By Teresa Hansen, Associate Editor
The air in the Minnesota Twin Cities will soon be cleaner thanks to a visionary plan proposed by Xcel Energy, parent company of Northern States Power (NSP), just more than five years ago. Xcel Energy proposed to the Minnesota Public Utility Commission (PUC) a plan to significantly reduce air emissions from three of its coal-fired power plants in the Twin Cities area while increasing generating capacity. Xcel Energy developed the $1 billion package, called the Metro Emissions Reduction Project (MERP), in response to an emissions reduction bill passed by the Minnesota legislature in 2001, encouraging utilities to make voluntary emissions reductions. The bill is written so that electric utilities can recover the costs of qualifying voluntary emissions reduction projects without going through a full rate case proceeding.
Xcel Energy submitted the MERP proposal in July 2002 and the PUC approved it in December 2003. The utility closely evaluated the emissions reduction alternatives in the Twin Cities area to identify plants and projects that could provide significant emissions reductions at a reasonable cost to customers. Xcel Energy settled on a plan to install state-of-the-art emissions control equipment at its Allen S. King plant and convert its High Bridge and Riverside plants from coal to natural gas. Xcel Energy expects the three-plant project, which is well underway, to add at least 410 MW of capacity while significantly reducing emissions (Table 1).
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Minnesota’s Environmental Legislation
Xcel Energy worked with key stakeholders to craft the legislation, which was fashioned after a similar, but smaller-scale model involving Xcel Energy in Denver.
“This legislation offers an effective approach to encouraging emissions reductions by reducing the timing lag and processes that would be required to gain approval for both these three projects and the associated cost recovery,” said Judy Poferl, Xcel Energy’s Director of Regulatory Administration. It also eliminates some of the unknowns and risks, since cost recovery issues are addressed at the same time as project approval, she said.
 Construction is in the early stages on the Riverside plant, located on the Mississippi River in northeast Minneapolis, Minn. Photo courtesy of Xcel Energy. |
Under the legislation, the initial project proposal is presented to the PUC, the Pollution Control Agency (PCA) and interested parties for review. The PCA provides an assessment of the project’s environmental benefits. After weighing the input of the PCA and other interested parties, the PUC weighs the project’s benefits against its cost. If it determines the cost-benefit is reasonable and consistent with the public interest, the PUC approves the project and an associated rate rider to facilitate cost recovery.
“The legislation is beneficial to all Minnesota investor-owned utilities (IOUs) because it allows them to recover the costs for an approved project without a general rate case hearing,” Poferl said. “A target rate of return is set and approved.”
This does not mean, however, that because the MERP is approved and the rate of return set Xcel is no longer accountable to the PUC. A rate recovery filing for the project is submitted annually to the PUC. In addition, Xcel is subject to PUC audits at any time. “Our costs remain subject to traditional regulatory review for prudence,” said Poferl.
The Minnesota Legislature’s main reason for enacting this law was to encourage utilities to make voluntary emissions improvements. The legislation includes an emissions reduction rider that bars a utility from recovering any costs associated with correcting environmental violations or compliance issues that are necessary to bring a power plant up to state and/or federal requirement. Therefore, Xcel had to prove to the PUC that its proposed project was going to significantly reduce emissions beyond current permit requirements.
The law also required Xcel Energy’s proposal to be reviewed by the Minnesota PCA, said Ron Elsner, Xcel Energy’s Project Director.
The PCA determines if the proposal looks accurate and credible and if the proposed project will actually provide the claimed environmental benefits. “If it doesn’t pass muster with the pollution control agency, the PUC isn’t likely to look any further,” Elsner said.
One major benefit of the legislation is that it allows the utility to begin recovering costs early in the process. Xcel Energy was allowed to begin recovering costs prior to completing the project when the refurbished plants return to service. Because the PUC allowed Xcel Energy to start collecting its return on capital used in construction early on, it can better manage the cost and financing for the project. What’s more, beginning cost recovery early lowers total costs to the customers, as it eliminates carrying charges on large capital expenditures over the five-year construction period. “This equates to a lot of savings in carrying costs, which in turn means savings for Xcel’s customers,” said Poferl. “Basically, it decreases the cost of the overall project.”
Power Plant Selection
When Xcel Energy evaluated its power generation facilities to choose the best way to take advantage of the emissions reduction legislation, it not only considered environmental improvements, but also the best way to add capacity and use the existing infrastructure.
