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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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All of the costs identified on pages 30 and 33 represent costs directly associated with running the generating plant. These costs are segregated from the operational expenses category based on UPPCo's accounting and billing systems. Included in this category are costs attributable to UPPCo's employees (health insurance, pensions, FICA, state and federal unemployment, worker's compensation and administrative labor for employees located at other locations) and property and liability insurance.
The steep increase in this category is mainly attributable to health insurance and pension benefit cost inceases; the total increases are not limited to the 2004/2005 fiscal year. In 2001/2002, these costs totaled $666,000. This indicates that the amounts billed by UPPCo for these costs have seen an average compounded increase of over 35% per year in that time frame. While projecting these costs into the future is difficult - and we have subsequently experienced a decrease in some of these costs - the average compounded increase of less than 6% used in the report seems reasonable given our past experience.
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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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Concerning federal tax credits for biomass by a private firm isn''t any tax savings mis leading, as a private firms operating expense would be higher because they would have to pay taxes in the first place?
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While not being an authority on federal taxes, it is believed that tax credits could be transferred within a conglomerate of businesses. What this means is that a large corporation that has profit making businesses with tax liabilities could take tax credits from another business within the same company. An example would be taking the tax credits from a biomass fired power plant operated by one company and offsetting the tax liability of another company.
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Why doesn't the city have someone to correct inaccuracies reported in the local media? ie 13.5 million in fuel prices. Wasn't it 1.3 million?
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The city cannot control what is reported in the local media. The Electric Department is budgeted to lose $1.7 million this year due to the increase in coal costs.
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How come the EAC meeting minutes are not updated in a timely manner?
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The EAC minutes have always been approved before they are posted. Starting this month we will start to post draft minutes. These minutes will be posted within 8 business days after the meeting.
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If the city was to sell, lease or shutdown the plant, do the citizens of Escanaba get to vote on it or is it a City Council decision.
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Sale of the Plant: The plant cannot be sold without a 3/5ths vote of the people voting.
Lease of the Plant: The plant cannot be leased without a 3/5ths vote of the people voting
Buy Power (100%) from outside source and mothball plant (but retain ownership): The City would not be able to mothball the plant without a 3/5ths vote of the people voting. Assuming the plant would then be allowed to just deteriorate and eventually would no longer be able to produce electricity.
Buy Power (100%) from outside source and down size the plant to minimal levels: The City could do so without a vote of the people as long as the plant was maintained and was able to be ramped up for use in the future.
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Has the City of Escanaba been paying any charge to utilize the ATC transmission lines to export/import power previous to this date?
What triggered the ATC to consider charging the City of Escanaba a service fee for the use of their transmission system to import/export power?
If we did not have the peaking unit and did not export the power associated with the peaking unit, would the City of Escanaba be subject to the proposed charges for the use of the ATC transmission lines?
If we pay a charge to ATC for the use of their transmission lines, would ATC upgrade their lines to improve the import power availability (IE quality and quantity)?
If UPPCo (or the party that purchases excess power) has contracted to purchase power from the City of Escanaba (available from our peaking unit) why isn't UPPCo paying that charge to transfer the power across the transmission lines owned by ATC?
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Yes, the City of Escanaba has been paying charges to utilize the ATC transmission lines to import/export power previous to this date, but it has been at a much smaller amount than we may be paying in the future. ATC has always charged us some to use their lines, they are considering using a different methodoloy to determine our charges. Yes, the City of Escanaba would be subject to the proposed charges for the use of the ATC transmission lines even if we did not have the peaking unit and did not export the power associated with the peaking unit. ATC will not upgrade their lines based on Escanaba paying more for transmission access. They will upgrade their lines if we show a need for improved lines and commit to importing more power. Escanaba's charges are based off of the amount of power we are taking in at the time of the monthly ATC system peak. The proposed charges would be based off our total load at the time of the monthly ATC system peak. Escanaba would not be charged for power being sold at the time of the monthly ATC system peak.
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On page 45 of the information posted from the EAB meeting, from the notes section of the memorandum dated October 6, 2008; it states that if the electors pass the proposal to obtain eneregy from alternate sources, the need to renew the plant operating agreement is voided and will simply self-expire. My question is, what would the self-expire date exactly be?
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UPPCO enacted their 3 year termination notice of the current operating agreement to the City on June 4, 2008. Therefore, the expiration date of the current operating agreement is June 5, 2011.
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Did you ever consider net metering for solar power users?
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Yes, there have been some preliminary discussions on developing a net metering policy, but nothing is in place at this time.
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I was reading the details of the 2009 Economic Stimulus plan that is going through congress. Amazingly, I didn't see a word about the "Shovel Ready Project" that we have on hand. From what I have learned on the Escanaba power plant upgrade project is that we have all of the required permits, and we are only missing someone to put up half of the cash to get the shovels digging. Why hasn't someone from the city of Escanaba contacted our congressman or senator to have this project put into the stimulus package? This is exactly the type of "Shovel Ready Project" that they are looking for. And, it seems to me that they would be jumping all over this if they also knew that they would get this entire project done for half of its total cost.
