Utah witness says more data needed on Bridger SCR plan

A witness for the Office of Consumer Services has told the Utah Public Service Commission that Rocky Mountain Power, also known as PacifiCorp, hasn’t fully justified its application to add new selective catalytic reduction (SCR) on, and therefore save the lives of, its coal-fired Jim Bridger Units 3 and 4.

Testimony from Randall Falkenberg, a utility regulatory consultant and President of RFI Consulting Inc., was filed on Nov. 30 with the commission by the Office of Consumer Services (OCS). The company filed an Aug. 24 application with the commission for approval of these projects.

Falkenberg, in his heavily redacted testimony, said he has identified a number of errors and problematic assumptions that call into question the company’s results. “PacifiCorp’s implementation of the System Optimizer model lacks transparency because the SO Model is not available to regulators and intervening parties for review or verification and the reports developed from the model are very limited in detail and poorly organized,” he added. “This makes error tracking very difficult and lowers confidence in the model results.”

There are a number of serious errors in the SO Model studies, Falkenberg wrote. The company has understated the coal mine capital costs in the gas conversion case by $105m present value requirements (PVRR), he said. The Bridger power plant gets most of its coal from its own neighboring coal mining operations, with the power plant and mining operations each two-thirds owned by PacifiCorp and one-third owned by Idaho Power. The company also incorrectly included SCR system costs of $16m in the gas conversion case, Falkenberg wrote. Combined, these errors produce additional benefits due to the SCR project of almost $90m PVRR, he added.

The company has also overstated the capacity of the coal-fired Wyodak power plant in the SO Model study which causes the dispatch benefits of Bridger in the SCR (coal) case to be understated, though the company has not quantified the impact, Falkenberg said.

“The Company assumes that if Bridger Units 3 and 4 do not continue coal-fired operation, it will be necessary to stop surface mining operations and complete reclamation of the surface mine before 2030,” he added. “This increases the cost of the gas conversion case by [redacted] million PVRR [difference]. While OCS has examined this issue in discovery, the Company has not adequately justified these assumptions. The Company has updated the estimated cost for the Bridger SCR system, reducing the cost of the continued coal operation case by [redacted] million PVRR(d). The final SCR cost is unknown, and crucial to the economics of the continued coal operation case. The Commission should not grant approval for any more than the amount assumed by the Company in its filing, [redacted].” 

At another point, Falkenberg wrote: “The Company acknowledges that the Bridger Units 3 and 4 outage rates used in the case of continued coal operation are lower than any values used in any general rate case since 2001. Further, the outage rates used for Bridger are far lower than recent actual results and the unit averages for the past 20 years. This overstates the benefits of continued coal operation.”

The SO Model study fails to consider whether other coal plants may also be retired early or converted to natural gas in addition to or before Bridger Units 3 and 4, said Falkenberg. Conversion of these resources could significantly impact the SCR decision.

Transmission is another key issue that needs to be looked at

The company has also not examined whether transmission related investments may be deferred or avoided by alternatives to the Bridger SCR decision, he said. “Consequently, the Company has not demonstrated that installation of the Bridger SCR in conjunction with the currently planned Gateway transmission projects is the least cost alternative,” Falkenberg added. “Transmission system impacts should be studied in additional scenario analyses. Such studies should examine a combined cycle replacement for Bridger Units 3 and 4 located nearer to load centers, with transmission system impacts quantified.”

In developing the SO Model 2016-2030 base plan, the company assumes a 925 MW expansion of wind capacity in Wyoming is necessary to meet the existing renewable portfolio standard (RPS) requirements in California, Oregon and Washington. The company also includes an additional 250 MW of Wyoming wind capacity to meet assumed federal RPS requirements and 900 MW of incremental Wyoming wind capacity on policy and risk mitigation grounds. “This aspect of the Company’s expansion plan has adverse impacts on the Bridger SCR scenario,” Falkenberg noted. “Alternative assumptions should be further explored with scenario analysis.”

