Xcel’s Minnesota unit outlines latest resource needs

The Midcontinent ISO capacity situation is in “flux” and some new estimates create doubts about what generating capacity Northern States Power d/b/a Xcel Energy (NYSE: XEL) will need in the 2007-2019 timeframe, said official James Alders.

Alders is a Strategy Consultant for Rates and Regulatory Affairs for Northern States Power. Testimony from Alders was filed Sept. 27 at the Minnesota Public Utilities Commission in a Northern States Power (NSP) resource plan case. Within that case, the commission is reviewing bids for new capacity, including bids from outside power suppliers and a bid from the utility for its own self-built capacity.

Northern States Power proposes to add to its system three 215 MW (208 UCAP rating) natural gas-fired, simple-cycle, combustion turbines (CTs). The first CT – Black Dog Unit 6 – is proposed to be constructed in 2017, 2018, or 2019 at the company’s existing Black Dog plant in Burnsville, Minn. Black Dog Unit 6 will use existing infrastructure and feed power directly to the existing 115 kV transmission system that directly serves distribution substations throughout the utility’s largest load center – the Minneapolis-St. Paul area. Utilizing the existing Black Dog site with its existing natural gas and transmission infrastructure significantly reduces the cost of this CT, Alders noted.

The utility proposes the second CT to be placed in service in 2018 or 2019 at a greenfield site in Hankinson, N.D. – to be called Red River Valley Unit 1 – which would take advantage of existing nearby transmission and natural gas infrastructure. The third CT is proposed to be added in 2019 as Red River Valley Unit 2.

The Hankinson site is about 70 miles from the Fargo load center, near the juncture of the 230 kV transmission system and a large natural gas interstate pipeline in the area. This site places generation closer to regional load centers in North Dakota than the utility’s existing power plants. The specific site for the Red River Valley Plant has not been identified yet, and the specific routes for the transmission and gas supply infrastructure have not been determined and permitted. The utility also has not worked through the MISO interconnection process to confirm what system upgrades may be necessary.

Latest resource need estimates have fallen a bit

The commission has previously found it may be appropriate to add about 150 MW in 2017 growing to up to 500 MW in 2019 for NSP’s five-state, integrated system. Since March, the utility has updated its need assessment as part of its regular business process based on new data. The September 2013 update indicates a capacity deficit of 93 MW in 2017, growing to 307 MW by 2019, Alders noted. “However, there are factors that create uncertainty and could materially affect our resource need assessment,” Alders added. “[T]he Midcontinent Independent System Operator’s resource adequacy process is in flux.”

The Strategist computer model results show that Black Dog 6 is the lowest cost resource among all the proposals, Alders wrote. The least-cost portfolio includes Black Dog 6 and Invenergy’s Cannon Falls Expansion proposal, while the next least cost portfolio includes Black Dog 6 and Calpine’s (NYSE: CPN) Mankato Expansion proposal. The Red River Valley Unit 1 in combination with other proposals is also highly ranked but slightly behind the others. The utility recommends that the commission select Black Dog 6 in combination with either Cannon Falls Expansion or Mankato Expansion to address the company’s range of potential need in the 2017-2019 time period.

With the uncertainty surrounding the 2017-2019 resource need, NSP believes it would be beneficial to explore contract options providing implementation flexibility, Alders said. “Our proposal includes the flexibility to adjust in-service dates or even cancel development of one or more units in the event of changed circumstances warrant. We believe it is important to establish similar flexibility options in the PPAs if possible. Such options may impact pricing and help the Company and the Commission judge the value of flexibility.”

Alders added: “We continue to believe it is prudent to closely monitor changes in resource adequacy occurring in the MISO market that provide opportunities to adjust plans if customer benefits can be had.”

Two coal units at Black Dog due for retirement by early 2015

Also providing Sept. 27 testimony was Gregory Ford, Director of Engineering, Design, and Document Services in the Energy Supply Engineering and Construction  Department at NSP.

