Rising sulfur levels in the coal at two of its power plants will mean higher operational costs for those plants as emissions control equipment is run harder to compensate, said Dana Ralston, Vice President of Thermal Generation at PacifiCorp d/b/a Rocky Mountain Power.
Testimony from Ralston was included in a February rate case application by Rocky Mountain Power at the Utah Public Service Commission. The company’s thermal generation resources at Dave Johnston Unit 4, the Wyodak plant, and Naughton Units 1 and 2 are impacted by environmental permit changes related to emissions, Crane noted. The impacts are:
- Dave Johnston Unit 4, Wyoming – The previously permitted SO2 emission rate was 0.50 lbs/MMBtu and the new permit lowers the rate to 0.15 lbs/MMBtu. This decrease in permitted emission rate causes the plant to use more lime in the SO2 scrubber to achieve the new permit level emissions rate which will increase forecasted costs by approximately $0.65m.
- Wyodak plant, Wyoming – A new permit added a 30 operating day limit of 0.16 lbs/MMBtu for SO2, which will increase forecasted costs approximately $0.5m.
- Naughton Units 1 and 2, Wyoming – For each of these units, the permitted emission rate was lowered from 1.2 lbs/MMBtu to 0.15 lbs/MMBtu. This decrease in permitted emission rate required the company to install scrubbers on both units and add the associated reagent and O&M costs to operate these scrubbers. The increased operations and maintenance costs at Naughton Units 1 and 2 are forecast to be about $3.3m.
The total increase in O&M costs due to permit changes for SO2 for the PacifiCorp Energy thermal generation fleet in the rate case test period is forecasted to be about $4.45m.
Also, Hunter Units 1-3 in Utah will experience an increase in the sulfur content of the coal from 0.54% sulfur during the base year to 0.73% sulfur during the test year, due to higher-sulfur coal coming from PacifiCorp’s own Deer Creek mine because it has run into an area of coal with higher sulfur content, and the signing of a contract for higher-sulfur coal from the West Ridge mine in Utah. This increase in sulfur will require an increase in the use of lime and increase forecasted costs approximately $1.71m.
Huntington Units 1-2 in Utah will experience a similar increase for similar reasons in the sulfur content of the coal from 0.54% sulfur during the base period to 0.70% sulfur during the test period. The increase in coal sulfur content will require increased use of lime to meet SO2 emission permit levels which is forecast to increase costs approximately $1.7m.
The total increased O&M costs due to rising sulfur content of the coal is forecasted to be approximately $3.41m.
Another higher maintenance expense relates to the fact that once coal is mined and delivered to a power plant it needs to be ground to a fine powder before it is injected into the boiler. The previous mine that provided a long-term coal supply to Cholla Unit 4 in Arizona is closed, and the last coal from this source was used in September 2010. The new coal supply at Cholla Unit 4 is harder to grind and as a result, is causing increased wear on the grinding elements in the mill. This increase in wear is forecast to increase costs by about $0.7m.
Also, Cholla Unit 4 has experienced a buildup of scale in the SO2 scrubber to the point that it was necessary to take the unit offline for maintenance. The plant operator determined that the addition of dolomitic lime will reduce scale buildup. Prior to the use of dolomitic lime the scrubber needed to be operated in such a way to ensure compliance with existing permits even though scale was being formed during operation. Dolomitic lime was added to the scrubber operations in December 2011 and will continue to be added going forward, including during the test period. The increased cost attributed to the use of dolomitic lime is about $0.33m.
Rocky Mountain Power is requesting approval of an increase in its retail electric utility service rates in Utah in the amount of $172.3m, or 9.7%, and approval of its proposed electric service schedules and electric service regulations to become effective Oct. 12, 2012. Rocky Mountain Power’s request is based upon a forecast test year ending May 2013, using a 13 month average rate base with a historical base period of twelve months ending June 30, 2011.