Due to the various problems and concerns he has identified, Falkenberg said the commission lacks the information necessary to reach a decision in this proceeding at this time.

He noted that Best Available Retrofit Technology (BART) compliance requires the installation of the SCR systems on Bridger Units 3 and 4, or the units must cease operation on Jan. 1, 2016, and Jan. 1, 2017,  respectively.

PacifiCorp told OCS that Bridger coal operations can’t be sold

In response to an OCS data request about whether the Bridger coal mining operations could be sold, PacifiCorp responded: “Bridger Coal Company is located in southwest Wyoming, a relatively small niche market. The vast majority of the coal produced in this region is consumed locally either by the “trona” patch companies or power plants. Currently, an imbalance exists between supply and demand for Southwest Wyoming coal. Kiewit Mining initially commenced operation of the Haystack mine in 2011; however, the Company understands that Kiewit Mining has now delayed development of the mine due to lack of demand. The planned conversion of Naughton Unit 3 from coal to natural gas will further exacerbate the current market disequilibrium. Finally, the lack of competitive transportation alternatives undermines the ability of Southwest Wyoming coals to economically compete with coals from other production basins.”

Whenever a resource is removed from the system mix, it impacts the economics of all the remaining resources, Falkenberg noted. The pending retirement of PacifiCorp’s Carbon coal plant in Utah and the coal-to-gas conversion of PaciCorp’s Naughton Unit 3 in Wyoming serve to enhance the benefits of continued coal operation of Bridger Units 3 and 4, he added. “If other coal plants are retired or converted to gas, it could also serve to improve the economics of continued operation of Bridger Units 3 and 4. The Company has not addressed this in its SO Model studies.”

Based on company figures, Bridger Units 3 and 4 are not necessarily the only, or best, candidates for gas conversion. “In fact, there is potentially 88-523 MW of additional capacity that may be candidates for gas conversion either before (or in addition to) Bridger Units 3 and 4,” Falkenberg wrote. “Some of smaller units (Craig-2 and Hayden) appear to be the most likely retirement/conversion candidates. Other units may not be conversion candidates, but may be better candidates than Bridger Units 3 and 4.” Craig and Hayden are coal plants in Colorado.

Mark Crisp, Managing Consultant of Global Energy & Water Consulting LLC, provided Nov. 30 testimony on behalf of the state Public Utilities Division. He said he supports the technology selected by the company to achieve compliance with the settlement agreement of November 2010 with the Wyoming Department of Environmental Quality known as the “BART Settlement Agreement.” However, the scope of the commission’s approval of this request should be limited without the company having a contract “in-place” with a technology vendor, including firm costs and contractual terms, Crisp added. “I also am not convinced the Company has thoroughly vetted other options including retrofit technology and stand-alone or ‘greenfield’ options while using appropriate modeling variables,” Crisp wrote.

Bridger Units 1-2 not affected by this planning

The Jim Bridger plant consists of four coal units. The plant is operated by PacifiCorp Energy. Unit 3 began operation in 1976 and Unit 4 followed in 1979. Unit 3 and Unit 4 have nominal net capacities of 523 MW and 530 MW respectively, of which the corresponding PacifiCorp two-thirds shares are 349 MW and 353 MW.

Both affected units are configured with Alstom (formerly Combustion Engineering) controlled circulation, tangentially fired, pulverized coal boilers and General Electric steam turbine-generators. Both units are configured with closed loop circulating water cooling systems that include mechanical draft cooling towers and electrostatic precipitators (ESPs). Unit 4 was originally equipped with a sodium-based wet flue gas desulfurization (FGD) system, and Unit 3 was retrofitted in 1985 with a sodium-based wet FGD.

The plant is adjacent to PacifiCorp’s and Idaho Power’s co-owned Jim Bridger mines, which supply about 6 million tons per year of sub-bituminous coal to the plant along a 2.4-mile long, 42-inch wide overland belt conveyor. An additional 3 million tons per year of sub-bituminous coal is delivered to the plant from other mines in southwestern Wyoming via rail or truck.

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.