Minnesota Power is using a 465-mile, 250-kV DC transmission line that runs from Center, N.D., to Duluth, Minn., to transport increasing amounts of wind energy from North Dakota while gradually phasing out electricity delivered over this transmission line from Square Butte Electric Cooperative’s coal-fired generating unit in North Dakota, said Minnesota Power parent ALLETE Inc. (NYSE: ALE) in an Aug. 2 Form 10-Q filing.
One of those North Dakota wind projects is Bison 1, which is an 82-MW facility that was completed in two phases. The first phase was completed in 2010 and the second in January. The project also included construction of a 22-mile, 230-kV transmission line. Bison 1 had a total project cost of $173.8m. Minnesota Power expects to incur additional costs of $3.6m through 2013 related to land restoration and completion of remaining associated upgrades for the 250-kV DC transmission line.
Bison 2 and Bison 3 are both 105-MW wind projects in North Dakota which are expected to be completed by the end of 2012. Construction is currently underway for both projects and the total project costs are estimated to be approximately $160m each, of which $123.5m and $100.7m, respectively, was spent through June 30.
Minnesota Power has a power purchase agreement (PPA) with Square Butte that extends through 2026 and provides a long-term supply of energy to customers in its electric service territory and enables Minnesota Power to meet reserve requirements. Square Butte, a North Dakota cooperative, owns a 455 MW coal-fired generating unit near Center, N.D., that is part of the Milton R. Young complex. The unit is adjacent to a generating unit owned by Minnkota Power Cooperative, a North Dakota cooperative corporation whose Class A members are also members of Square Butte. Minnkota Power serves as the operator of the unit and also purchases power from Square Butte.
Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on Minnesota Power’s entitlement to unit output. Its output entitlement under the agreement is 50% for the remainder of the contract, subject to the provisions of a Minnkota Power sales agreement. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power for a period of one year. Square Butte’s costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. As of June 30, Square Butte had total debt outstanding of $419.2m. Annual debt service for Square Butte is expected to be about $44m in each of the five years, 2012 through 2016, of which Minnesota Power’s obligation is 50%. Fuel expenses are recoverable through Minnesota Power’s fuel adjustment clause and include the cost of lignite coal purchased from BNI Coal under a long-term contract.
In December 2009, Minnesota Power entered into a power sales agreement with Minnkota Power. Under the agreement, Minnesota Power will sell a portion of its output from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025. No power will be sold under this agreement until Minnkota Power has placed in service a new AC transmission line, which is anticipated to occur in late 2013. This new AC transmission line will allow Minnkota Power to transmit its entitlement from Square Butte directly to its customers, which will free up Minnesota Power to transmit additional wind-based generation on the existing DC transmission line.
New emissions projects considered as EPA piles on the new air programs
Minnesota Power is also dealing with the impacts of new emissions rules, including the U.S. Environmental Protection Agency’s Cross-State Air Pollution Rule (CSAPR), on its coal-fired capacity. Since 2006, the utility has significantly reduced emissions at its Laskin, Taconite Harbor and Boswell generating units.
“Our analysis, based on our expected generation rates, indicates that these emission reductions would satisfy Minnesota Power’s SO2 and NOX emission compliance obligations with respect to the EPA-allocated CSAPR allowances for 2012,” the Form 10-Q said. “We will continue to evaluate our compliance strategy under the CSAPR and, if any capital investments or allowance purchases are required, we would likely seek recovery of those costs.”
The federal regional haze rule requires states to submit State Implementation Plans (SIPs) to the EPA to address regional haze visibility impairment in 156 federally-protected parks and wilderness areas. Under the regional haze rule, certain large stationary sources, put in place between 1962 and 1977, with emissions contributing to visibility impairment, are required to install emission controls, known as Best Available Retrofit Technology (BART).
“We have two steam units, Boswell Unit 3 and Taconite Harbor Unit 3, which are subject to BART requirements,” the Form 10-Q said. In December 2011, the EPA published in the Federal Register a proposal to approve the trading program in the CSAPR as an alternative to determining BART. On May 30, the EPA finalized this rule allowing states participating in the CSAPR trading programs to use those programs in place of source-specific BART for SO2 and NOX emissions.
On Jan. 2, the Minnesota Pollution Control Agency (MPCA) submitted to the EPA a draft supplemental Minnesota regional haze SIP stating that it would rely on the CSAPR to satisfy BART requirements for SO2 and NOx for electric generating units. On Jan. 25, the EPA published in the Federal Register a proposal to approve the Minnesota SIP, including the supplemental Minnesota SIP. The MPCA submitted the final supplemental SIP to the EPA on May 8. The EPA approved the portion of the Minnesota SIP pertaining to elimination of BART requirements for those power plants which are required to comply with the CSAPR in a final rule published in the Federal Register on June 12. If the CSAPR is reinstated, Minnesota Power does not foresee a need to make significant additional expenditures at Taconite Harbor 3 to comply with the regional haze rule. If additional regional haze related controls are ultimately required, Minnesota Power will have up to five years from the final promulgation deadline to bring Taconite Harbor 3 into compliance.
Under EPA’s Mercury and Air Toxics Standards (MATS), affected sources must be in compliance by February 2015. States have the authority to grant sources a one-year extension and the EPA is assessing other means for granting additional extensions when justified. The company said in the filing that compliance at Boswell 4 to address the final MATS rule is expected to result in capital expenditures totaling between $350m to $400m through 2016.
Under Minnesota law, a mercury emissions reduction plan for Boswell Unit 4 is required to be submitted by July 1, 2015, with implementation no later than Dec. 31, 2018. But, mercury emission limits have also been included in the recently-finalized MATS rule. “We anticipate that the emission reduction plan implemented to comply with the MATS rule will satisfy the mercury emission limits under Minnesota law,” said the Form 10-Q.