PacifiCorp may shut Carbon coal plant in Utah due to MATS

The U.S. Environmental Protection Agency’s recently promulgated Mercury and Air Toxics Standards (MATS) are pushing the need for new emissions controls, like dry sorbent injection, at PacifiCorp’s coal-fired, 172-MW Carbon plant in Utah.

Carbon Units 1 and 2 do not demonstrate compliance with MATS limits for the pollutants regulated under that rule, PacifiCorp said in an updated integrated resource plan (IRP) that it filed with various state commissions, including the one in Utah, at the end of March. Emissions control equipment currently installed on the units is limited to electrostatic precipitators for particulates.

“The company is in the process of assessing emerging technologies, namely dry sorbent injection into the combustion processes of the units, in order to identify possible MATS compliance options,” the updated IRP said. “Should the testing provide positive results for all MATS regulated emissions, the company will further assess the long-term commercial viability of such emerging technologies, as well as the ability of said technologies to support compliance with other emissions regulations such as National Ambient Air Quality Standards (NAAQS) and long-term Regional Haze Rule planning.”

PacifiCorp has assessed the feasibility and economics of major environmental equipment retrofits of Carbon Units 1 and 2 in the past and did not identify viable least-cost options for the units. The company has also assessed conversion of the units to natural gas as a fuel source and did not find that approach to result in favorable economics nor an acceptable long-term emissions profile. Each of those assessments will be further reviewed against current environmental requirements and economic drivers, the company added.

“While the assessments described above will continue, the company does not expect to identify a least-cost option, accounting for risk and uncertainty, other than retiring Carbon Units 1 and 2,” the company added. “For resource planning purposes, these units were assumed to retire as of January 1, 2015. However, the company is also currently assessing potential transmission system impacts associated with potential retirement of the Carbon units, particularly with respect to long-term regional transmission system reliability, that may result in a need to request an extension of the compliance deadline for the Carbon facility to accommodate transmission system improvements. The initial results of said study are expected in April 2012. Should reliability concerns or other considerations support the need for an extended compliance schedule, the company will work within the conditions included within the MATS regulations and administrative guidance to request an appropriate compliance extension.”

Various adjustments made from prior IRP

The main changes to existing and firm planned resource capacity in the updated 2012 Business Plan load and resource balance relative to the 2011 IRP include:

  • Coal plant turbine upgrade capacity is lower by 20 MW, reflecting elimination of the Huntington 2 project in Utah in 2016 and Hayden 2 project in Colorado in 2021.
  • The company entered into new PURPA Qualifying Facility contracts with existing industrial customers, representing an 81 MW capacity increase beginning in 2017. There were also new biomass and wind QF contracts totaling 21 MW and 15 MW, respectively. PacifiCorp also assumed that several industrial customers and PURPA Qualifying Facilities will use self generation rather than selling their output to the company through 2016, thereby reducing loads and resource capacity.
  • In the company’s Utah North sub-region, there is a need for a capacity purchase of 200 MW for August 2011 through December 2013.
  • The termination of the Southeast Idaho Exchange Agreement effective as of June 2016 removed PacifiCorp‘s obligation for providing firm peak load for Bonneville Power Administration‘s Idaho customers. This firm peak load is partially offset by the availability of BPA‘s Idaho resources, which count towards meeting the system peak load requirement. Termination of this exchange agreement also reduces power purchases in the PacifiCorp West Balancing Area.
  • Retirement of the Carbon Units 1 and 2 as of Dec. 31, 2014.
  • Updated capacity ratings for a number of owned existing generating units, along with termination of the Grant Mid-Columbia hydro contract in 2013.

Updated planning by sub-region includes:

PacifiCorp East

Thermal – A capacity decrease in 2015 is due to the assumed retirement of the 172 MW Carbon coal plant, as well as de-rates for several coal units for which environmental control equipment is being installed. Cancellation of turbine upgrade projects further reduces capacity by 18 MW in 2016 and by about 2 MW in 2021.

