While it sees coal as a continued major source of power generation, Great River Energy is reducing its coal exposure, accelerating the depreciation of two coal plants and negotiating with Dairyland Power Cooperative to exit a contract to buy 50% of the generation from the coal-fired Genoa Unit 3.
Great River Energy (GRE) filed an Oct. 31 integrated resource plan (IRP) with the Minnesota Public Utilities Commission that outlined its current thinking on its sources of generation capacity.
GRE owns three coal-fired power plants, all of which are located in North Dakota: Coal Creek Station (1,163 MW), Stanton Station (187 MW) and Spiritwood Station (99 MW). Its modeling and other analysis described in this IRP led it to the conclusion that these baseload power plants are least cost resources that should be retained during the 15-year forecast period of this IRP. Several factors led to this conclusion:
- GRE’s coal plants are its only significant baseload resources. Eliminating any of these plants would create unacceptable exposure to the market nearly every day of the year.
- GRE has over $1bn invested in its coal plants. Much of the investment is in connection with environmental upgrades. Although GRE in 2013 started to accelerate the remaining depreciation of Coal Creek Station and Stanton Station so that they will be fully depreciated by 2028, any retirement of either of these plants before that time would require GRE to write off significant assets.
- GRE’s coal plants are efficient, least cost resources. All of its financial analysis indicates that the coal plants provide the economic foundation for the affordable rates enjoyed by members and the physical foundation for the reliability of GRE’s service to its members.
- GRE’s coal plants are fully compliant with all applicable environmental regulations.
- GRE’s analysis indicates that, under the EPA’s proposed Clean Power Plan, GRE will be able to continue to operate all of its coal plants. Over the IRP planning period, under the proposed EPA methodology, GRE expects to achieve a 28% reduction in carbon dioxide intensity from 2012 levels.
- GRE’s modeling resulted in no retirements of its owned coal plants, under expected market and load growth conditions.
Coal as a percentage of the GRE portfolio has fallen sharply
While a majority of its generation comes from coal, GRE said it has taken important steps to diversify fuel types. Between 2001 and 2009, it added more than 1,200 MW of natural gas generation in the form of peaking plants. It added 469 MW of purchased wind power between 2005 and 2010. It also obtains renewable energy through hydroelectric energy purchases from the Western Area Power Administration and seasonal exchange agreements with Manitoba Hydro.
GRE generated approximately 11% of its electricity from renewable energy in 2013, including generation that uses refuse derived fuel from the Elk River Energy Recovery Station and power purchases from eight wind farms in Minnesota, North Dakota and Iowa. Hydroelectric power provided 13% of its electricity production in 2013. Coal-based energy provided 67% electricity production in 2013, down from 80% in 2005.
Spiritwood Station is the first utility-scale combined heat and power plant (CHP) in North Dakota designed to serve more than a single third-party steam user. Spiritwood Station, built several years ago but held on idle since then, will produce electricity and industrial process steam for the Midcontinent Independent System Operator (MISO) market and will produce industrial process steam for sale to third parties located nearby. The station will be in full commercial operation on Nov. 1, 2014, the resource plan said. This CHP facility will help make progress toward President Barack Obama’s August 2012 executive order calling for 40 GW of new CHP by 2020.
GRE and the Manitoba Hydro Electric Board (MHEB) executed a new 200 MW Diversity Exchange Agreement in July 2013 that will begin on Nov. 1, 2014, and continue through April 30, 2030. The agreement allows GRE to acquire summer capacity from MHEB and MHEB to acquire winter capacity from GRE. The agreement also provides GRE the opportunity to acquire hydroelectric energy from MHEB. GRE and MHEB have signed a Memorandum of Understanding (MOU) to jointly investigate the sale of up to 600 MW of electricity from MHEB to GRE, commencing in approximately 2020.
GRE has been, and is expected to remain, a summer peaking utility. Its 2014 summer coincident peak was 2,458 MW. The 2013 annual sales to members were 12,105,295 megawatt hours (MWh). GRE owns and operates a resource mix that includes 12 power plants and purchases power from several wind farms and other generating facilities, resulting in more than 3,500 MW of generation capability.