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We are researching the issue to determine if it is legal for the City to operate a plant as a merchant plant. By merchant plant, I mean a plant that does not serve customers directly, rather, it sells power onto the transmission system.
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Once the ballot lanquage is turned in, MUST the voters vote on it? Or can it be taken off the ballot if to many questions are left unanswered? It seems like the deadline is fast approaching to have the ballot language in, but it seems like there is even more information that is still not answered. At least that is the impression I had from the EAC meeting on Feb. 4th.
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If something comes to our attention between now and May 5th that would be considered a deal breaker, we have the ability to pull the question off the ballot, so long as the ballots have not been printed already. We are at the point now where we have 4 good, viable wholesale proposals and 3 good, viable plant purchase offers. The evaluations that have been completed show that there would be considerable savings for Escanaba to buy wholesale power. Before we expend alot of time and money investigating further details, it was felt that this was a good time to ask the citizens if a plant sale was even a possibility. The vote only seeks the authority to sell, lease, or dispose of the plant.
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There is the possibility of hydrogen power. This could be done by the process of electrolysis, we have no shortage of water!
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This option has not been researched by the City.
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I presented these questions at the 2/4/09 meeting with the EAC,however, no answers yet. So here they are again.
If we shut down our existing Power Plant, based on existing demands currently recorded by the ATC transmission system for the Delta county area, will enough import capacity AND capability be available for our Delta county area?
If we shut down the existing power plant what will our system reliability be for uptime, outages etc compared to our existing system reliability? Answer this question as if you treat the distribution system for the city of Escanaba as a node in the Delta county region.
We know reliability will go down because we will loose a local generation source. However, ATC upgrades will influence our reliability. Will ATC upgrade their existing transmission system serving the Delta county area? When will that be completed?
Could you update your 2006 Escanaba Load Duration Curve that was presented on August 13, 2008 for both years 2007 and 2008?
If you sell the existing power plant and enter into a long term power purchase agreement with the outside transmission system and outside generation providers, what would I expect my new bill to be? Would you be willing to submit with your next bill a what if comparison showing what I paid for each month during the last 6 months versus what I would have paid if the new contract to purchase power was in place?
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Will enough import capacity and capability be available for our Delta County Area?: ATC would have to complete an analysis of their system to see if the local transmission system could handle the addition of Escanaba's load. ATC does not have the need to do the study at this time as Escanaba has not declared their load on the system, additionally, most of the Escanaba load is masked by the local generation.
What will our system reliability be for uptime?: Being that we have 3 good, viable offers to purchase the plant, it would appear unlikely that the plant would be shut down under any scenario. However, for the sake of your question, if it was shut down, I think any decrease in reliability would be very small. We have been recording every outage inthe City for more than 2 years now and we have had 1 transmission outage compared to 110 distribution outages over this period. Will ATC upgrade the existing transmission system serving the Delta Co region?: Once we declare our load to ATC, they will study the transmission system feeding Escanaba. If they determine that upgrades are needed, they will start the process of designing and constructing the needed upgrades. When will that be completed?: If ATC determines that upgrades are needed, they estimate 3 years to complete the upgrades. Could you update your 2006 load duration curve?: Yes, it will be posted on the escanabaenergy website. What can I expect my new bill to be?: Of course this answer depends on what type of customer you are, what your energy requirements are, etc. For an average residential customer using 500 kWh/mo, the current bill would be $50.88, BUT we need to remember that this is an artifically low rate. For fiscal year 2008/2009 a rate increase of 13% was needed to balance the electric budget. This increase was not passed on to the customer. IF the 13% increase would have been passed last year, that same customer would have a bill of $57.49. If Escanaba would have been purchasing power from an outside source, we could expect that same customer's bill to be $45.94. Would you be willing to submit a "what if" bill for comparison?: Creating "what if" bills for over 7000 customers would be a huge undertaking, so it would not be done for every customer. Sample billls for various customers are available in some of the power point presentations found on the escanabaenergy website. The lowest cost proposal that has been submitted to the City shows a 20% decrease in costs as compared to the 2008/2009 TRUE costs.
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How will the city of Escanaba control the potential future cleanup cost (forever our burden) for environmental contamination within the area of the power plant that would be sold? When will we have an assesment cost estimate?
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A Baseline Environmental Assessment (BEA) is needed to determine the potential of environmental issues at the site. This was discussed at the 03/11/2009 Electric Advisory Committee meeting.
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What is the year 2008 and 2007 operations, supervision and maintanance cost to the city of Escanaba for our power plant?
