The primary features of Duke Energy Indiana’s Phase 2 compliance plan for the 2014-2015 period include new, “critical path” selective catalytic reduction systems (SCRs) on Cayuga Units 1-2.
The utility described its plans in recent filings with the Indiana Utility Regulatory Commission. Other Phase 2 projects include:
- dry sorbent injection (DSI) systems on Cayuga Units 1-2 for SO3 mitigation;
- activated carbon injection (ACI) systems on Cayuga Units 1-2, all five Gibson units and Gallagher Units 2 and 4; and
- mercury re-emission chemical injection systems on Cayuga Units 1-2 and Gibson Units 1, 2, 3 and 5.
These Phase 2 projects were designed primarily to meet the requirements of the U.S. Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) and are targeted towards mercury reductions at these units (with the exception of the DSI systems at Cayuga, which are proposed for SO3 mitigation). The company tentatively plans to file its Phase 3 compliance plan with the commission by the spring of 2013, said Douglas Esamann, President of Duke Energy Indiana, an indirect subsidiary of Duke Energy Corp. (NYSE: DUK).
The implementation of the prior, Phase 1 plan was substantially complete by the fall of 2008, when the second of the new scrubbers at the Cayuga plant was placed into service.
Esamann was one of several Duke officials that supplied June 28 testimony to the commission in an environmental cost review case. He noted that EPA programs like MATS and the Cross-State Air Pollution Rule (CSAPR) put a heavy burden on the company’s coal units. “Duke Energy Indiana’s only options for each unit are clear – lower emissions or shut it down,” he added. “While our compliance options under the MATS rule are severely limited, long-term environmental compliance planning and implementation remains extremely complex for electricity generators.”
The company’s tentative Phase 3 projects, to be executed in the 2014-2020 period, include:
- Gibson Units 1-3 precipitator enhancements;
- Gibson Unit 5 flue gas desulfurization (FGD) replacement, since the existing FGD is a 1970s vintage technology, while the Units 1-4 FGDs are newer;
- Cayuga Units 1-2 and Gibson Units 1-4 FGD enhancements;
- Gibson Units 1-5 SCR upgrades; and
- Gallagher Units 2 and 4 selective non-catalytic reduction (SNCR) installation.
Wabash River retirements reduce coal in Duke’s Indiana fuel mix
Duke Energy Indiana owns 12 generating stations and 60 generating units, with a total capacity of over 7,215 MW. The company remains heavily reliant on coal: 70% of its generating capability is coal-fired, with 26% natural gas-fired, 3% oil-fired, and less than 1% hydro-powered. About 97% of the energy generated by its units in 2011 was produced from its coal units. As a result, the company is Indiana’s largest purchaser of coal – about 12.5 million tons annually, most from Indiana mines. This portfolio will become less dependent on coal over time, with the projections for 2016 being that coal will make up only 58% of generating capability and 88% of generation.
Duke Energy Indiana’s plan includes the retirement of Wabash River Units 2-5 in April 2015, the oldest and smallest coal-fired units on its system, because the retrofit of these units will not be economical. The company is also assessing the long-term options for Wabash River 6 and Gibson 5, including reviewing the potential for retrofitting Wabash River Unit 6 to run on natural gas by April 2015.
Duke Energy Indiana decided to take additional time in the development of some components of its MATS compliance plan because there were major changes to the final rule versus the proposed rule. Most importantly, as a result of the changes to the final MATS rule, the company was able to avoid the installation of several baghouse projects. Now that the company does not need to install the baghouse projects, there is a need to develop scope and cost estimates for precipitator upgrades, which are needed to ensure adequate performance due to the addition of the ACI systems.
“The Company felt it was necessary to present its Phase 2 projects now because we need to start construction work on the Cayuga SCR projects this summer in order to have them in service by the MATS rule compliance date,” Esamann wrote. “The two Cayuga SCRs are the critical path projects in our Phase 2 Plan.”
MATS work practices could eliminate Gallagher ACI installations
An area of uncertainty that could impact the company’s Phase 2 plan relates to the implementation of the MATS rule’s work practice standards. Depending on how the standards are implemented, there is a potential that the ACI systems for Gallagher Units 2 and 4 could be cancelled. “However, based on what we know today, it is prudent to plan for the ACI systems for Gallagher Units 2 and 4 to comply with the MATS rule, but also to include a potential ‘off ramp’ prior to expending significant dollars,” Esamann explained.
