The Oklahoma Gas & Electric unit of OGE Energy (NYSE: OGE) is bracing for new air emissions control needs, which includes possible SO2 scrubber and dry sorbent injection installations on some of its coal-fired capacity.
OGE noted in a Nov. 7 Form 10-Q quarterly report that the U.S. Environmental Protection Agency’s regional haze rule, with its Best Available Retrofit Technology (BART) provisions, is a big factor in its decision-making. “As required by the Federal regional haze rule, the state of Oklahoma evaluated the installation of BART to reduce emissions that cause or contribute to regional haze from certain sources within the state that were built between 1962 and 1977,” OGE wrote. “Certain of OG&E’s units at the Horseshoe Lake, Seminole, Muskogee and Sooner generating stations were evaluated for BART. On February 18, 2010, Oklahoma submitted its SIP to the EPA, which set forth the state’s plan for compliance with the Federal regional haze rule. The SIP was subject to the EPA’s review and approval.”
The Oklahoma SIP included requirements for reducing NOX and SO2 from OG&E’s seven BART-eligible units at Seminole, Muskogee and Sooner. The SIP also included a waiver from BART requirements for all eligible units at the gas-fired Horseshoe Lake station based on air modeling that showed no significant impact on visibility in nearby national parks and wilderness areas.
The SIP concluded that BART for reducing NOX at all of the subject units should be the installation of low NOX burners with overfire air (flue gas recirculation was also required on two of the units) and set out associated NOX emission rates and limits. OG&E preliminarily estimates that the total capital cost of installing and operating these NOX controls on all covered units, based on recent industry experience and past projects, will be about $100m.
For SO2 emissions, the SIP included an agreement between the Oklahoma Department of Environmental Quality and OG&E that established BART at four coal-fired units located at OG&E’s Sooner and Muskogee stations as the continued use of low-sulfur coal (along with associated emission rates and limits). The SIP specifically rejected the installation and operation of dry scrubbers as BART for SO2 control from these units because the state determined that dry scrubbers were not cost effective.
In December 2011, the EPA issued a final rule in which it rejected portions of the Oklahoma SIP and issued a Federal Implementation Plan (FIP) in their place. While the EPA accepted Oklahoma’s BART determination for NOX in the final rule, it rejected Oklahoma’s SO2 BART determination with respect to the four coal-fired units at Sooner and Muskogee. The EPA is instead requiring that OG&E meet an SO2 emission rate of 0.06 lbs/MMBtu within five years. OG&E could meet the proposed standard by either installing and operating dry scrubbers or fuel switching at the four affected units. OG&E estimates that installing dry scrubbers on these units would include capital costs to OG&E of more than $1bn.
OG&E and the state of Oklahoma filed an administrative stay request with the EPA on Feb. 24. The EPA has not yet responded to this request. OG&E and other parties also filed a petition for review of the FIP in the U.S. Court of Appeals for the Tenth Circuit on Feb. 24 and a stay request on April 4. On June 22, the appeals court granted the stay request. The stay remains in place until a decision on the petition for review is complete, which will delay implementation of the haze rule in Oklahoma. On June 15, OG&E, the state of Oklahoma and other parties filed their brief in support of the petition for review of the final regional haze rule of the EPA. The briefing by all parties was completed in October.
Dry sorbent injection looked at for MATS compliance
In December 2011, the EPA signed the Mercury and Air Toxics Standards (MATS) governing emissions of hazardous air pollutants from power plants. The final rule includes numerical standards for particulate matter (as a surrogate for toxic metals), hydrogen chloride and mercury emissions from coal-fired boilers, the Form 10-Q said. The regulations also include work practice standards for dioxins and furans. The effective date of the final rule was April 16 and compliance is required within three years after the effective date of the rule with a likely possibility of a one-year extension.
“To comply with this rule, OG&E is planning to utilize dry sorbent injection with activated carbon injection at up to five coal-fired units at a cost in the range of $155 million to $310 million (depending on the level of removal), but the timing of such expenditures is uncertain,” the Form 10-Q added. “The final rule has been appealed by several parties. OG&E is not a party to these appeals. OG&E cannot predict the outcome of any such appeals. OG&E is planning to conduct field testing to develop firm cost estimates and implementation schedules.”
