The Tucson Electric Power (TEP) unit of UniSource Energy (NYSE:UNS) had increased generating output in 2011 compared with 2010, with that higher output primarily due to the increased availability of TEP’s largest coal-fired facilties, Springerville Units 1 and 2, said UniSource in its Feb. 28 annual Form 10-K report.
In 2010, Springerville Units 1 and 2 experienced unplanned outages, in addition to a planned maintenance outage at Springerville Unit 1, the Form 10-K added.
TEP generates, transmits and distributes electricity to about 404,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western U.S. In addition, TEP operates Springerville Unit 3 on behalf of Tri-State Generation and Transmission Association and Springerville Unit 4 on behalf of the Salt River Project.
TEP’s principal fuel is low-sulfur, bituminous or sub-bituminous coal from mines in Arizona, New Mexico and Colorado. More than 90% of TEP’s coal supply is purchased under long-term contracts, which results in more predictable prices, the Form 10-K said. The average cost per ton of coal, including transportation, for 2011, 2010 and 2009 was $46.64, $41.99, and $39.81, respectively.
In 2003, TEP amended and extended the long-term coal supply contract for Springerville Units 1 and 2 through 2020 and expects coal reserves to be sufficient to supply the requirements for those units for their presently estimated remaining lives. During the extension period from 2011 through 2020, the coal price is determined by the cost of Powder River Basin coal delivered to Springerville Unit 3 subject to a floor and ceiling. This range would be from $19.30 to $26.15 per ton. TEP estimates its future minimum annual payments under this contract to be $14m from 2012 through 2020.
TEP is the operator and sole owner (or lessee) of Springerville Units 1 and 2 and Sundt Unit 4. The coal supplies for Springerville Units 1 and 2 are transported about 200 miles by railroad from northwestern New Mexico.
TEP does not have a long-term coal supply contract for Sundt Unit 4. TEP purchases coal for that unit on the spot market and can supply it with natural gas it is competitive with coal. Coal burned at Sundt Unit 4 represents less than 10% of TEP’s total coal consumption. In December 2011, the take-or-pay obligations under a coal transportation agreement previously effective through December 2015 were terminated. As a result, TEP is relieved of a $4m obligation recognized under this contract in December 2010. TEP reversed a $4m regulatory asset. TEP has a short-term coal contract for Sundt Unit 4 ending Dec. 31, 2012, and has hedged gas costs through September 2012.
The coal supplies for Sundt are transported about 1,300 miles by railroad from Colorado. Prior to 2010, Sundt Unit 4 was predominantly fueled by coal; however, it also can be operated with natural gas. Both fuels are combined with methane piped in from a nearby landfill. Since 2010, TEP has fueled Sundt Unit 4 with both coal and natural gas depending on which resource is most economic. In 2012, TEP expects to fuel Sundt Unit 4 with natural gas.
San Juan mine fire leaves parties looking for options
TEP also participates in jointly-owned generating facilities at the coal-fired Four Corners, Navajo and San Juan, where coal supplies are under long-term contracts administered by the operating agents.
In September 2011, a fire at the underground mine of BHP Billiton that provides coal to the San Juan plant in New Mexico caused mining operations to shut down. TEP owns about 20% of the San Juan plant, which is operated by Public Service Co. of New Mexico. “As we are unable to predict when operations will resume at the mine, we and the other owners of San Juan are considering alternatives for operating the facility,” said the UniSource Form 10-K. “However, based on information we have received to date, we do not expect the mine fire to have a material effect on our financial condition, results of operations, or cash flows due to the current inventory of previously mined coal and the current low market price of wholesale power.”
PNM Resources (NYSE:PNM), the parent of Public Service Co. of New Mexico, had more details on the San Juan mine fire in its Feb. 29 Form 10-K report. In September 2011, the BHP Billiton unit that runs the mine informed PNM that the fire was extinguished and continues to report that all measurements from the area of the fire continue to suggest the fire is extinguished. However, the U.S. Mine Safety and Health Administration required sealing the incident area and confirmation of a noncombustible environment before allowing re-entry of the sealed area. BHP Billiton informed PNM that MSHA approved a sealing plan in October 2011. BHP Billiton has indicated to PNM that it believes the mine’s longwall equipment has experienced only minor damage, if any, and currently estimates being able to restart longwall mining operations in early May 2012.
