be in compliance with MATS. DEI is building redundancy into the configuration of Cayuga by asking for the SCRs, the mercury re-emissions control, and the ACI system. If one of these control systems fails, there will be two more mercury control systems in place that can operate. This may allow Cayuga to remain in compliance while operating at higher capacity factors than it has historically operated. While this will assist the Cayuga facility to operate at higher loads if DEI chooses to dispatch this unit more often in the future, the OUCC questions whether these expenditures are worthwhile and necessary. DEI Witness Kent Freeman shows the annual recovery of DEI’s Phase II Environmental Compliance Plan projects in his Confidential Workpapers and OUCC Witness Bradley Lorton displays an economic comparison between these technologies in his testimony. Ratepayers would pay approximately $35 to $45 million more per year to operate the Cayuga SCRs at full load under any condition during any part of the year. Since Cayuga has operated at capacity factors between 55% and 70% over the past five years, operating Cayuga at a higher capacity factor may not be necessary or reasonable. The OUCC posits whether it would be wiser instead to expend resources on hedging the potential failure of Cayuga’s control technology with capacity and power purchases.”

The main advantage of installing SCRs on Cayuga is that they will also substantially decrease the NOx emissions from Cayuga Units 1 and 2. DEI states that the installation of the SCRs on Cayuga Units 1 and 2 on an accelerated timeline is necessary to meet new Ozone NAAQS limits by 2020. DEI asserts that it can avoid a baghouse on Cayuga Units 1 and 2 and still meet the MATS deadline by moving up the installation date of the SCRs, Armstrong reported. In addition, DEI states that installing SCRs on Cayuga will further improve the utility’s NOx budget positions under CSAPR.

DEI argues that accelerating the installation of the SCRs for MATS compliance will avoid the installation of baghouses on these Cayuga units. If a baghouse is needed to meet MATS, and if DEI is eventually required to install SCRs on Cayuga Units 1 and 2 to comply with ozone NAAQS, then installing SCRs now for MATS compliance would avoid the investment in baghouses for Cayuga Units 1 and 2, Armstrong wrote. But, Duke has not provided enough evidence for the OUCC to verify the assertion that a baghouse would be required for MATS compliance in the absence of an SCR on Cayuga, she added. DEI conducted testing on Cayuga Units 1 and 2 to determine if ACI and mercury re-emissions additives were viable technologies for mercury control on these units. The tests showed that both technologies have a positive impact on mercury emissions from those units, but the company has not tested ACI and mercury re-emissions additives simultaneously, so the combined performance of these technologies on Cayuga’s mercury emissions is not known.

“Even if the SCRs are needed in 2020, it is better for consumers to wait for installation; every year that these projects are delayed translates into approximately $50 to 55 million in annual revenue requirements that will not be added to DEI’s rates,” Armstrong said. “Furthermore, DEI has not conducted tested mercury re-emissions additives and ACI simultaneously on Cayuga Units 1 or 2 to determine the cumulative impact on Cayuga’s mercury emissions, and this information is vital to determine whether the SCRs should be installed now rather than at some future date.”

Based on Cayuga Units’ 1 and 2 historical NOx emissions and the planned retirement of Wabash River Units 2-6 in 2015, it appears that DEI’s coal units will receive more NOx allowances than its NOx emissions will be, Armstrong pointed out. This assumes that operation of these units will be similar to what has occurred in the 2009-2011 timeframe. Even if Cayuga Units 1 and 2 were to operate at 80% of their maximum designed heat input, DEI’s NOx shortfall (assuming no NOx allowances were banked from previous years), would be about 2,800 tons per year. This shortfall could be replaced by allowance purchases, Armstrong noted.

OUCC says Gibson Unit 5 needs ACI, other Gibson units not so much

Turning to issues related to ACI, Armstrong pointed out that Gibson Unit 5 has the highest mercury emissions of the five units, and if DEI were to use facility-wide averaging for Gibson, Unit 5’s emissions have the potential to throw the entire facility out of compliance with MATS, especially if DEI dispatches Gibson 5 more often than it has operated this unit lately. In order to provide an ample margin between mercury emissions at the MATS mercury limit for Unit 5 and the entire Gibson facility, ACI installation on Unit 5 is necessary. “The capital cost of the ACI equipment is worth the operational flexibility that Unit 5 would gain from the additional mercury removal of the ACI,” Armstrong wrote.