Regional haze program triggers new series of compliance measures
GRE is in good shape in terms of meeting EPA air emissions programs, with much of the current work centering on the regional haze best available retrofit technology (BART) rules. BART emission controls must be installed and operational no later than five years (i.e., April 2017) after EPA approves North Dakota’s state implementation plan (SIP) or finalizes its own federal implementation plan (FIP). EPA’s final SIP/FIP determination for North Dakota was published in April 2012. EPA approved North Dakota’s SIP relative to Stanton Station and relative to Coal Creek Station SO2 and particulate matter emissions. However, EPA rejected part of the North Dakota SIP and issued a FIP for more stringent Coal Creek Station NOx emission controls.
GRE disagreed with EPA’s FIP and filed a petition for review with the U.S. Court of Appeals for the Eighth Circuit. In 2013 the Eighth Circuit determined that EPA was “arbitrary and capricious” in its determination of a FIP for Coal Creek Station NOx controls. Consequently, the court instructed EPA to either accept the amended North Dakota SIP which provided for technical corrections, or reject it on different grounds before re-issuing a FIP. While EPA has yet to act, it is GRE’s expectation that EPA will ultimately approve the North Dakota SIP determination for Coal Creek Station NOx controls.
GRE at Coal Creek and Stanton has been working diligently on BART control strategies and fully expects to meet the regulatory timeline. Coal Creek Station has installed and has been operating DryFining, which uses waste heat from the power plant to dry lignite before it is burned in the plant, thus increasing boiler efficiency, as a foundational multi-pollutant control strategy since 2010. In addition, Coal Creek Station has been working on stack modifications in order to comply with the SO2 limit by the 2017 deadline. Finally, Coal Creek Station engineers recently identified and implemented a cost-effective electrostatic precipitator performance improvement to better control particulate matter, even though BART did not require it.
Stanton Station continues to evaluate dry sorbent injection (DSI) as an acid gas control to comply with its BART SO2 limit. Currently, Stanton Station has identified that sodium-based sorbents are effective at reducing the SO2 emissions to meet the BART limit. However, the sodium sorbents do interfere partially with activated carbon’s effectiveness at controlling mercury. As such, GRE continues to assess sorbents to better optimize the overall system. The most recent tests were completed in 2013 and involved a micronized lime product, which was injected into expected in late 2014 or 2015 to better understand the balance of plant impacts of the various dry sorbents and their possible interactions with activated carbon for mercury control.
For NOx reductions, Stanton Station has recently performed a third-party evaluation of tuning and burner operations to understand Stanton Station’s ability to consistently meet the BART NOx limit. Although these tests were encouraging, more work is needed to fully understand continuous operation of a range of operations.
Coal Creek Station’s novel multi-pollutant DryFining technology is foundational for several regulations including the BART requirements. In addition, Coal Creek Station is spending approximately $25m on flue gas design updates in order to prepare for the limits.
With respect to NOx controls, Coal Creek Station has already spent approximately $6m on expanded over-fire air and low-NOx burner upgrades on Unit 2. GRE expects to spend an additional $6m for the same level of NOx controls on Unit 1.
Stanton Station currently projects spending approximately $10m for a DSI system in order to comply with the BART SO2 limit. NOx costs are contingent upon pending research and could range from $3.3m to less than $1m, depending on the final configuration.
In 2018, North Dakota regulators are expected to start the second round of regional haze reductions. Cost-effective controls and associated visibility improvements will again be determined for all emission sources in the state, with an expected compliance date of no later than 2023 for any applicable control requirements.
GRE didn’t say much in the IRP about the Dairyland Power Cooperative (DPC) situation, saying at one point as one of its goals over the next five years: “Work with DPC to terminate our long-term contractual obligation to purchase 50 percent of the capacity and energy from Genoa 3.” GRE’s preferred plan subtracts that 119 MW of Genoa 3 capacity as of 2016.