“However, if the longwall mining operation is shut down longer than currently anticipated by [BHP Billiton], PNM and the other owners of [the San Juan Generating Station] would need to consider alternatives for operating SJGS, including running at less than full capacity or shutting down one or more units, the impacts of which cannot be determined at the current time,” said the PNM Resources Form 10-K. “In late February 2012, [BHP Billiton] began the process of re-entering the sealed portion of the mine. Although no unanticipated conditions have been encountered to date, a complete assessment of the incident site and the longwall mining equipment cannot be made until full access is made to the sealed area.”
As of the September 2011 mine fire, there were inventories of previously-mined coal available to supply SJGS for about 8.5 months at forecasted consumption. Production from continuous miner sections of the San Juan mine was re-started in November 2011 and coal sourced from other mines is being considered to supplement inventories.
Tucson assesses impacts of EPA air rules
Under the Mercury and Air Toxics Standards (MATS) rule issued by the U.S. Environmental Protection Agency in December 2011, mercury and particulate emission control equipment may be required at the Navajo plant by 2015, the UniSource Form 10-K said. TEP’s share of the estimated capital cost of this equipment for Navajo is less than $1m for mercury control and about $43m if the installation of baghouses to control particulates is necessary.
Based on the EPA’s final MATS standards, mercury emission control equipment may be required at Springerville by 2015. The estimated capital cost of this equipment for Springerville Units 1 and 2 is about $5m. The annual operating cost associated with the mercury emission control equipment is expected to be around $3m.
Current emission controls at the San Juan plant are expected to be adequate to achieve compliance with the EPA’s final MATS standards. TEP also does not anticipate the final EPA rule will have a material impact on TEP’s capital expenditures related to Sundt Unit 4.
Based on the EPA’s final MATS standards, mercury emission control equipment may be required at Four Corners by 2015. The estimated capital cost of this equipment is less than $1m, with the annual operating cost expected to be less than $1m.
The EPA’s regional haze rules, designed to protect national parks and other scenic areas, require emission controls known as Best Available Retrofit Technology (BART) for power plants. The rules call for all states to submit the EPA haze compliance within a revised a state implementation plan (SIP). Navajo and Four Corners are located on the Navajo Indian Reservation and therefore are not subject to state jurisdiction. The EPA is the lead regulatory agency for these plants in terms of regional haze planning.
“Compliance with the EPA’s BART determinations, coupled with the financial impact of future climate change legislation, other environmental regulations and other business considerations, could jeopardize the economic viability of the San Juan, Four Corners and Navajo plants or the ability of individual participants to meet their obligations and maintain participation in these plants,” said the UniSource Form 10-K. “TEP cannot predict the ultimate outcome of these matters.”
In August 2011, EPA Region VI issued a federal implementation plan (FIP) establishing new emission limits for NOx, SO2 and sulfuric acid emissions at the San Juan plant. The FIP requires the installation of selective catalytic reduction (SCR) technology with sorbent injection on all four units within five years in order to reduce NOx and control sulfuric acid emissions. San Juan is able to meet the FIP’s SO2 limit with current emissions control equipment. Based on two cost analyses commissioned by plant operator PNM, TEP’s share of the cost to install SCR with sorbent injection is estimated to be between $180m and $200m.
In September 2011, PNM filed a petition to review the FIP with the U.S. 10th Circuit Court of Appeals challenging various aspects of that plan. In addition, PNM filed a request with the EPA to stay the five-year installation timeframe for environmental upgrades ordered by the FIP until the 10th Circuit considers and rules on the petition to review. The court on March 1 refused to grant that stay.
In February 2011, the EPA supplemented the proposed FIP for the BART determination at Four Corners that it had originally issued in 2010. If approved, the revised plan would require the installation of SCR on Units 4 and 5 by 2018. TEP’s estimated share of the capital costs to install SCR is about $35m.
The EPA is expected to issue a proposed rule establishing the BART for the Navajo plant following the consideration of a report by the National Renewable Energy Laboratory in partnership with the U.S. Department of the Interior and the U.S. Department of Energy. The report addresses potential energy, environmental and economic issues related to compliance with the regional haze rule. The report was submitted to the EPA in January. A final BART rule is expected later in 2012.
If the EPA determines that SCR is required at Navajo, the capital cost impact to TEP is estimated to be $42m. In addition, the installation of SCR at Navajo could increase the plant’s particulate emissions, necessitating the installation of baghouses. If baghouses are required, TEP’s estimated share of that cost would be about $43m. The cost of required pollution controls will not be known until final determinations are made by the regulatory agencies. TEP anticipates that if the EPA finalizes a BART rule for Navajo that requires SCR, the owners would have five years to achieve compliance.