Calpine supports Xcel need for new gas-fired capacity in 2017-2019

Calpine (NYSE: CPN) is recommending that the Minnesota Public Utilities Commission follow the state Department of Commerce’s recommendation and establish for Xcel Energy (NYSE: XEL) a resource acquisition process for up to 500 MW of new, natural gas-fired resources over the 2017-2019 time frame.

Calpine, in a Jan. 16 filing at the commission, also said the PUC should specify that bidders may submit proposals for combustion turbine and/or combined-cycle capacity for all or part of the need. “Approval of the Department’s more flexible approach will in no way discriminate against Xcel or any other party; all parties would have an opportunity to supply all or part of the need based on the relative competitiveness of their bids,” Calpine added.

The filing came in the matter of Xcel’s 2011-2025 Integrated Resource Plan and the application of Xcel’s Northern States Power unit for a Certificate of Need for the stalled Black Dog coal-to-gas repowering project. Xcel, due to slumping demand growth, has shelved the Black Dog repowering to gas and plans to retire the plant’s coal capacity in 2015 for clean-air needs.

The commission on Nov. 30, 2012, sought comments on the latest developments in this matter, with Calpine now responding to Xcel’s subsequent Dec. 18, 2012, comments.

The commission’s Nov. 30 order directed Xcel and the Department to “develop the base level of Xcel’s resource needs sufficiently to enable the Commission to identify the size, type, and timing of any new resources required.” In their respective comments, Xcel and the Department generally agreed on the size and timing of Xcel’s resource needs, Calpine noted.

Xcel believes it will need 443 MW and the Department believes Xcel should procure up to 500 MW. Both agree that new gas-fired capacity will be needed during the 2017-2019 timeframe. Xcel recommends that the commission set the need at 154 MW in 2017, 319 MW in 2018, and 443 MW in 2019, and states that it is “actively developing” a proposal consisting of three combustion turbine (i.e., peaking) units to meet that need. The Department suggests that a combination of peaking and intermediate capacity should be considered.

Both Xcel and the Department recommend that the specific resource type and/or mix should be determined based upon an analysis of actual bids submitted rather than being predetermined by the commission because their updated Strategist computer modeling did not express a clear preference for a specific type of resource.

Calpine supports capacity need, but not the Xcel plan to meet it

“Calpine supports the Department’s approach of establishing a need of approximately 500 MW of natural gas capacity in the 2017 to 2019 timeframe and agrees that this Competitive Resource Acquisition Process should solicit proposals for both peaking and intermediate resources,” Calpine wrote in its Jan. 16 comments. “Calpine agrees with Xcel that the process should provide developers ‘with the flexibility to offer the generating unit size of their choice to meet either all or part of the resource need.’ Calpine further agrees with Xcel that this will ‘elicit as many proposals as possible’ and, therefore, maximize the number of potential cost-effective options for consumers. Calpine opposes Xcel’s recommendation that the Commission ‘specify the estimated generation deficits by year.’ Such ‘specific guidance’ is not necessary and would be counterproductive.”

  • First, said Calpine, Xcel’s recommendation fails to account for the imprecise nature of resource planning. Actual demand growth does not always follow a smooth curve and the most cost-effective resource additions are often “lumpy,” as in they have economies of scale or other attributes that provide superior long-term value even though they might result in a modest short-term over-build.
  • Second, Calpine said, adopting Xcel’s recommendation would restrict the range of proposals by favoring roughly equal annual capacity additions over other potential solutions. “Indeed, nothing in the Department’s modeling appears to suggest that three equal capacity additions represent the least cost approach under any of its modeling scenarios,” Calpine wrote. “Moreover, Xcel’s recommendation represents a limitation that would bias the process towards combustion turbines, which can more easily be developed in 150 MW increments than other types of resources, such as combined-cycle. Indeed, adopting Xcel’s recommendation to provide such ‘specific guidance’ would effectively bias the process toward Xcel’s own proposed project. Xcel may believe that adding 150 MW per year is the least cost option it can propose, but that is not sufficient reason for the Commission to limit competitive proposals for other types of projects from other prospective bidders.”
  • Third, Calpine opined, Xcel’s recommendation is inconsistent with the concept that the commission should not be overly specific with respect to the type of project(s), but should let the competitive process itself determine the outcome.

Calpine has previously pitched to the commission a proposal for a 350-MW expansion of its existing Mankato Energy Generation Station as an option to meet Xcel’s need.

Xcel told the commission in Jan. 16 comments that it continues to be in general agreement with the Department on the size, type, and timing parameters for the competitive resource acquisition process scheduled to begin in March 2013. It also continues to recommend that the commission’s order:

  • Set the need at 154 MW in 2017, 319 MW in 2018, and 443 MW in 2019; and
  • Not specify the resource type, but let the process select the most cost effective proposals.

“We are continuing to develop our proposal to meet the resource need identified here,” Xcel added in its Jan. 16 comments. “Our proposal will consist of three combustion turbine units to meet generation needs in the 2017 to 2019 timeframe, providing flexibility that would allow 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.”

Xcel outlines factors in its estimate of future resource needs

“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,” Xcel/NSP wrote in the Dec. 18 filing that Calpine was responding to. “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 through the planning period.”

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.