“Xcel Energy was faced with load growth and an aging fleet-not a good combination,” said Poferl. “We needed to increase capacity and update our fleet to carry us into the future. These three sites seemed like the best way to do that.”
With this project, Xcel Energy is making environmental improvements and adding more than 400 MW of capacity while using the same transmission infrastructure.
“These plants were economically and physically at the end of their useful lives,” said Elsner. “We knew there would be value in reusing these locations.”
The High Bridge and Riverside plants are in or near densely populated locations as well as close to large loads and existing infrastructure. King plant is in a key location to support the grid, located at the east end of the Twin Cities metro area where it is vital to the operating stability of the transmission system. Had King not been rehabilitated, some sort of base load generation would have been required at or near that location to keep the grid stable.
“Environmental concerns are growing, and we weren’t likely to get a lot of local support or PUC approval if we had asked to keep High Bridge and Riverside coal-fired plants and/or not make significant environmental changes at King,” Poferl said.
To keep the King plant operating on coal, it is undergoing a significant emissions control upgrade. “We went above and beyond environmental requirements to keep the plant operating,” Poferl said. Xcel could have continued to operate King plant without making any environmental improvements. “We decided, however, to modernize it and take it a level where it could take us into the next era of generation.”
Gaining Public Support
Public support for the project was overwhelming, Poferl said. Neighborhood and environmental groups were brought into the process early-even before Xcel Energy submitted its proposal to the PUC.
Initially, businesses were concerned that power prices might be too high, especially with the volatility of natural gas prices. The eventual settlement reached regarding the project contained important provisions to address the business community’s concerns, including requirements regarding hedging of natural gas prices used to fuel the High Bridge and Riverside plants.
Elsner organized neighborhood meetings after which “a number of adversaries actually became supporters during the approval process,” he said. These groups saw that the Xcel Energy project was an effort by the utility to make the environment better. They also recognized that Xcel Energy didn’t have to make the improvements, but that the decision was entirely voluntary.
Elsner credits much of the support to the fact that Xcel Energy was attentive to details from the beginning and made sure that the facts it released were correct and accurate. This, he believes, helped the utility’s credibility. He also believes that the regulators’ thorough review of the project during the licensing process helped build public support.
Organizations and the public were excited about the project because it was large enough to make an impact on the nearby communities. “The size of the project was instrumental in creating enthusiasm about it,” Poferl said.
Because both major cities were included in the project, the extent to which anyone felt slighted or overlooked was minimized. There was some apprehension about which city’s project would go first. Some worried that Xcel Energy might cancel the project’s second phase after the first one was started. Concerns surfaced that the utility might run out of funding or decide after the first plant was underway that a second wasn’t economically feasible.
Another important factor was that the project never progressed to an evidentiary hearing. “We were able to negotiate a settlement with all interested parties without a contested-case hearing,” Poferl said. Some of the organizations/groups involved in the approval process included the Sierra Club, Chamber of Commerce, American Lung Association, municipalities and businesses. “This left everyone, the utility, regulators, customers, businesses, organizations and so on, with a better feeling about the project.”
Natural Gas Concerns
Natural gas price volatility is a concern for many utilities, but proved not to be a major concern for Xcel Energy. In NSP’s territory, Xcel Energy is not a heavy natural gas user. “Our generation portfolio is varied and far from natural gas-heavy,” Poferl said.
Mitigating factors also included the fact that Minnesota has access to Canadian natural gas and Mid-Continent natural gas through four different pipelines running through the state. “Pricing in the state is pretty competitive,” Elsner said. “We don’t have to worry about being held captive by one supplier or another.”
In addition, the power plants are located in the MISO (Midwest Independent Transmission System Operator) region, which will determine when the plants are or are not competitive. The power from the High Bridge and Riverside plants will only be dispatched if the price is competitive. “The market, administered by MISO will set the competitive price,” said Poferl.
Nevertheless, a gas price spike that occurred during the MERP licensing process concerned regulators enough that they ordered a separate hearing on natural gas prices.
“We ran families of natural gas cost curves for both High Bridge and Riverside, using six to eight natural gas price scenarios in the model,” Elsner said. Xcel Energy considered the possibility that the plants might run only a little if the gas prices were high and remained high, and it looked at whether moving forward with the projects would be cost effective in the face of high gas prices. The utility also considered the economics if the plants ran a lot. It presented all of these scenarios to the PUC for consideration.
Project Status
As of early April, all permits were in place for all three MERP plants. These permits include not only environmental permits, but also operations permits. The regulatory process took 22 months.
