Xcel unit argues for purchase of three gas-fired Brush units

In an effort to make “a concise and compelling filing” with the Colorado Public Utilities Commission about its plans to buy the gas-fired Brush Units 1, 2 and 4, Public Service Co. of Colorado did leave some needed details about the condition of those units out of its application, said Karen Hyde.

Hyde is employed by Xcel Energy Services Inc., a wholly-owned subsidiary of Xcel Energy (NYSE: XEL), the parent company of PSCo. Hyde’s position is Vice President, Rates and Regulatory Affairs–Colorado. The utility filed testimony from Hyde and other company officials on Oct. 5 at the commission as part of three combined cases, including an application to buy the three Brush units.

Hyde was responding to criticism from witnesses in these cases that implied that the Brush units are relatively old and in poor condition. “I can assure the Commission that the witnesses in the case were fully aware that the generating facilities at Brush 1, 3 and 4 were refurbished equipment when they were installed at Brush,” Hyde wrote. “Before my time in Regulatory, I was in the Company’s purchase power unit on and off since the early 1990s and I am very familiar with the history of the Brush units. Further, since the Brush facilities have been under Power Purchase Agreements (PPAs) to sell their output to the Company since they started operating, we have a good understanding of the operational availability of these units.”

Hyde said equipment of this vintage was engineered and constructed to “robust standards” that suggest the equipment should be appropriate for long-term operation. “The robustness of the original equipment, the fact that it was refurbished to new and clean condition when installed at Brush, the good care that has been given the units while at Brush, and the very low starts and operating hours, all gave our engineering experts comfort that these units have a long life ahead of them and will provide reliable service to the Public Service system,” Hyde noted.

Hyde assured the commission that the company had no intention of either hiding the history of the units or of misleading the commission. But, the company now recognizes that it did not provide a detailed history of how the units came to be located in Brush, Colo. “In focusing on making a concise and compelling filing with the Commission, we left out some ‘color commentary,’” Hyde conceded. “We can never know what approach parties will take in Answer Testimony when we write our direct case but it is clear Staff would have preferred that we include more discussion on the history of these units.”

The company said its original assessment of 45 years from the times of these units’ refurbishment and installation at Brush, which was in 1990 and 2002, is the appropriate useful life to be applied to them for ratemaking purposes.

Brush buy is a good deal compared to greenfield alternatives

To the extent that there is any uncertainty about whether the Brush units will reach their full remaining useful lives as estimated by PSCo (22, 31, and 34 years for Brush Units 1, 3, and 4D respectively) the Brush acquisition is a good deal for customers under a greenfield replacement power scenario so long as the units remain in-service through 2023, wrote James Hill, the utility’s Director, Resource Planning and Bidding. “Even under a brownfield replacement power scenario, the Brush units only need to remain in service 16 years (until 2028) for our customers to break-even,” Hill added. “After those dates, every additional year creates net savings for our customers.”

Kurtis Haeger, employed by Xcel Energy Services as Managing Director, Wholesale Planning, also provided Oct. 5 rebuttal testimony on a range of issues, including the likely retirement of Arapahoe Unit 4, which if it isn’t retired would be converted from firing coal to natural gas. His testimony included issues related to the retirement of Arapahoe 4 and the approval of a new PPA with Southwest Generation Operating Co. LLC for the output from its Arapahoe Units 5-7 and the accompanying gas supply agreement.

Haeger was asked if he agreed with parties that want to accelerate the retirement of Arapahoe Unit 4 before replacement power is identified. “No, we strongly oppose decoupling the Arapahoe retirement decision from the replacement decision,” he wrote. “[T]he almost fully depreciated Arapahoe 4 is a very low cost generation resource for our customers. We need to keep Arapahoe 4 running on natural gas in order to ensure that bidders are bidding against that low cost option and not just each other in order to get the most competitive bids for replacement generation. If we make the decision to retire Arapahoe 4 prior to knowing the cost of the replacement unit, we lose a substantial amount of price discipline. This will allow [independent power producers (IPPs)] to offer higher bids, not lower bids, to replace this capacity. Obviously this is not in our customers’ best interests.”

PSCo had provided to the commission an estimated retirement for Arapahoe 4 at the end of 2013. But Haeger said that is only an estimate and depends on the results of bids being evaluated for replacement power.

