Northern States Power eyes new combustion turbines for future needs

Northern States Power, a unit of Xcel Energy (NYSE: XEL), is working in a number of areas to meet expected new capacity needs, with three gas-fired combustion turbines the preferred new capacity at this point, the company told the Minnesota Public Utilities Commission in a Dec. 18 filing.

The filing was an updated analysis and comments in compliance with the commission’s Nov. 30 order in a 2011-2025 Resource Plan proceeding.

“The size and timing of our generation resource need are informed by a relatively straightforward comparison of the forecast of peak demand plus system reserve requirements with existing resources available to meet that requirement,” the company wrote. “Our analysis identifies a 154 MW capacity deficit in 2017, growing to 319 MW in 2018 and 443 MW in 2019.”

NSP’s resource need analysis continues to be based on the median peak demand forecast presented in its December 2011 Resource Plan Update filing with suggested adjustments. The company has also updated its resource need estimate to reflect a reserve generation margin based on the Midwest ISO’s unforced capacity (UCAP) methodology.

“On the supply side, we have updated our model to remove the 117 MW that was anticipated with the completion of the Prairie Island EPU, and we continue to reflect our plan to retire Black Dog Units 3 and 4 in 2015,” the company noted. “We have also reexamined our assessment of three smaller peaking resources – Key City, Granite City, and French Island.”

The EPU is a delayed uprate project for the Prairie Island nuclear plant, while Black Dog Units 3 and 4 are coal facilities that have been targeted for shutdown by the company for some time.

NSP has several small peaking units at the Key City plant in Mankato (43 MW) and at the Granite City plant near St Cloud (54 MW). The depreciable life of current assets at these units expires at the end of 2012. “However, we have no immediate plans to retire these units from operation, and we believe their age and condition is such that they can continue to operate through 2016,” the company said. “We have updated our model to reflect continued operation of these plants through 2016 but have not extended their life further at this time.”

French Island Unit 3 developed a short circuit in the generator stator in 2009 and has been unavailable for dispatch since then. Since the NSP system has had excess capacity since 2009, there has been no need to invest the capital to repair the unit. The company currently estimates the facility can be brought back to service with an approximate $3m investment. “We have determined that this is a cost effective way to maintain peaking generating capacity, and we are including the necessary funds in our budgets,” the company added. “Our updated model includes the 57 MW of production capacity at French Island Unit 3 starting in 2016 and continuing for through the planning period.”

Size of resource need in part depends on MISO rule changes

While the size and timing of the utility’s resource need recommendation is based on this analysis, the company said it recognizes there are factors that could affect resource requirements on its system. For example, MISO is revising the way reserve margins are calculated, which may affect overall resource requirements. Historically, NSP’s reserve requirements were set based on the NSP system’s peak demand.

The new method is based on reserves on the NSP system load at the time of the MISO’s peak demand. Historical data indicates that the NSP system’s power demand is typically lower at the time of MISO’s system-wide peak. With this change, future reserve requirements may be lower than currently. While the reduction in reserve requirements for the NSP system could be substantial, this concept is just now being implemented by MISO. So the utility said it does not have enough information about the impact of these changes on the long-term planning needs of the company to recommend updating reserve requirement calculations at this time.

NSP said it is actively developing a proposal to meet the identified resource need and has determined the most cost-effective proposal it can put forward to meet generation needs in the 2017 to 2019 timeframe consists of three combustion turbine units. “We would like the opportunity provide a flexible proposal that allows the Commission to select all or portions of our proposal in combination with other projects to meet our customers’ power requirements reliably and as cost effectively as possible,” the company said.

NSP is recommending that the commission:

  • establish the size and timing of its generating resource need to be addressed in a competitive resource acquisition process at 154 MW in 2017, 319 MW in 2018, and 443 in 2019;
  • provide participants in the competitive resource acquisition process the flexibility to offer peaking or intermediate resources or a combination of the two, as well as the flexibility to address all or a portion of the identified need;
  • allow proposals in the competitive resource acquisition process from existing generators; and
  • take no action at this time to reduce the estimated resource need based on demand response potential.

“Xcel Energy is actively preparing the most cost effective proposal we can identify to meet the resource needs presented in our updated analyses,” the company said. “We intend to design our proposal in a modular fashion so that the Commission has flexibility to select three combustion turbines to meet the entire need identified or combine fewer units with other proposals if more cost effective. We also have flexibility to adjust the timing of our generation additions if evolving circumstances warrant. We look forward to Commission’s consideration in the competitive acquisition process.”

The Department of Commerce said in a Dec. 18 filing in this case: “The Department recommends that the Commission order Xcel to pursue up to 500 MW of natural gas fired (peaking and intermediate) capacity for implementation in the 2017 to 2019 time frame. The specific type of capacity should be determined based upon actual bids submitted in the competitive resource acquisition proceeding.”

The Midwest ISO’s new regional structure with the MISO footprint divided into seven Planning Resource Zones limits the geographic scope of potential competitors due to costs of moving resources between zones, the department noted. The department said it discussed this structure with utilities and understands that, in effect, the Planning Resource Zone structure places limits on how far a resource can be located from load and still be economic. If Xcel does  not provide a bid for a combined cycle unit, the department said it is concerned that there may not be a reasonable amount of competitive bids if only combined cycle units are allowed to bid. The department concluded that the best way to ensure adequate competition is to allow the company to bid its preferred peaking resources, against whatever resources potential competitors, such as regional power producer Calpine (NYSE: CPN), are willing to bid.

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.