Great River Energy does well on renewables, bracing for coal regs

New environmental retrofits for its coal-fired capacity and the waiting-in-the-wings Spiritwood coal plants are among the features of a 2012 resource plan that Great River Energy (GRE) filed Nov. 1 with the Minnesota Public Utilities Commission.

Based on GRE’s review of the expected load forecast, which includes demand response (DR), energy efficiency (EE) and conservation, existing resources, legislative requirements, sensitivities and expansion plans, a Preferred Plan was developed that meets members’ resource requirements at least cost while complying with regulatory requirements. Based on the information considered in this resource plan filing, the company’s first with the commission since 2008, GRE’s Preferred Plan includes:

  • Continued active conservation and EE programs;
  • Continued use of existing supply side resources, except where contracts expire;
  • Interaction with the market for cost‐effective energy purchases and sales;
  • Addition of renewable energy beginning in 2024 to meet the Minnesota Renewable Energy Standard (MN RES); and
  • No additional generation resources until after the forecast period.

GRE is a not‐for‐profit electric generation and transmission cooperative serving 28 member distribution cooperatives. Through its members, it supplies electric energy to nearly 645,000 customers in Minnesota and a small part of western Wisconsin. GRE’s resource mix includes 12 power plants and it purchases power from several wind farms and other generators, resulting in more than 3,500 MW of generation capability. Its portfolio is a mix of baseload and peaking power plants, including resources that utilize coal, natural gas, fuel oil, wind, hydro, refuse‐derived fuel (RDF), landfill and biogas energy.

A number of changes have occurred in the resource planning environment since GRE filed its 2008 Resource Plan. These changes include:

  • Lower annual residential customer additions as a result of a slowdown in housing starts within member cooperatives’ service areas.
  • Overall lower load and energy growth rates as a result of the economic recession and fewer housing starts.
  • The remaining six member cooperatives exercised their right to fix the amount of capacity and related energy they purchase from GRE.
  • The gas-fired, simple-cycle, 183-MW Elk River Peaking Station was placed into service in 2009.
  • The construction of the 99-MW Spiritwood Station combined heat and power project was completed. The plant will be fueled by dried and refined lignite. Based on the development of customer facilities that require process steam and other services from Spiritwood, GRE anticipates that the plant will be fully operational in January 2015.
  • GRE entered into long‐term agreements to purchase the output of two wind facilities, Ashtabula II and Endeavor I, totaling 151 MW. It began taking energy from the facilities in 2010 and 2011, respectively.
  • Two long‐term purchase agreements and one long‐term sales agreement expired and were not renewed.
  • One new long‐term capacity sale agreement was executed.
  • The Midwest ISO market continued to mature, which included changes to the MISO Resource Adequacy (RA) construct, which was approved by the Federal Energy Regulatory Commission in June 2012.
  • New drilling technologies and additional supply have led to lower natural gas prices.
  • The economic recession and lower natural gas prices have resulted in lower energy prices in the MISO market.

Another resource available to GRE is the Midwest ISO market. All of GRE’s resources are offered into the market, and all of its member loads are served from the market. Its resource portfolio provides a hedge against market prices. “In effect, we still meet a significant portion of our members’ energy needs through our resource portfolio,” the plan noted. “However, the MISO market provides us with access to a much broader pool of economically dispatched resources and economic management of transmission congestion and losses.”

GRE in good shape for Minnesota, Wisconsin renewables goals

GRE has added renewable resources well ahead of the timing requirements of the MN RES. It currently has 468 MW of wind resources under contract. It also processes municipal waste into refuse‐derived fuel (RDF) and uses the RDF to generate 21 MW at its Elk River Energy Recovery Station (ERERS) facility. Other sources include a 3-MW landfill gas generator in Elk River and two dairy farms with anaerobic digester projects.

GRE has added 151 MW of renewable energy to its portfolio since the 2008 Resource Plan was filed. It currently has sufficient renewable resources to meet the existing MN RES and the Wisconsin Renewable Energy Objective (WI REO) until 2024.

Several of GRE’s smaller wind power purchase agreements (PPAs) are scheduled to expire in the mid to late 2010s. Two larger wind PPAs are scheduled to expire in the mid‐2020s. The expirations of the two larger PPAs, combined with expected load growth and the legislatively-mandated future percent increase in the MN RES will result in the need for additional renewable energy beginning in the year 2024.

One of GRE’s energy efficiency initiatives is the DryFining technology. In December 2009, GRE commercialized the patented DryFining process. DryFining improves fuel quality by simultaneously drying and refining lignite coal. Through the system, which is in service at Coal Creek in Underwood, N.D., residual heat from plant processes is diverted and used to remove moisture from lignite coal before the lignite is fed into the boilers at Coal Creek. Through this process, the energy content of the lignite increases, reducing fuel input into the boilers and increasing plant efficiency. The technology also yields a significant reduction in stack emissions, reducing SO2, mercury, NOx and CO2.