The company’s Phase 2 compliance plan is estimated to require a capital investment of about $450m, plus actual accrued AFUDC.
The Esamann testimony presented the overall compliance plan, with more details provided in companion testimony from Joseph Miller Jr., employed by Duke Energy Business Services LLC as General Manager, Analytical & Investment Engineering.
The company wasn’t able to identify any potential environmental control options that were economically viable for Wabash River Units 2-6 for long-term continued operation as coal units, Miller noted. “To ensure minimum compliance with MATS, we would expect to install baghouses with ACI for mercury control, and DSI for hydrogen chloride control; in addition, it would be necessary to switch to low sulfur, low chlorine western fuels. When the costs of these projects are combined with the future expected costs for the other pending environmental regulations, the overall economics do not support the continued use of coal at Wabash River when compared with construction of new natural gas-fired generation.” Duke is still investigating opportunities to potentially continue operations of the coal unit, at least short-term.
Miller added: “Wabash River Unit 6 is the largest (at 318 net MW), newest, and most efficient of the units at the Station. We are investigating an option to convert the unit from coal-fired to natural gas-fired by replacing the coal burners in the boiler with gas burners. There is already a large natural gas supply line at the site, which we could access, that supports the Wabash River IGCC unit.”
In the 1990s, the old Wabash River Unit 1 was repowered to an integrated gasification combined cycle (IGCC) facility that is currently controlled by the Wabash Valley Power Association and is not part of the Duke Energy Indiana environmental planning process.
Duke Energy Indiana reviewed the possibility of switching to low-sulfur coal with additional lower capital cost control options on Wabash River Unit 6 to allow it to continue to use coal. However, once the initial tests were performed, which indicated that a derate to 200 MW would be likely, this option was rejected.
Hydrogen chloride pushes Gallagher units toward western coals
One issue that involved a lot of evaluation of alternative coals was hydrogen chloride emissions. The scrubbed units performed exceptionally well in terms of hydrogen chloride emissions, with the exception of Gibson Unit 5, Miller noted.
“Gibson Unit 5 has older and less efficient FGD technology, and also employs an open, un-controlled bypass around the FGD absorbers,” Miller explained. “This bypass may require physical closure to improve the hydrogen chloride compliance margin. We also rigorously tested the Gallagher units, which have DSI systems and baghouses instead of wet FGDs. While we were able to achieve hydrogen chloride emissions below the MATS limit, compliance generally required higher injection rates of the hydrated lime reagent (the dry sorbent used at the Units). Also, we were not able to achieve hydrogen chloride compliance on the Gallagher units while utilizing Illinois Basin coals; the native chlorine content of these coals is simply too high for the DSI system to remove it to the required levels. We tested coal from both the Air Quality mine (lower sulfur and chlorine levels relative to Illinois Basin coals), and the Gibson County mine (more typical sulfur and chlorine levels for Illinois Basin coals). We have determined that the Gallagher units will have to be limited to low sulfur, low chlorine western fuels (such as Powder River Basin, Colorado, or Utah coal, or blends thereof), with higher DSI injection rates to achieve hydrogen chloride compliance. With this combination, the Company was able to determine that no additional control equipment will be required for the Gallagher units to achieve hydrogen chloride compliance.”
Air Quality is a Peabody Energy (NYSE: BTU) mine in Indiana noted for its unusually low-sulfur coal (thus the mine name), while Gibson County is an Alliance Resource Partners LP (NASDAQ: ARLP) mine in Indiana.
The company’s preliminary Phase 3 compliance plan includes additional MATS-related projects that are still undergoing testing and analysis, Miller wrote. “At this time, Duke Energy Indiana’s tentative Phase 3 plan includes precipitator enhancement projects (to address additional particulate loading from ACI) on Gibson Station Units 3, 4, and 5; potential boiler equipment improvements on Gibson Unit 5 to reduce exit gas temperatures and enhance flue gas mercury oxidation; our MATS rule monitoring strategy, including the potential for mercury CEMS, mercury sorbent trap devices, continuous particulate monitors, stack provisions to support testing on a quarterly frequency for hydrogen chloride at Gibson Unit 5 and possibly Gallagher Units 2 and 4; adding an FGD chemical additive system (di-basic acid or other acid) and/or other minor FGD enhancements to Gibson Unit 4 for further enhanced SO2 removal capability to meet the hydrogen chloride alternate compliance option with SO2; and development of our compliance plan, incremental costs, and up-front provisions that may have to be made on the units to comply with the Work Practice Standards for organics, and start-ups and shut-downs.”