Purchase – An increase in capacity for 2012-2013 is due to the new 200 MW August 2011 Utah capacity purchase. The termination of the Southeast Idaho exchange contract with the Bonneville Power Administration in June 2016 accounts for a 168 MW capacity decrease beginning in 2016.

Loads – A large decrease is attributable to lower forecasted loads and the removal of the load service obligation for BPA‘s customers as a result of termination of the Southeast Idaho Exchange Agreement.

Qualifying Facilities – For planning purposes, the company assumed that certain PURPA Qualifying Facilities are electing to self-generate through 2016 rather than sell their output to PacifiCorp. This assumption results in about a 150 MW capacity decrease.

Sales – The updated reflects a new two-year contract for sales of up to 150 MW for years 2011-2012.

Transfers – This reflects an increase in economic imports of capacity from PacifiCorp West as determined by the System Optimizer capacity expansion model.

PacifiCorp West

Thermal and Hydro – Updated capacity ratings are included for a number of owned existing generating units, along with termination of the Grant Mid-Columbia hydro contract in 2013.

Renewable – A renewed contract for Stateline Wind and the Seattle City Light integration and exchange agreement accounts for a 17 MW increase.

Purchase – A large drop in purchase capacity in 2016 is due to cancellation of the Southeast Idaho exchange contract with BPA, reflecting removal of power deliveries from BPA into PacifiCorp‘s system.

Qualifying Facilities – A capacity decrease reflects contract updates along with the addition of two biomass facilities in Oregon and California.

Sales –  Increased capacity is mainly attributable to the new Stateline Wind and Seattle City Light integration and exchange agreement, as well as other minor contract updates.

Transfers – This update reflects an increase in economic exports from PacifiCorp West to PacifiCorp East as determined by the System Optimizer capacity expansion model.

PacifiCorp re-looks at coal emissions project economics

In an updated coal capacity replacement study near the back of the updated IRP, PacifiCorp said it has been committed to various new emissions controls for these coal units:

  • Naughton Unit 3, Wyoming, selective catalytic reduction (SCR), baghouse and mercury control, all to be in-service in 2014. Notable is that PacifiCorp is now before the Wyoming Public Service Commission saying that switching Naughton Unit 3 to natural gas would be cheaper than these previously-planned emissions controls.
  • Jim Bridger Unit 3, Wyoming, SCR in-service in 2015 and mercury controls in 2014.
  • Jim Bridger Unit 4, SCR in 2016, mercury in 2014 and an SO2 scrubber upgrade in 2012.
  • Hunter Unit 1, Utah, baghouse in 2014, mercury in 2012 and low-NOx burners in 2014.
  • Craig Unit 1, Colorado, selective non-catalytic reduction (SNCR) in 2017.
  • Craig Unit 2, SCR in 2016.
  • Hayden Unit 1, Colorado, SCR in-service in 2015.
  • Hayden Unit 2, SCR in 2016.

In doing more recent analyses of its coal options, PacifiCorp noted that natural gas conversion compliance alternatives were not developed and made available for the Craig and Hayden units because PacifiCorp does not have the ability to unilaterally pursue this compliance option because it only co-owns these units. It noted that the Colorado commission has approved Xcel Energy‘s (NYSE: XEL) emission reduction plan to install NOx controls on both Hayden units. In the event that incremental environmental capital investments are not justified, natural gas conversion served as the most beneficial replacement resource alternative for Naughton Unit 3, Jim Bridger Units 3-4, and Hunter Unit 1 among all replacement scenarios studied.

“In conclusion, the updated coal replacement study shows that the economic analysis of incremental environmental capital investments committed or planned for coal units as a means to meet compliance with emerging environmental regulations varies among specific coal units and is highly dependent upon assumptions for both natural gas prices and CO2 prices,” the update said. “The study further highlights the challenge in having to make near-term capital investment decisions that are required to meet both known and uncertain environmental regulations in the face of tremendous uncertainty around the price of natural gas and coal costs 10 to 20 years into the future. Despite these challenges, the investment decisions must be made and compliance with known environmental regulations must be achieved. PacifiCorp welcomes maintaining an open dialogue with its state commissions and stakeholders as these decisions are studied through the IRP and ultimately implemented.”

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.