All three plants that are part of the MERP are actively under construction. King plant is substantially complete and is in the start up testing process. King plant’s first coal fires were on Earth Day (Sunday, April 22), exactly two years from the day ground was broken at the site. That day, too, was Earth Day. Construction is about half completed on High Bridge plant. It is a two-on-one combined- cycle plant. Once completed, the old plant will be razed and the stack torn down. For now, the old plant is still running.
Riverside had its ground breaking ceremony on April 20, also to coincide with Earth Day. Some foundation work was completed prior to groundbreaking, but construction remains in the early stages.
MERP PROJECT DESCRIPTIONS
King Plant Rehabilitation
The Allen S. King plant is on the St. Croix River in Oak Park Heights, Minn. It is a 571 MW single-unit coal-fired plant with a cyclone boiler that came on-line in 1968. It is a base load unit that burns Wyoming and Montana coal. King formerly burned pet coke as a part of its fuel mix, but it will not be burned following the rehabilitation project. The plant’s boiler is 20-stories tall. The boiler is a cyclone-fired, supercritical boiler, and is one of the few of its vintage that, up until the rehabilitation, retained its original cyclones and floor. King plant has an 85 percent average availability rate and a 75 percent capacity factor.
The plant’s performance is one of the main reasons Xcel Energy decided to rehabilitate it rather than replace it with a new combined-cycle combustion turbine.
The MERP will add a new air quality control system that includes selective catalytic reduction (SCR) for nitrogen oxide (NOX) control, flue gas scrubbers (FGD) for sulfur dioxide (SO2) emissions control and fabric filters to control particulate matter. The rehabilitation also includes steam turbine replacement, steam generator repairs and modifications, circulating water system modifications, coal handling upgrades, auxiliary electric system upgrades and other equipment improvements to extend the life of the plant and make the emissions control upgrades economically feasible. The existing 785-foot-tall stack will continue to be used.
In addition to reducing emissions (see Table 1 in the main feature), the rehabilitation will recover 60 MW of routinely dispatchable capacity and should cost $385 million. (Note that this and all other project costs are estimates based on 2001 dollars.)
| Scrubber/Baghouse | Alstom Environmental Controls |
| SCR | Mitsubishi Power Systems |
| Steam Turbine | Alstom Power |
| Boiler Rehabilitation | Babcock & Wilcox |
| Control System/DCS | Emerson |
High Bridge Plant Replacement
The High Bridge plant is on the Mississippi River near downtown St Paul, Minn. It is a multi-unit coal-fired plant. Two of the units, built in 1942 and 1944, are used only to produce steam for a nearby manufacturing facility. The original two units, built in 1924, have been retired for some time. The two newest units went into service in 1956 and 1959 and together generate 267 MW.
The MERP will replace the existing coal-fired units with a natural gas-fired combined-cycle unit consisting of two combustion turbines, two corresponding heat recovery steam generators (HRSGs) and a new steam turbine. The new plant will be installed in a new building located at the southwest corner of the existing site. This new plant will use the existing circulating water supply and return from the Mississippi River. Once the new plant is brought on-line, the existing plant and its accompanying structures (including a 565-foot-tall stack) will be demolished.
The replacement will add 270 MW to 280 MW in generation capacity and is expected to cost $394 million.
| Turbo Machinery | Mitsubishi Heavy Industries |
| HRSG | Nooter Erickson |
| EPC | Lockwood Greene |
Riverside Plant Repowering
The Riverside Plant is on the Mississippi River in northeast Minneapolis, Minn. It is the oldest coal-fired plant in the Xcel Energy system, with the first of the eight units being built in 1911. Only three of the units (Units 6, 7 and 8) are currently functioning; they produce 373 MW in total. Units 1 through 5 were abandoned in place. The abandoned units date between 1914 and 1930.
Units 7 and 8 have three functioning boilers. Boilers 6 and 7 currently drive the Unit 7 generator and boiler number 8 drives the Unit 8 generator. The MERP project will replace the existing Units 7 and 8 with a natural gas combined cycle arrangement with two combustion turbines and corresponding HRSGs. Steam produced in the HRSGs will be used to drive the existing Unit 7 steam turbine. After the new turbines and steam generators are constructed, Unit 7 will be taken out of service and the new steams lines from the heat recovery boilers installed. Unit 8 will continue to operate in its current fashion until the new units are fully operational. It will then be retired and demolished.
The repowering project will increase the plant’s generating capacity by 80 MW for an estimated cost of $226 million.
| Engineering contractor | Sargent & Lundy |