Dogwood Energy argues that Empire should buy its gas capacity

Dogwood Energy LLC wants Empire District Electric Co. to consider power from Dogwood Energy as it looks to shut coal-fired capacity and adjust its gas-fired generating position in the next few years.

On April 26, Dogwood Energy filed comments with the Missouri Public Service Commission, which in April 2011 had approved an integrated resource plan for Empire District Electric. The comments related to a March 27 stakeholder workshop that Empire held to update parties on the IRP.

At the annual update workshop, Empire stated that for purposes of the annual update it had not reexamined any alternatives from its 2010 IRP, but rather had only adjusted the timing of various components of the preferred plan, Dogwood noted. “A principal component of Empire’s adjusted preferred plan involves a costly conversion of the Riverton 12 combustion turbine generating unit to a combined cycle facility, adding 108 MW to Empire’s supply portfolio,” Dogwood added. “As adjusted, that conversion would now occur in 2016. Preparatory steps would include conversion of the Riverton 7 and 8 plants from operating primarily on coal to natural gas in late 2013. Subsequent to the Riverton 12 conversion, plants 7, 8 and 9 would be retired, removing 104 MW from Empire’s supply portfolio.”

As required by the commission’s IRP approval order, Empire should obtain more comprehensive information on its supply alternatives, fully examine purchase power and other supply alternatives, and improve its assessment of integration of intermittent supply sources such as wind and its overall risk evaluation process, Dogwood added.

“To that end, on April 18, 2012, Dogwood sent a thorough proposal to Empire describing a currently available option to purchase a share of its remaining majority ownership in the Dogwood Energy Facility, a combined cycle plant in Pleasant Hill, Missouri, involving up to 100 MW (or even more) of the plant’s capacity, at a cost significantly less than the cost of new construction. Dogwood recently closed on such sales to three other utilities serving load in Kansas and Missouri for a total of 27.5% ownership in the Dogwood Energy Facility and has implemented joint ownership and operation of the Dogwood Energy Facility with its new co-owners.”

An ownership position for Empire in the Dogwood Energy Facility represents a viable alternative, free of the construction and other risks inherent in the contemplated conversion of the Riverton 12 unit to combined cycle, Dogwood said. The Dogwood plant option can be made available in late 2013, obviating the need to continue to operate Riverton units 7, 8 and 9 for three additional years until a conversion of Riverton 12 to combined cycle could be completed, Dogwood argued.

“There have been dramatic reductions in gas prices since Empire developed its IRP – far beyond anything anticipated – as well as significant declines in load forecasts,” Dogwood added. “Such changes underscore the advantages of options such as the existing Dogwood plant versus riskier and more expensive construction projects. Taking advantage of an existing plant as soon as practicable, rather than waiting until new construction can be planned, developed and completed, offers much greater flexibility, both in terms of immediate availability as well as cost savings that preserve financial resources to address other needs down the road.”

Since Empire’s Preferred Plan also indicates a need for an additional 250 MW of combined cycle capacity in 2019, any planning and analysis performed to date by Empire on conversion of Riverton 12 to combined cycle operation would not be wasted, since it could be evaluated for Empire’s 2019 combined cycle capacity addition, Dogwood added.

Empire filed a one-page update with the commission in April that lays out in bare terms its power plants. It shows the Riverton 7 and 8 coal units not being available as of 2014. It also shows the Riverton combined cycle plant, at 250 MW, being available as of 2016.

Riverton coal-to-gas conversions part of air plan

Said Empire in a more complete IRP update filed in March at the commission about its clean-air planning: “Empire is taking actions to implement its compliance plan and strategy (Compliance Plan). This Compliance Plan largely follows the preferred plan presented in the most recent IRP. The Compliance Plan calls for the installation of a 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 ranging from $112 million to $130 million. The addition of this air quality control equipment will require the retirement of Asbury Unit 2, an 18 megawatt (MW) steam turbine that is currently used for peaking purposes.”

The Compliance Plan also calls for the transition of Riverton Units 7 and 8 from operation on coal to full operation on natural gas after the summer of 2013. Riverton Units 7 and 8, along with Riverton Unit 9, a small combustion turbine that requires steam from Unit 7 for start-up, will be retired upon the conversion of Riverton Unit 12, a recently installed simple cycle combustion turbine, to a combined cycle unit. This conversion is scheduled for the 2016 timeframe.

The most significant fuel price change since the September 2010 IRP filing is the recent drop in natural gas prices, the Empire update said. Current market power prices are also lower than the IRP assumed due to its correlation with natural gas price. The production of natural gas from shale formations has “rejuvenated” the natural gas industry in the United States, Empire wrote.

