Calpine seeks site permit for 345-MW expansion of Mankato plant in Minnesota

The Mankato Energy Center II LLC subsidiary of Calpine Corp. (NYSE: CPN) on Aug. 5 filed an application with the Minnesota Public Utilities Commission for a site permit on a 345-MW expansion of its existing Mankato Energy Center.

On Feb. 5, the commission approved the Northern States Power unit of Xcel Energy (NYSE: XEL) to buy power from this expansion under a long-term contract.

The Mankato Energy Center received a site permit in 2004 for a primarily natural gas-fired combined cycle facility in Blue Earth County, Minn. The facility was permitted to consist of two combined-cycle power trains, one steam generator and other ancillary equipment. Each combined cycle power train was to include a combustion turbine generator (CTG) and one heat recovery steam generator (HRSG). The Mankato Energy Center commenced operations in 2006 with only one combined cycle power train.

The Mankato Energy Center, as it exists today, consists of equipment and land owned by Mankato Energy Center I LLC and operated by Calpine Operating Services Co. Inc. (both subsidiaries of Calpine Corp.). The existing facility is capable of producing 375 MW under winter conditions through the combustion of natural gas, or fuel oil for a limited number of hours. It accesses the grid via Northern States Power’s Wilmarth Substation. Under the current power purchase agreement, Northern States Power provides needed natural gas through a pipeline owned by Calpine Natural Gas and supplied by Northern Natural Gas.

The additional equipment required to complete construction of the Mankato Energy Center will be owned by Mankato Energy Center II and will be operated by Calpine Operating Services. “The Expansion Project is capable of producing 345 MW under winter conditions through the combustion of natural gas only (fuel oil cannot be burned in the Expansion Project turbine),” said the application. “The existing offsite infrastructure installed for the Existing Facility (i.e. electrical transmission, gas, water) will be used and is of sufficient capacity to operate the Expansion Project. No upgrades to this offsite infrastructure will affect public use. Air emissions will be permitted via modification of the Total Operating Permit.”

This expansion will bring total capacity to 720 MW (winter)

The total generating capacity of the combined facility will be 720 MW at winter conditions in a configuration that provides a large efficiency advantage over a conventional simple-cycle plant, the application noted. The combined facility is anticipated to be complete and operational by June 1, 2018.

Mankato Energy Center II asked that the expansion project site permit be issued by Jan. 15, 2016, to facilitate the anticipated June 1, 2018, operation date.

This plant was orginally permitted as a 2×1 combined cycle facility consisting of two natural gas-fired (with fuel oil back-up) CTGs, two HRSGs with natural gas-fired duct burners, one steam turbine and associated machinery and equipment. However, MEC I constructed it as a 375 MW (winter rating) natural gas-fired combined-cycle facility and included only one natural gas-fired (with oil back-up) combustion turbine, one heat recovery steam generator with natural gas-fired duct burners, one steam turbine generator, and associated machinery and equipment. Importantly, it was constructed to accommodate future expansion through the installation of an additional combined cycle power train (CTG and HRSG) and includes a steam turbine generator that is big enough for the expansion.

“The Expansion Project, for which MEC II now seeks a Site Permit, involves the completion of the originally planned 2×1 project located within the City of Mankato, Minnesota through the addition of one natural gas-fired CTG, an additional HRSG, and related ancillary equipment (e.g., four additional cooling tower cells),” said the application. “The Expansion Project would result in an incremental 345 MW of integrated combined-cycle and peaking capacity, as measured under winter conditions. The Expansion Project would be sited entirely on the Existing Facility site within its 25-acre footprint.”

Low sulfur distillate oil is available for use at the existing facility. The expansion project’s combined cycle power train cannot burn fuel oil for emergency back-up and will not operate in times when gas supplies are not available. 

The existing facility’s current capacity of 375 MW is composed of about 290 MW base load capacity at winter conditions and 85 MW peak load service. The expansion will add around 290 MW of baseload capacity and 55 MW of peaking capacity at winter conditions. This would bring the total capacity to 720 MW, consisting of about 580 MW of baseload and 140 MW of peaking capacity at winter conditions. The expansion will provide approximately 315 MW of net capacity at summer conditions.

Northern States Power will arrange for the delivery of natural gas to the expansion. The gas is delivered through a four-mile lateral pipeline connecting the existing facility to the Northern Natural Gas mainline. The lateral is connected to the mainline downstream of Northern Natural Gas’ interconnection with Northern Border Gas at Welcome, Minn. This segment of the Northern Natural Gas system is further reinforced by connections with their other north-south lines that run between Ventura and the Minneapolis-St. Paul market. The minimum throughput design of the existing pipe is one million cubic feet of natural gas per day with a maximum throughput capacity of 126 million cubic feet per day at a maximum allowable pressure of 936 pounds per square inch. The pipeline is operated at a normal pressure of between 525 and 550 pounds per square inch. The existing lateral is a 20-inch line, big enough to handle the expansion project.

A company contact is: Heidi M. Whidden, Director, Environmental Services, East Region, Calpine Corp., 500 Delaware Ave, Suite 600, Wilmington, DE 19801, Phone 320-468-5381, hwhidden@calpine.com.

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.