Work done at coal plants to reduce emissions, up efficiency

GRE’s coal-fired plants are:

  • Coal Creek Station (CCS) is North Dakota’s largest power plant, with two units with total capacity of more than 1,100 MW. The fuel for the plant is dried and refined lignite, supplied by the adjoining Falkirk mine. CCS uses about 7.5 to 8 million tons of lignite per year. CCS is participating in several projects to test novel methods to further improve efficiency and reduce environmental impact. These include mercury research projects, fly ash sales, cogeneration for an ethanol plant and use of DryFining. Most of the fly ash produced at CCS is marketed primarily as a replacement for Portland cement and concrete. Blue Flint Ethanol (BFE) is located adjacent to CCS, which provides steam for the ethanol plant’s distiller’s grain drying and other system thermal requirements. In addition to the benefit of using low‐pressure steam that would normally be unused, the project results in much lower emissions than a stand‐alone ethanol plant.
  • Stanton Station, located near Stanton, N.D., is located on the bank of the Missouri River. The plant has a unique steam path involving two boilers feeding a single turbine on a common steam header. Stanton uses about 850,000 tons of Power River Basin (PRB) coal each year, which is rail delivered. Stanton’s boilers are equipped with particulate removal systems and the supplemental boiler has an SO2 scrubber. GRE is participating in mercury research projects at Stanton and CCS. In 2011 and 2012, Stanton completed several tests evaluating dry sorbent injection (DSI) along with activated carbon injection (ACI) to comply with pending air regulatory requirements such as Regional Haze/BART and MATS. “These preliminary tests demonstrate that DSI is a cost effective, compliance control strategy for SO2 and other acid gases, while also meeting MATS mercury reductions from ACI,” the plan said. Fly ash from Stanton is used to solidify liquid oil waste and for soil stabilization projects.
  • The 99-MW Spiritwood plant incorporates state‐of‐the art technologies and will be one of the cleanest coal plants in the world, the plan noted. For instance, Spiritwood intends to burn refined lignite shipped from CCS, and will use Best Available Control Technologies (BACT) for emissions. Construction of Spiritwood is complete and GRE said it anticipates that the plant will be in full operation in January 2015.
  • Genoa Station 3 (G‐3) is on the Mississippi River near La Crosse, Wisc. GRE has a life‐of‐the‐plant agreement with plant owner Dairyland Power Cooperative (DPC) for 50% of the output. This single-unit station has a capacity of 379 MW and burns blended coal from Wyoming and Utah. Nearly all of the coal ash is recycled into construction materials. Emission needs at G‐3 are impacted by a consent decree DPC entered into with the U.S. Environmental Protection Agency and the Sierra Club in 2012. The decree calls for DPC to add selective non‐catalytic reduction by June 1, 2015, and sets tighter emission limits for NOx, SO2 and particulate matter.

New EPA regs to have some impact, at some point, on coal units

To meet clean-air needs, upgrades have been made to the SO2 scrubbers on both units at CCS and on Unit 10 at Stanton. In 2004, Stanton switched from lignite to PRB coal, resulting in lower emissions. Current and imminent regulations such as the regional haze and the Mercury and Air Toxics Standards (MATS) rules require GRE to operate Coal Creek and Stanton at annual emission levels significantly lower than the number of annual SO2 allowances allocated under the Acid Rain Program, resulting in a surplus of SO2 allowances that can be used for Acid Rain Program compliance for any of its acid rain units.

EPA has promulgated a series of rules (referred to as ‘transport rules’) designed to address the transport and contribution of upwind states’ emissions to nonattainment of National Ambient Air Quality Standards (NAAQS) in downwind states. All such rules have been challenged in court and remanded back to EPA. The latest remanded rule, with the remand coming in August, was the Cross‐State Air Pollution Rule (CSAPR). The appeals court that did the remand left the Clean Air Interstate Rule (CAIR) in place while EPA reworks or replaces CSAPR, but CAIR is not applicable to Minnesota or North Dakota so it does not impact any GRE facilities.

The first phase of EPA’s regional haze rule requires certain power plants to install Best Available Retrofit Technology (BART) to control SO2, NOx and particulate matter emissions. In December 2009, the North Dakota Department of Health (NDDH) issued its final BART determinations for public comment as part of its regional haze State Implementation Plan (SIP). These emission controls must be installed and operational no later than five years (April 2017) after EPA approves North Dakota’s SIP or finalizes its own Federal Implementation Plan (FIP). EPA’s final SIP/FIP determination for North Dakota was published on April 6. EPA approved North Dakota’s SIP relative to Stanton and relative to CCS SO2 and particulate matter emissions. However, the EPA FIP includes a more stringent requirement than the SIP for CCS NOx emissions.

“GRE disagrees with EPA’s FIP and has filed a petition for review of EPA’s FIP determination with the U.S. Court of Appeals for the Eighth Circuit,” the plan said. “Consequently, the extent of the SIP/FIP requirements for CCS NOx emissions will not be known until the Eighth Circuit issues its decision, which is expected in mid‐2013. Coal Creek and Stanton stations have been working diligently on their BART control strategies required by the SIP and do not anticipate any difficulty meeting the regulatory timelines.”

Since the late 1990s, GRE said it has been an industry leader in researching mercury reduction technologies at its plants. It continues to work with partners such as the Electric Power Research Institute (EPRI), U.S. Department of Energy (DOE), and University of North Dakota’s Energy & Environmental Research Center (EERC) to identify and test novel mercury reduction technologies.

In February, EPA published its final MATS rule, which took effect in April. “Utilities have three years to comply with the rule (April 2015),” the GRE plan noted. “The rule provides for an optional one‐year extension by the state and a second one‐year extension by EPA if certain conditions are applicable. We recognize the rule provides for a relatively tight timeframe for design and construction. Our North Dakota generating plants have been working diligently on control strategies required by the MATS rule and continue to conduct testing and research on the best control methods. The rule is the subject of petitions for review filed with the U.S. Court of Appeals for the District of Columbia Circuit.”

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.