Additionally, the base natural gas prices in Empire’s most recent IRP assumed that a carbon cap and trade system would be in place beginning in 2015, which was assumed to increase the use of natural gas as a fuel for the production of electricity, putting upward pressure on the natural gas price. But, since CO2 regulation has been shelved by Congress, Empire’s five year business plan for 2012 through 2016 does not contain any carbon costs.

Overall, coal prices used in the September 2010 IRP compare closely to current coal price projections for Empire’s coal units. For the purposes of this update, a weighted average cost of coal has been developed to compare the 2010 IRP versus Empire’s five year business plan. At this time, Empire has not developed coal costs for the 2013 IRP. The current projection for the weighted average cost of coal is slightly higher than the 2010 IRP for the period 2012 through 2016.

Empire’s updated load forecast depicts a slower anticipated rate of load growth as a result of the more recent assumptions which includes a prolonged economic downturn. Both forecasts contain the impacts of existing demand side management (DSM), increased efficiency standards as well as conservation trends, but no impacts of future DSM. As a result, the more recent forecast contains recent energy efficiency and conservation trends that were not present in the 2010 IRP forecast. The more recent forecast presented in this update also contains a slightly lower anticipated customer count in the early years of the forecast due to the 2011 Joplin tornado.

The base load forecast from the September 2010 IRP filing had a compound demand growth rate (net peak demand) of about 2% and a compound energy growth rate (net system input or NSI) of about 2.4%. The low-growth case from the September 2010 IRP filing had a compound demand growth rate of about 1.60% and a compound energy growth rate of about 1.91%. For comparison, the corresponding compound growth rates for this 2012 IRP update is about 0.77% for demand and about 0.81% for energy.

Contracts signed earlier this year for Asbury retrofits

The Asbury plant, located near Asbury, Mo., consists of two coal-fired units totaling 207 MW. Unit 1 (189 MW) was installed in 1970 and Unit 2 (18 MW) was installed in 1986. In the September 2010 IRP Empire studied various scenarios related to the Asbury coal plant. This included the potential retrofitting of the plant to include installation of additional environmental equipment so the plant would be in compliance with prospective regulations that could require maximum achievable control technologies in the 2015 timeframe. Asbury in 2008 got selective catalytic reduction equipment (SCR) installed for NOx control.

Several IRP plans, including the preferred plan, proposed the installation of a scrubber to reduce SO2, a fabric filter to reduce particulate matter, and a powder activated carbon injection system to reduce mercury at Asbury (collectively referred to as the AQCS). In Empire’s last IRP a commitment was made to investigate permitting requirements, issue a request for proposal (RFP) for the project and evaluate the RFP bids.

In October 2010, Black & Veatch (B&V) completed the Asbury AQCS study that was under way at the time that Empire filed its September 2010 IRP. In January 2011, Empire’s Asbury AQCS team began working with B&V to develop technical specifications based on the recommendations of the Asbury AQCS study. These technical specifications were delivered to Empire in May 2011, at which time Empire began working with Sega Inc. to issue an RFP and to evaluate the resulting proposals. The RFP was issued in June 2011.

Empire spent about two months evaluating the five proposals before selecting the proposal submitted by a joint venture of Alberici Constructors (St. Louis, Mo.) and Stanley Consultants (Muscatine, Iowa). Empire executed a contract with the joint venture on Jan. 16, requiring completion of the project by Feb. 1, 2015.

Associated with the Asbury AQCS project and other pending environmental regulations is the potential need for an ash landfill and bottom ash conveyance equipment at the Asbury plant. In mid to late 2012 the U.S. Environmental Protection Agency is expected to finalize new regulations pursuant to its authority under the federal Resource Conservation and Recovery Act (RCRA) governing the management and storage of Coal Combustion Residuals (CCR), often referred to as coal ash. Empire anticipates the new rule will require the permitting of a new ash landfill along with the conversion of the existing wet ash handling to a dry system for the Asbury AQCS project. The permit application and approval process for the landfill construction permit is estimated to be 60 months. It is anticipated that Empire’s existing ash impoundments will be allowed to close in place under applicable state requirements.

Riverton Unit 12 is a natural gas-fired Siemens V84.3A2 combustion turbine that was installed at the Riverton power plant in Riverton, Kan., in 2007. It is currently rated at 142 MW for the summer peak season and it is primarily used as a peaking unit. When this unit was originally constructed adequate natural gas piping and transmission were designed and built to accommodate its later conversion to a combined cycle unit. The potential Riverton 12 conversion to a combined cycle unit was considered as a candidate resource in the most recent IRP (September 2010 IRP). In all 17 plans that were studied, including the preferred plan, the Riverton combined cycle project was selected as the first supply-side resource addition for the 2015 timeframe. This project is assumed to add about 100 MW to the system, making the Riverton combined cycle a roughly 250 MW unit upon completion.

In this project, 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 combined cycle unit. Upon completion of the project, Riverton Units 7, 8 and 9 will retire.

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.