Empire District Electric adding air controls at Asbury coal unit

In order to comply with environmental regulations, Empire District Electric is taking actions to implement its compliance plan and strategy (including adding a new scrubber at Asbury), the utility said in an integrated resource plan filed July 1 at the Missouri Public Service Commission.

This Compliance Plan is already in action and largely follows the preferred plan presented in the 2010 IRP, along with what was in Empire’s 2012 IRP Annual Update.

The Compliance Plan calls for:

  • the installation of an SO2 scrubber, fabric filter, and powder activated carbon injection system at the Asbury plant (collectively referred to as the Asbury air-quality control system or AQCS) by early 2015 at a cost of $112m to $130m. The Asbury plant consists of two coal-fired units totaling 203 MW. Unit 1 (189 MW) was installed in 1970 and Unit 2 (14 MW) was installed in 1986. The Asbury AQCS and turbine project is currently in progress as of the filing of this IRP. The addition of this air control equipment will require the retirement of Asbury Unit 2, which has been used for peaking purposes, but the surviving Asbury Unit 1 will gain efficiencies and be uprated from 189 MW to 194 MW;
  • the transition of the Riverton Units 7 (38 MW) and 8 (54 MW) from operation on coal to full operation on natural gas. Riverton Units 7 and 8 last burned coal on Sept. 18, 2012, ending a roughly 60-year run of coal-fired production from these two units. Unit 7 is rated at 38 MW burning 100% natural gas and was installed in 1950. Unit 8 is rated at 54 MW burning 100% natural gas and was installed in 1954;
  • the now gas-fired Riverton Units 7 and 8, along with Riverton Unit 9, a small gas/oil-fired combustion turbine that requires steam from Unit 7 for start-up, are to be retired upon the conversion of Riverton Unit 12, a recently-installed simple-cycle combustion turbine, to a combined-cycle unit. The conversion of Riverton 12 is currently scheduled for the 2016 timeframe and was included as a committed resource for this IRP compliance filing.

Empire worked with parties to re-review Riverton uprate project

Riverton Unit 12 is a natural gas-fired Siemens V84.3A2 combustion turbine that was installed at the Riverton power plant in Riverton, Kansas, in 2007. It is currently rated at 142 MW for the summer peak season and it is primarily used as a peaker. When this unit was originally constructed adequate natural gas piping and electrical transmission were designed and built to accommodate its conversion to a combined-cycle unit at some point in the future.

The Riverton 12 upgrade project will add about 100 MW to the system, making the Riverton combined-cycle facility around a 250-MW unit upon completion. A heat recovery steam generator (HRSG) will be installed along with a new steam turbine and a cooling tower to provide cooling water for the condenser. A new control room and control system will also be installed to operate the unit.

In an application for waiver and extension regarding the 2013 IRP, Empire agreed to further evaluate the supply-side resource proposal prior to completion of the 2013 IRP with the help of an outside consultant. Ventyx, who was already retained by Empire for work on the 2013 IRP, conducted the 2016 resource analysis. As part of the agreement, Empire provided a statement of work for this study, and it was reviewed and amended by the interested parties. Ventyx performed the study by utilizing the 2013 IRP assumptions and the methodology reviewed by all parties in the scope of work statement as amended based on stakeholder input.

A study report was supplied to the interested parties on April 5 and a meeting to discuss the results was held on April 23. The study showed that the Riverton conversion project was the lowest cost and lowest risk resource option for Empire for its 2016 resource need. In addition, there were several other key factors such as operational issues, transmission and congestion cost risks and unit age that favored the Riverton 12 conversion option. Empire said it expressed to the interested parties that the Riverton 12 conversion is the lowest cost 2016 supply alternative.

Empire worked with the engineering firm Black and Veatch (B&V) to develop a specification for the project to support the release of a request for proposal (RFP). The RFP was issued to six bidders in January 2013, and four bids were returned in response. Empire said it performed a rigorous evaluation of the bids, and after interviewing the two highest scoring proposals, is in the final selection and negotiation process. Empire has begun acquiring the necessary permits for the construction and operation of the Riverton Combined Cycle unit. At this time, construction is expected to begin in the summer of 2014, with the unit available for service in mid-2016.

Empire looks at exercising Plum Point purchase option

The Plum Point Energy Station is a 665 MW, sub-critical coal-fired facility located near Osceola, Ark. Empire is a joint owner of the unit at the 7.52%, or about 50 MW level. In addition, since September 2010, Empire has a 30-year power purchase agreement (PPA) for roughly an additional 50 MW of capacity from this unit and has an option to purchase an undivided ownership share of the 50 MW covered by the PPA in 2015.

For purposes of this IRP, the Plum Point PPA was not converted to ownership in any of the plans studied. From a resource planning perspective, the capacity level would not be altered during the 20-year planning horizon of this IRP based on the decision to continue with the PPA versus converting to ownership.

During the IRP development process, Empire analyzed the option to purchase the 50 MW of Plum Point capacity currently under PPA. The analysis indicated that under certain circumstances the conversion to ownership was a low cost long-term supply-side option. The decision to exercise the purchase option also has to take into consideration undefined issues that were not reflected in the IRP modeling. While Empire said it intends to maintain an ownership interest in the plant for the life of the asset (expected to be well in excess of 30 years), the risks of taking on an even larger ownership interest in the plant must be further analyzed.

Several risk factors including the plant ownership structure, availability of operating personnel, operation by a third party, plant equipment redundancy, and availability restrictions due to location, make this plant unique when compared to Empire’s other singly- and jointly-owned units. Empire said it must weigh the risks and costs associated with increased ownership, as well as the components of the purchase price, versus the guarantees and costs allowed in the PPA. Due to these uncertainties and other capital projects Empire is undertaking in the same timeframe, the timing of the conversion to ownership in 2015 may not be optimal. For these reasons, Empire said it will continue to explore options with the PPA holder, Plum Point Energy Associates.

In 2012, 73.1% of Empire’s total system input (in kWh) was supplied by its steam and thermal generation units, 1% was supplied by its hydro generation, and the remaining 25.9% was purchased power including wind energy. Coal-fired energy purchased from others under contract constituted 5.2% of Empire’s 2012 energy profile and wind energy purchases amounted to 15%. Empire’s total installed capacity is 1,388 MW, plus 65 MW of purchased capacity.

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.