Gibson Unit 5 on the bubble due to costly need to replace FGD
Uncertainty about SO2 National Ambient Air Quality Standards (NAAQS) implementation makes the Gibson Unit 5 FGD replacement less than certain, Miller said. The capital expense in the preliminary Phase 3 plan represents the risk for either the FGD project itself, or the potential for new capacity resources to replace Gibson Unit 5 should the ultimate economics support its retirement, he added.
Robert McMurry, Director, Integrated Resource Planning for Duke Energy Business Services, gave more detail about the Gibson Unit 5 deliberations in his own June 28 testimony. The utility analyzed three options for Gibson 5 for Phase 3 because of the uncertainty associated with SO2 NAAQS. The looked-at options are:
- The existing FGD can meet the new SO2 NAAQS with structural repairs. A range of costs were evaluated to represent the conditions if a new stack is required or if the existing stack can be repaired.
- A new FGD is required to meet the SO2 NAAQS.
- The Phase 2 controls are installed but Gibson 5 is retired at the end of 2017 and replaced with combined cycle gas-fired generation. The purpose of analyzing this option was to assure that installation of the Phase 2 controls is the best option regardless of whether Gibson Unit 5 ultimately installs Phase 3 environmental controls or is retired by the end of 2017.
The possibility of retiring any part of Gibson will be a shock to the coal industry, since Gibson has traditionally been considered one of a select group of big, relatively new coal plants in the U.S. (like Detroit Edison‘s Monroe plant in Michigan or several American Electric Power plants with one or more 1,300-MW units) that would largely be invulnerable to near-term retirement. The GenerationHub database shows the five units at Gibson, including Gibson Unit 5, with 668 MW of nameplate capacity apiece.
Duke projects coal price hikes, and drops, in its forecasting
Duke Energy Indiana’s plans are in part based on projected fuel prices. In the High Fuel Cost case, gas prices increase by 35% and coal prices by 20%. “The base case natural gas price projection is on the lower end of the range generated from multiple vendor estimates,” McMurry noted. “In general, we believe there is more upside risk associated with natural gas because of the potential that suppliers could limit new drilling until there is a higher supporting price. We are observing this in today’s market where suppliers are limiting new gas well installations due to the current low natural gas price. The +35% high gas sensitivity was based on two standard deviations off the mean based on the multiple vendor estimates. The Company examined the potential for increased coal prices primarily because of the risk of increased international exports. … The +20% coal price sensitivity generally follows the upper range of vendor estimates.”
In the Low Fuel Cost case, gas prices are projected to fall 20% and coal prices to drop 40%. “As stated above, our fundamental natural gas price projection is on the lower end of a range of vendor estimates,” McMurry wrote. “Also, the current reduction in drilling and hedging by gas suppliers limits our downside gas price forecast. The -20% low gas sensitivity was based on two standard deviations off the mean based on the multiple vendor estimates. The Company believes it is reasonable to analyze the potential for lower coal prices because of the significantly lower demand projection by the coal industry driven by coal retirements in the 2015 timeframe, fundamentally lower gas prices that offset coal generation, and additional longer-term retirements based on pending environmental regulations. … The -40% coal price sensitivity generally follows the lower range of vendor estimates.”
The company issued a request for proposals (RFP) in February for purchased power for a period of one to three years, starting with Planning Year 2014/15, as a stop-gap measure until longer-term capacity could be built or acquired. The RFP was issued primarily due to the expected retirement of Wabash River Units 2-6 in April 2015. The expected retirements were projected to result in a need for 300-400 MW of additional capacity to meet the MISO Resource Adequacy requirement.
“Five bids were received, three of which have been short-listed as candidates for further analysis and discussion,” wrote McMurry about the RFP process. “We are continuing to evaluate our need for short-term capacity and expect to make a decision regarding these bids later this year. We are also evaluating multiple options to meet the longer-term need, including self build options, purchase of existing assets, natural gas conversion, and purchased power agreements.”