OG&E’s coal units are: Muskogee Unit 4, with 504 MW of capacity; Muskogee Unit 5, with 500 MW; Muskogee Unit 6, with 506 MW; Sooner Unit 1, with 515 MW; and Sooner Unit 2, with 523 MW.
While some of the underlying clean air rules are in flux, OG&E plans several new emissions-control projects, said an integrated resource plan (IRP) that the utility filed Oct. 9 with the Arkansas Public Service Commission. The planned projects include:
- Low NOX Burners on seven units, start construction in February 2013, finish February 2017, $122m cost;
- Dry Sorbent Injection on five units, construction start February 2014, finish May 2015, $126m cost; and
- Activated Carbon Injection on five units, construction start February 2014, finish May 2015, cost $21m.
OG&E in the IRP identified five alternatives for controlling SO2 emissions. The first continues the use of low-sulfur coal and the other alternatives use different technologies to achieve higher levels of SO2 reductions. All alternatives assume Low NOx Burners on the seven regional haze-impacted units, ACI by 2015 on all coal units that are planned to run after 2017 and DSI on Muskogee 6 for acid gas removal. Installation dates for emission controls are for analysis purposes only and may differ based on construction constraints and the outcome of the pending review of the EPA’s FIP at the appeals court. The alternatives are:
- Benchmark – add DSI to all coal units by 2015 for acid gas removal;
- Scrub – scrub four coal units by 2018;
- Convert – convert four coal units to natural gas by 2018;
- Hybrid Convert – scrub two coal units by 2018, and convert two coal units to gas by 2018; and
- Hybrid Replace – scrub two coal units by 2018, and replace two coal units with new combined cycle capacity by 2018.
OG&E working through dispute over 2010 coal plant operations
OG&E has also been working through some issues related to operations and fuel costs at its coal-fired plants. The Oklahoma Corporation Commission (OCC) reviews fuel costs through OG&E’s fuel adjustment clause. In August 2011, the OCC staff filed an application to review OG&E’s fuel adjustment clause for calendar year 2010, including the prudence of OG&E’s electric generation, purchased power and fuel procurement costs. OG&E responded by filing direct testimony and the minimum filing review package in October 2011.
On April 6, witnesses for the OCC Staff, the Oklahoma Attorney General and the Oklahoma Industrial Energy Consumers association filed responsive testimony. The witness for the Oklahoma Industrial Energy Consumers recommended that the OCC disallow recovery of about $44m of costs previously recovered through the fuel adjustment clause. This was based on allegations that OG&E’s lower cost coal-fired capacity was underutilized, that OG&E failed to aggressively pursue purchasing of power at a cost lower than its marginal cost of generation and that the utility should be found imprudent over an unplanned outage at the Sooner 2 coal unit in November-December 2010. The witnesses for the OCC staff and the Oklahoma Attorney General recommended that OG&E should provide additional information to allow them to reach a conclusion on their prudence review.
On May 8, OG&E filed rebuttal testimony supporting the appropriateness of its use of coal-fired generation during 2010, its practice regarding purchasing power and the appropriateness of management actions related to the Sooner 2 outage. A hearing on the merits was conducted on July 17 and 18. The witness for the Oklahoma Attorney General offered no further testimony. The witness for the OCC staff recommended approval of OG&E’s actions related to utilization of coal plants and practices related to purchasing power, but recommended that OG&E refund $3m to customers because of the Sooner 2 outage, the Nov. 7 Form 10-Q said.
On Sept. 26, the administrative law judge recommended that the OCC find that for the calendar year 2010 OG&E’s generation, purchase power and fuel procurement processes and costs, including the cost of replacement power for the Sooner 2 outage, were prudent and no disallowance for any of these expenses is warranted. A hearing in this matter is scheduled on Nov. 8 and OG&E expects to receive an order from the OCC in November.