Ford said the Black Dog plant is currently a coal- and natural gas-fired station with four operating units. Units 1 and 2 were installed in the 1950s, and before being repowered with a natural gas combined-cycle facility in summer 2002, fired coal. With the repowering, Unit 1 was retired and replaced with new Unit 5. Combined Units 2 and 5 increased output from the two original units by more than 100 MW.  Black Dog Units 3 and 4, which currently utilize coal as the primary fuel, were put into service in 1955 and 1960. Operating data indicates a declining reliability as the units continue to age. The utility has decided to retire the units by no later than early 2015. Upon their retirement, there will be no coal-fired generation at the Black Dog plant.

Key considerations in adding any new generating unit at this site is its ability to integrate into the transmission system and access the necessary fuel. The company is proposing to add a 215 MW (208 UCAP rating) natural gas-fired, simple-cycle, CT as Unit 6 to the Black Dog plant, which will be a very cost-effective use of this plant facility upon retirement of Units 3 and 4.

In terms of transmission, while minor modifications to the existing 115 kV switchyard will be required to connect it to the transmission system, no upgrades of the 115 kV transmission system are required. However, because Black Dog Unit 6 will increase the plant’s high pressure natural gas need, we will conduct a competitive process for supply to the plant. It may be necessary to replace the existing pipeline serving the plant with a new higher pressure natural gas line, which will be the responsibility of the fuel supplier and has been factored into NSP’s plans and proposal.

NSP will operate Black Dog Unit 6 as a peaking generator, with an anticipated annual capacity factor of four to ten percent. It expects annual availability will be greater than 95%, and that its service life will exceed 35 years.

The Red River Valley plant would connect to the transmission network via a double circuit 230 kV line to either an expanded Otter Tail Power Hankinson 230 kV substation, or a new 230 kV substation constructed at another location. NSP has conducted a preliminary generation interconnection study to identify likely transmission upgrades needed for the interconnection. The study identified two potential system upgrades that may be required to support interconnection: completion of the Big Stone-Brookings County 345 kV transmission line; and rebuilding Otter Tail Power’s existing Hankinson-Wahpeton 230 kV line.

The Red River Valley plant would not be directly responsible for any of the Big Stone-Brookings line cost, since it is part of the MISO Multi-Value Portfolio of regional transmission improvements. The Hankinson-Wahpeton rebuild, however, would be necessary to support interconnection of Red River Valley Unit 2, so the plant would be responsible for its cost.

The Red River Valley plant site area is near the Alliance interstate natural gas pipeline. Multiple parties utilize this line to transport gas, and have indicated a willingness and ability to provide natural gas service for the plant.

The layout of the plant would allow for two simple-cycle CTs to be installed, as well as for the conversion of the two units to a combined-cycle configuration in the future. Consistent with Black Dog Unit 6, the units will be operated as peaking generators with an anticipated annual capacity factor of 4% to 10%. Annual availability will be greater than 95%, and the service life of the units would be in excess of 35 years.

Invenergy, Calpine among the parties offering RFP bids

Steven Wishart, Director of Resource Planning and Bidding for Xcel, provided Sept. 27 testimony that had more details about the proposals made in the RFP, though the price details are redacted from the public version of the filing.

  • Invenergy offered two separate proposals for new peakers: the first for one additional CT at its existing Cannon Falls site, and the second for two CTs at a new site located near the Hampton Corners Substation. These CTs are a different type than those proposed by NSP, and each has an estimated summer capacity value of 150 MW. The two proposals have similar cost and operating characteristics, with a 20-year PPA for each, and an in-service date of June 2016 for both projects.
  • Calpine has proposed an expansion of its existing natural gas combined cycle (CC) plant located in Mankato. Combined cycle plants are typically defined as intermediate generation which has higher expected annual capacity factors. These types of units are more efficient than peaking facilities, but have higher construction costs and higher annual operation and maintenance (O&M) costs. The expansion of the Mankato facility would have a proposed in-service date of June 2017 with a term of 20 years, and would add approximately 278 MW of summer capacity to the company’s system.
  • Geronimo Energy has offered a 100 MW (AC) solar project with a targeted in-service  date of December 2016. The project will have up to 31 sites throughout the company’s service territory.
  • Great River Energy (GRE) offered a three-year capacity purchase for either 100 MW or 200 MW. This proposal would be for MISO Zone 1 resource credits only; no energy or generation would be associated with this purchase. The purchase would cover 2016, 2017, and 2018, potentially allowing a delay of the in-service dates of one or more of the other proposals.
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.