The Idaho Public Utilities Commission on June 1 adopted adjustments to Idaho Power rates in seven separate cases that overall represent about a 0.6% increase for all customer classes combined.
Idaho Power is a unit IDACORP (NYSE: IDA). Still pending before the commission is an application by Idaho Power to increase its annual revenue by $60m to pay for the $398m, 300-MW Langley Gulch natural gas-fired power plant in Idaho, which is due in operation imminently. If that application is approved, residential rates will increase by 6.6% effective July 1.
On June 1 of every year since 1993, Idaho Power is allowed to adjust its rates up or down to reflect its annual cost of providing electricity. Because about half of its power generation comes from hydropower facilities, Idaho Power’s power supply expenses vary from year to year due to changes in Snake River streamflows and in wholesale market power prices.
This year’s water forecast is slightly better than normal hydro conditions for the April-July runoff period, so water is not a primary factor in this, the commission noted. About 95% of the $70m in additional power supply expense is in new power purchases from wind farms under the provisions of the federal Public Utility Regulatory Policies Act.
Among the rate adjustments effective on June 1 was an 0.18% increase in the Boardman coal plant balancing account. In February, the commission approved Idaho Power’s application to establish a balancing account related to the early closure of the Boardman plant in Oregon. Idaho Power is a 10% of the owner of the plant, which is due to be closed in 2020. Portland General Electric is the primary owner of the plant. The balancing account tracks, on a cumulative basis, the difference between revenues and expenses associated with the shutdown. It ensures customers pay only for actual expenditures.
Another adjustment is an 0.08% increase in a transmission deferral mechanism. Idaho Power is allowed to recover $2m over three years for lost transmission revenue associated with a federal transmission case. The adjustment increases base energy rates by .0052 cents per kWh. The Federal Energy Regulatory Commission (FERC) found that Idaho Power had assessed transmission fees to PacifiCorp for transmission service on Idaho Power lines that were significantly lower than the Open Access Transmission Tariff (OATT) rates Idaho Power proposed to charge other customers for similar transmission service.
The rate charged PacifiCorp was part of three “Legacy Agreements” the two utilities entered into during the 1960s regarding transmission service from their co-owned Jim Bridger coal plant in western Wyoming to each utilities’ respective service territories. Since the initial FERC order, Idaho Power petitioned for rehearing and did amend portions of the Legacy Agreements, but the utility lost on appeal, the Idaho commission noted.
Portland General readies for air controls at Boardman
Portland General Electric (PGE) reported in its May 3 Form 10-Q quarterly report that in June 2011, the U.S. Environmental Protection Agency approved revised rules that established new emissions limits at Boardman and provide for coal-fired operation to cease no later than Dec. 31, 2020. The emissions limits imposed under the revised rules require the addition of certain controls. PGE’s portion of capital spending on the Boardman emissions controls through March 31, 2012, was about $24m.
In December 2011, the EPA issued new emissions limits under the National Emission Standards for Hazardous Air Pollutants (NESHAP) from coal- and oil-fired electric generating units. Emissions limits included in the NESHAP are based on the application of maximum achievable control technology (MACT). Based on its review of the rules and the preliminary full-scale test results, PGE said it believes Boardman should be able to meet the MACT requirements with the installation of the currently planned controls.
PGE began activated carbon injection and calcium bromide injection to achieve mercury emissions reductions at Boardman in 2011, said PGE in March 30 testimony filed at the Oregon Public Utility Commission in a power supply cost update.
The Regional Haze Rules established by the Oregon Department of Environmental Quality mandate a maximum level of SO2 emissions that must be achieved beginning July 1, 2014. A dry sorbent injection (DSI) system, using Trona as the sorbent, is being installed in order to help achieve compliance with the DEQ requirements. The DSI system is currently scheduled to be operational beginning in July 2013.
In 2013, concurrent with the performance testing of the DSI system, PGE will be burning coal with reduced sulfur content, said the March 30 testimony, without adding detail about that new coal supply. The sulfur content of the coal influences the amount of Trona needed to achieve a given SO2 emission level.
In addition to completing testing and installation of new emissions controls at the plant, PGE said on its website that it will engage stakeholders in a comprehensive analysis of potential options to replace the power from the Boardman plant — or convert the existing plant to a different fuel, such as biomass — as part of its integrated resource planning process.
Boardman is a 585-MW plant in northeastern Oregon. It is one of PGE’s most cost-effective sources of power, producing electricity at a variable cost of about one-third to one-half the wholesale market price, the company website said. Boardman provides about 15% of the power PGE delivers to its customers. PGE operates the plant and owns 65% of it. The other owners are: Bank of America Leasing LLC, 15%; Idaho Power, 10%; and Power Resources Cooperative, 10%.
U.S. Energy Information Administration data shows Boardman taking coal in the first quarter of this year only from the Eagle Butte mine, an operation in the Wyoming Powder River Basin owned by Alpha Natural Resources (NYSE: ANR).