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Excluding this years lighting strike, what kind of reliabilty percentage has the plant maintained over the years?
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For the period of 2001 to 2006, the power plant's overall availability has been:96%,96%,95%,96%,95%,97%. These figures include scheduled outages for yearly maintenance. Taking the scheduled maintenance out of the equation, the availability goes to: 99%,100%,99%,100%,99%,100%. The 2007 numbers will be much lower than the past 6 years due to the lightning strike.
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Why did Mr. Butz make it seem the power plant wasn't reliable? In his report he states that there would be a savings of 30 million in 10 years, is that over and above the cost of transmission construction and the 1 million a year required to pay MISO?
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I don't recall Mr. Butz of Power System Engineering making statements regarding the plant being unreliable. In fact, Mr. Butz did make a statement reminding us that if the plant was shut down, we may have less reliable power due to being transmission dependant.
The $20-30M savings over 10 years does not include transmission construction that may be needed. It is unknown at this time what would need to be done and who would pay for any construction. The $1M/year to the American Transmission Company is included in the analysis.
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Thank you for your previous response. Very informative and a useful forum that I hope more people use. I guess I didn't fully understand Mr. Butz presentation. I didn't realize that the 1 million a year was part of the analysis that would be payed to ATC. Very good.
What I don't understand is why it seems that it has to be a "all or nothing" approach. When Mr. Butz covered partial purchase of around 3 MW, in addition to what the plant can produce, it seemed that he thought that was a bad idea. I thought he made reference to, what if something happens "again"? That is why I was wondering what the reliability of the plant has been in previous years. Is the Biomass actually a possiblilty? Again, thank you for taking the time to respond.
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Concerning the 3MW block purchase, Mr. Butz suggested trying to negotiate for point-to-point transmission, as this would be cheaper for us than Network Transmission Service. The downside of the point-to-point would be that if we needed to purchase more than the 3 MW, we would be subject to penalties of up to 50% for any amount purchased over the 3 MW. This would include times of both scheduled and unscheduled outages.
The biomass option is being looked at very seriously. 2 utilities that submitted wholesale power proposals to Escanaba indicated an interest in working with us to convert 1/2 or all of our plant to biomass. Preliminary information shows us that the biomass power will be more expensive than coal power. Therefore, we would not do this conversion on our own. The State of Wisconsin has a renewable energy standard in place that has created a market for renewable energy, and it is expected that there will be a renewable standard soon in MIchigan. If we can generate biomass power at a reasonable price, there will be a market for it. More work needs to be done in this area and is in progress.
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Is there still a possibility of building a new power plant in Escanaba?
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There is always that possibility, but it is not likely in the near or intermediate future. The preliminary cost estimates that Sargent and Lundy provided to the City in June, 2007 were too high for the City and/or WPPI to procede with at this time.
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It is my understanding that the rate payers of Escanaba do not pay for the street lighting. Is this true?
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The City of Escanaba rate payers do not pay for the street lights directly. The street lights are payed for out of the City's general fund, which is funded by the people of Escanaba.
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Page 30 of the PSE analysis states that the average historic cost of plant maintenance is $750,000/year but then it was decided to use $1,200,000 for the analysis. Why? if the $750,000 is used (and still using the 3% annual increase) over $6,000,000 in stated savings do not exist.
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Recent maintenance costs have been: $927,000 in 2004-2005, $1,153,000 in 2005-2006, $750,000 in 2006-2007. There have been some maintenance projects held back in recent years as the City believed there was going to be a new plant built and it did not make sense t o put money into a plant that was going to be replaced soon. The $1.2M figure used in the analysis was based on 1) the highest year of the past three years and 2) higher maintenance costs expected in the future with a 50 year old plant. From 1996-2006, the plant total fixed costs (i.e., Operating Expenses, Administration, Maintenance, and Management Fee) has increased at 5% compound annual growth rate.
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Please confirm as per our conversation that the power supply proposals submitted are not contractual or binding. By requesting non binding proposals what fees and charges will appear in contract negotiations that oops! were inadvertantly forgotten in the proposals?
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The proposals were not binding. If the City chooses to enter into negotiations with 1 or more of the proposing utilities, the proposals will be firmed up in these final negotiations.