Hill testified that the shutdown of both Arapahoe Unit 4 and Cherokee Unit 4, both subject to coal-to-gas conversion projects, depend on bid results from a power solicitation process. “Portfolios of bids would be developed for the case in which the Company continues to operate both the Arapahoe 4 and Cherokee 4 generating units on gas from 2014-2023 and 2018-2028 respectively,” Hill noted. Portfolios of bids would also be developed for three other cases: Arapahoe 4 retired January 2014; Cherokee 4 retired January 2018; and both Arapahoe 4 and Cherokee 4 retired January 2014 and January 2028, respectively. By comparing the costs of these four sets of portfolios the vompany will be able to determine if a more cost-effective alternative to burning gas in these units is available from the bid pool.

The heat rate of both Arapahoe 4 and Cherokee 4 is expected to increase about 4% when operated on gas compared to the heat rate on coal, Hill noted. That corresponds to a full load gas heat rate of about 11,500 Btu/kWh for Arapahoe 4 on gas and 10,500 Btu/kWh for Cherokee 4 on gas. The company has several existing gas-fired combustion turbines (CTs) on its system (both owned and purchased) with heat rates at or higher than these rates. Given that when operating on gas Arapahoe 4 and Cherokee 4 are expected to run at low annual capacity factors (less than 2%), fuel costs that result from the units’ heat rates are expected to be insignificant, Hill wrote.

Utility making moves to comply with Colorado clean air act

There are three cases under consideration, with the Oct. 5 testimony covering aspects of all three. There is a 2011 Electric Resource Plan filed with the commission. And on July 5, PSCo filed the two other applications.

The first is an application to purchase Brush Power LLC and all of its assets, including Brush Units 1, 3 and 4, for a total purchase price of about $75m. The buy is from Centennial Power LLC, an affiliate of Bicent Power LLC.

The Brush units have a total capacity of 237 MW, including Brush Unit 1, a 60 MW combined-cycle unit; Brush Unit 3, a 30 MW simple-cycle unit; and Brush Unit 4, a 147 MW combined-cycle unit. The Brush units currently provide energy and capacity to PSCo under purchased power agreements that are set to expire in 2017 for Brush Unit 1 and Brush Unit 3, and 2022 for Brush Unit 4.

The second July application seeks approval to retire Arapahoe Unit 4, a 109-MW coal-fired facility, at the end of 2013. This is an alternative to permanently switching the unit to natural gas, which is an option the commission has previously approved, and instead replacing the capacity and associated energy with a natural gas purchased power agreement with an existing generator.

Also in the second application, the utility requested approval to enter into a multi-element transaction with Southwest Generation Operating and its affiliates, SWG Arapahoe LLC and SWG Fountain Valley Gas LLC. The utility wants approval for a new ten-year, 118.8-MW PPA with SWG Arapahoe, under which PSCo will purchase the output from Arapahoe Units 5-7 from Jan. 1, 2014, through Dec. 31, 2023, and a natural gas sales agreement with SWG Fountain Valley Gas under which PSCo will sell natural gas for the Fountain Valley generation facility.

PSCo is the current supplier of gas to the Fountain Valley facility and the current purchaser of the electricity from that facility under a “tolling” arrangement that was due to expire Aug. 31, 2012. When this tolling arrangement expires, SWG will contract for a different purchaser of the power from this generation facility, but SWG will still need gas supplied to the facility, PSCo noted in the July 5 application.

In December 2010, the commission approved the utility’s Clean Air-Clean Jobs Act-compliance plan, which forms the basis for much of PSCo’s current actions and included:

  • Shutdown of Cherokee Units 2 and 1 in 2011 and 2012, respectively, and Cherokee 3 (365 MW in total) by the end of 2015, after a new natural gas combined-cycle unit is built at Cherokee (569 MW);
  • Fuel-switch Cherokee 4 (352 MW) to natural gas by 2017;
  • Shutdown of Arapahoe Unit 3 (45 MW) and fuel-switch Unit 4 (111 MW) in 2014 to natural gas;
  • Shutdown of Valmont Unit 5 (186 MW) in 2017;
  • Install selective catalytic reduction (SCR) for controlling NOx and a scrubber for controlling SO2 on Pawnee in 2014;
  • Install SCRs on Hayden Unit 1 in 2015 and Hayden Unit 2 in 2016; and
  • Convert Cherokee Unit 2 and Arapahoe Unit 3 to synchronous condensers to support the transmission system.
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.