On the other hand, there is not much evidence that the other Gibson units need ACI after mercury re-emissions are minimized, Armstrong said. Testing results suggest that only one control technology is needed for Gibson Units 1-3, and that the mercury re-emissions additive would provide the most incremental removal. There are conflicting tests suggesting that further long-term mercury re-emissions testing should be conducted on these units to confirm that mercury re-emissions is a prevalent problem with these units’ flue gas desulfurization (FGD) systems. “DEI should continue following the issue of mercury re-emissions on Gibson Units 1-5 and report back to the Commission, the OUCC, and other interested parties so that a decision regarding the potential need for ACI on Gibson Units 1-4 can be discussed in the future if it is needed,” she added.

Armstrong’s recommendations are:

  • The commission should deny DEI’s CPCN request for the SCRs on Cayuga Units 1 and 2, SO3 mitigation on Cayuga Units 1 and 2, and ACI systems on Gibson Units 1-4. The total cost of these avoided projects is redacted from the public version of her testimony.
  • The commission should approve DEI’s CPCN request for mercury re-emissions control on Cayuga Units 1 and 2 and Gibson Units 1-5. DEI should continue to monitor and test mercury re-emissions on all of these units and report back to the commission, the OUCC, and interested parties.
  • The commission should approve ACI installation on Cayuga Units 1 and 2, Gallagher Units 2 and 4, and Gibson Unit 5.
  • DEI should continue to monitor and report mercury emissions over a longer period of time more representative of the 30- or 90-day MATS averaging periods for mercury. If long-term testing and monitoring of the mercury re-emissions additives and ACI shows that the other projects the OUCC recommends disapproval of are necessary to meet the MATS, then it should re-file a petition seeking commission approval of these projects.
  • In any re-application for those environmental compliance projects, DEI should demonstrate that alternative technologies or control measures are either not feasible or as cost-effective as the proposed compliance plan. DEI should include any feasible technology or compliance alternatives in its overall integrated resource plan (IRP) analysis and should not run the only option that it has selected from its Engineering Screening Model as the preferred compliance plan. Furthermore, if operating a unit at a lower load to decrease emissions and supplementing the capacity and power from the unit is possible to avoid substantial pollution control investment on that unit, then this option should also be presented as part of DEI’s analysis. “The OUCC is troubled by the fact that DEI only included its one, desired compliance plan, in its analysis of whether to retrofit, repower, or retire units in this proceeding,” Armstrong added.

Enviros claim utility should have done more with energy efficiency

As has become common in cases like this where a utility is arguing for what are essentially life-extension projects for coal-fired plants, environmental groups have intervened in the DEI case to argue that none of these projects are justified. Frank Ackerman of consultant Synapse Energy Economics was one of the parties that provided Nov. 29 testimony to the Indiana commission from the Citizens Action Coalition of Indiana, Sierra Club, Save the Valley and Valley Watch.

Ackerman said he identified areas where the company’s analysis is inadequate, presented a Synapse base case that improves the treatment of two of these areas, and evaluated the proposed CPCNs for the Cayuga and Gallagher units under the Synapse base case and other scenarios. Of the four areas of inadequacy, he said:

  • First, the company should have analyzed the potential for increased energy efficiency and demand response beyond the minimum amount required by the commission. This analysis should include the option of continued expansion of energy efficiency and demand response programs beyond 2020, the date at which the company projects an abrupt halt to almost all new initiatives in these areas.
  • Second, the company should examine low load-growth scenarios in greater detail, and explore scenarios below its current low-load scenario, to reflect the substantial risks of continued macroeconomic instability. The suggestion that the current low load-growth scenario could represent either lower load growth or energy efficiency, said Ackerman, conflates two unrelated factors that deserve separate treatment: cost-effective energy efficiency and demand response should always be pursued, and in addition, the company should consider risks such as macroeconomic instability that might lower load growth in its scenario analysis.
  • Third, the company should analyze its proposed investments under scenarios with higher CO2 prices, rather than comparing only a relatively low price to no price at all.
  • Finally, Ackerman said that DEI should consider fuel price scenarios with a wider range of relative prices of coal vs. gas. The ratio between these two prices is of great importance to the company’s analysis, which in large part compares continued operation of retrofitted coal plants against replacement with gas plants, he added.

“Stress testing” of resource options against such scenarios will provide a better understanding of the risks facing company ratepayers, Ackerman added.

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.