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Please explain the administrative increase in the PSE study. 1) 2004-2005 saw an increase from $1.1M to $1.7M-a 55% increase in one year? 2)Please break down administrative costs. 3) $3M per year by 2017? (page 30 & 33 of PSE study)
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Administrative costs were calculated based on the most recent increase in costs from the 2005-2006 to 2006-2007 time period. This cost component is made up of a variety of fringe and overhead expenses. Just as many entities-both public and private-have seen significant increases in their health insurance and pension funding costs, these factors have resulted in increases in this cost component that are larger than the standard inflation rates. Of the total cost increase between 2002 and 2007, over 85% of the increase can be directly attributed to health insurance and pension increases.
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Numerous other issues with the PSE study cannot be independently confirmed without access to the actual power supply proposals. Its a shame with an issue this big that the City is unwilling to give the public access to this information.
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The proposals were submitted as confidential. It is necessary to keep these proposals confidential so the competing utilities cannot know what their competition is offering. This will allow the City to negotiate independently with each utility and get the best deal for the City.
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Power supply comparison sheet states the fixed total cost at $5M. Is this actual? With PRB conversion, the fixed cost is $5.5M. Is this actual? I understand PRB is more expensive to handle but with ash costs of $230,000 will our costs actually triple?
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In the 2006-2007 time period, the total steam plant costs were $11,425,304 and the fuel cost was $6,157,318. This leaves $5,267,986 for all other costs, including maintenance, labor, ash costs, etc. The $5M used in the power supply comparison spread sheets was just rounded off for simplicity purposes. The $5.5M used in the PRB conversion column is an estimate. It is higher than our fixed costs now due to more ash and more maintenance expected with the PRB coal.
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Do we plan to expose both of our existing boilers to the West Ridge coal test? Perhaps to avoid possible damage to the entire plant, we should only test burn in one boiler?
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The test burn will only be done on one boiler, This will enable the operators to concentrate their efforts on fine tuning the boiler to maximize the chances for success. The short period of the test burn and quantity of coal being burned would not result in damage to the plant even if both boilers were burning the coal.
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Will the test boiler be cleaned before testing to insure that we get a fully valid test?
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Both the boilers were cleaned in March during the annual outage. There are no plans to re-clean the boiler scheduled for the test burn. The soot blowing system may be used more frequently on the test boiler if conditions warrant. However, during the previous test burn the problem was with the quantity of ash "fines" not clinker formation.
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Will the West Ridge coal be allowed a drying time on the dock and do we have enough space not to co-mingle this coal with the eastern coal in stock?
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There are not any plans to dry this West Ridge coal, unless water is used to unload the boat, or the coal gets wet sitting on the dock. The moisture of the West Ridge coal is very similar to the eastern coal typically used at the plant. The percent moisture of the West Ridge coal is listed at 7% and the original Eastern coal identified for 2008 was 8%. If we do need to dry the West Ridge coal out, there is plenty of space available on the coal dock to spread it out for drying.
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What are the expectations for the amount of West Ridge coal to generate the same energy of eastern coal?
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The heat content of the West Ridge coal is equal to or slightly higher than the Eastern coal typically used at the plant. Therefore, we are expecting to use an equal amount of tons to generate power.
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Do we have the plant infra-structure to move more coal to the boiler and does the boiler itself have that capacity?
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Again, being that the heat content is equal to or slightly higher than the Eastern coal typically used, we should not have to move more coal. Therefore, our coal handling system in place should be adequate.
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How much burn time is necessary to determine success/failure or make a valid test?
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By contract, we will have 30 days after receipt of the West Ridge coal to make a determination of its suitability. It is expected that this amount of time will show short term problems if they exist, but potential long term problems developing may not be noticeable in this time frame. The potential long term problems include: boiler tube erosion, ash handling system performance, and precipitator performance. A test burn was done with the West Ridge coal in 2002. There was more fly ash observed, which caused some issues with the precipitators. However, there have been some minor adjustments made to the stokers since 2002. It is hoped that the changes made will negate some of the performance issues observed in 2002. Boiler tube erosion will be watched closely as most Western coals are more abrasive than Eastern coals are.
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When and how will the results be made public?
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The results will be made public within 30 days of receipt. The results of the test will be released throught the Electric Advisory Committee, City Manager's Call, and various City Council meetings.
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Are we using any outside experts or consultants to help evaluate the test? If so, who?
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A precipitator expert will be brought in to "tune-up" the precipitator controls to maximize performance. As previously stated, ash carry-over will be one of the areas of concern and we will need to make sure this doesn't translate into high opacity from the stack, and possibly violating our environmental permits.
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How are we to inspect the West Ridge coal when it is a different type for us?
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It will be inspected to ensure that it meets the specifications attached with the quotation. It will be tested to ensure the heat content, moisture content, etc are in range with the values quoted for each parameter.
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How has the price of diesel fuel changed since the CT was installed?
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On June 2, 2002 the City purchased diesel fuel for $0.73150/gal. On March 20, 2008 the City purchased diesel fuel for $3.32610/gal.
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What are the costs of Renewafuel briquettes?
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The City has not requsted a quotation from Renewafuel. However, the Marquette Board of Light and Power was scheduled to do a test burn with the Renewafuel briquettes recently. The published price was $95/ton. These briquettes contain approximately 8500 Btu/lb. This yields a cost of $5.59/MMBtu. The West Ridge coal for the test burn has a cost of $3.86/MMBtu.
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The administration and EAC members have claimed that we will be able to buy power for less than we can generate due to the much better heat rate of the new plants coming online in Wisconsin. But, the old plants owned by these utilities will stay online. Why would they sell us the cheapest power off these new plants and keep the relatively expensive power from their old plants for themselves?
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The older, larger plants are still much more efficient than the Escanaba plant. As an example, the new plants under construction in Oak Creek, WI are expected to have heat rates of 8,600 each. One old plant at this same site has a heat rate of 9,424. Both of these heat rates are much better than the Escanaba plant's heat rate of 14,500.
The utilities that supplied power puchase proposals to Escanaba use a pricing mechanism in which each wholesale customer pays an average cost of their total mix of generation assets. Basically what this means is that we would be paying for some of our power from old coal plants, some from new coal plants, some from combined cycle intermediate load plants, some from simple cycle peaking plants, etc. None of the utilities proposing full service supply contracts expressed an interest in maintaining the Escanaba power plant in operation as coal fired units. Two of the utilities expressed an interest in evaluating a biomass fuel conversion for the Escanaba power plant where the higher cost stucture might be competitive.
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What are the parameters that will be measured to declare the test burn a success or a failure?
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The parameters that will be measured and/or watched will be:
Heat Rate-the heat rate will be measured to monitor the plant efficiency
Ash carryover/ash bed on grate-the amount of ash going to the precipitator will be monitored. the ash bed on the grates will be monitored.
Opacity-the opacity will be monitored to see if our particulate emissions increase.
Slagging-the boiler walls will be monitored for a possible increase in the amount of slagging that occurs.
Clinkers-the boiler will be monitored for a possible increase in clinkers.
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If we had a private partner in the operation of the plant while running it as a biomass fueled facility, would they qualify for a Production Tax Credit?
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It is unclear at this time if a private partner would qualify for Production Tax Credits (PTC). The PTCs are scheduled to expire at the end of 2008. They have been renewed in other years, extending the time frame for their eligibility. The City is continuing to explore the possibilities in this area and will report findings to the Electric Advisory Committee.
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Is the power plant staying under our allowable emissions limits while burning the Westridge coal?
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Yes, the Westridge coal is very similar to the Eastern coal in properties that are relevant to the emissions. The primary concern is the % sulfer in the coal. We are allowed a minimum of 1.5% sulfur content as received. The Westridge coal we are now burning tested was analyzed and contained 1.2% sulfur as received. Also, the stack opacity is well within limits.
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Has the City had an independent analysis of the Westridge coal performed?
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A sample of the Westridge coal has been sent to an independent lab for full analysis.
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Has the City done a full-load test using the Westridge coal?
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City load has not dictated that we run the generators at full power. However, we recently performed some full-load tests and were able to generate nameplate output.
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What is the mercury content of the Westridge coal?
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The mercury is measured in an emissions test, as part of the trace metals determination, in accordance with DEQ standards and regulations.
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