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The City operates on a fiscal year, so the answers will be for fiscal years.
For 2006/2007, the costs to the city directly related to the plant were: 1) Operation (less fuel) = $1,525,344; 2) Maintenance = $747,383;
3) Administration = $1,669,468; 4) Management Fee = 38,848; 5) Dispatching Fee = $30,767;
6) Deprecication = $525,714.
For 2007/2008, the costs to the City directly related to the plant were: 1) Operations (less fuel) = $1,594,294; 2) Maintenance = $1,142,039; 3) Administration = $1,002520; 4) Management Fee = $40,837; 5) Dispatching Fee = $31,787;
6) Depreciation = $714,954.
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Will the city of Escanaba invite ATC to a public meeting in the city hall to present to the citizens of Escanaba a summary of the status and future of their transmission system serving the Delta county region. Request that ATC present their assesment as to the reliability of the 69kv transmission system in the Delta county region.
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Yes, this could be done. ATC has been here many times over the past few years to discuss transmission issues.
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With the advent of electric vehicles within one year, will the infrastructure for power delivery have the capacity for this potential huge growth? How will this impact the Upper Penninsula ATC transmission system's import capability from power plants located outside of the State of Michigan?
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Will the infrastructure for power delivery have the capacity for this potential huge growth?: Yes, many utilities have created rate schedules that encourage the customer to charge their electric vehicles at night or on weekends, when energy demand is usually low. I would anticipate Escanaba creating similar rate structures that would encourage the vehicles to be charged on off peak times. How will this impact the U.P. ATC transmission system's import capability?: It is likely that the impact would be very low. Typical transmission system peaks occur in the afternoon or evening. By creating rate structures that encourage these vehicles to be charged on off peak hours, the impacts to the system should be minimized.
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Ralph Peterson, our city attorney, stated we are being held responsible for 30% of the costs for power plant emission violations. Why can't the city hold our power plant operators responsible for their own mistakes? We hire them as professions to run the plant, that's their job. If they can't do it properly, find someone else who can do the job right. There are plenty of qualified companies and people out there looking for work right now. And only sign a contract where you hold people responsible for their own actions. Negotiate the contract to our terms which are: we will not pay for someone else's inept or careless mistakes. Isn't it time to find a company that will run the plant in a professional manner and be accountable?
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Why can't the City hold our power plant operators responsible for their own mistakes?: The operating agreement written many years ago does not specifically address who is liable for fines and costs where there is a violation of DEQ regulations and/or permits. The City would have had to pay the entire fine and all of the attorney fees and costs and then sue the operator to try to get our money back. The cost of the lawsuit against our operator would be equal to what the city paid to settle the matter. The city in filing such a suit against the operator would run some risk that the City would be responsible for the entire amount. Isn't it time to find a company that will run the plant in a professional manner and be accountable?: Our present operator has given the City notice that it will not operate our plant under the terms of the present operating agreement. In the event tha the May 5th vote does not give the City Council authority to sell the plant, the City has entered into negotiations with our present operator to try to work out a new operating agreement. Our present operator has indicated to us that they will not sign an operating agreement which requires them to pay fines and costs in the event that their employees are negligent or make mistakes. Hopefully, the questioner is correct that there are other qualified companies anxious to operate our plant and would be willing to enter into a contract which would be more favorable to the city. We are not, hovvever, confidant that there are such qualified companies who would be anxious to operate our 50-year-old electric plant.
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The most recent study by ATC has indicated our area has low voltage issues. In addition, the UP is affected by equipment in Ludington. How can we avoid worsening the low voltage in our area? Will this require we ensure or power plant is operational until after the ATC system has completed their upgrades? Is it possible we could hold off selling our plant until after the upgrades are completed? Furthermore, what is the payback or loss to the city of Escanaba if we plan this transision in the above method?
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How can we avoid the worsening low voltage in our area?: Our expectations are that if the plant is sold, it would continue to operate. Therefore, there would not be any changes needed to the transmission system. To improve the voltage in this area, it is likely the transmission lines would need to be upgraded. Will this require we ensure our power plant is operational until after the ATC system has completed their upgrades?: ATC would have to do a study with the generating plant removed and see what the results on the system would be. I do not know what data was entered into their system model to show this area having low voltage. Removing the generation would lower the voltage, but I do not know if it would be significant. Is it possible we could hold off selling our plant until after the upgrades are completed?: If the plant was sold to a company that continued to run the plant and converted one (1) boiler at a time, we could sell before the upgrades are completed, as it would be essentially the same as things are today. If the plant was to be shut down completely for a conversion, we may have to wait for transmission system upgrades to be completed. One of the stipulations for private entities to be eligible for federal production tax credits is that the plant must be operational by the end of 2013. If this plant doesn't sell soon, it may push the conversion past that date, make it less attractive to private companies. Furthermore, what is the payback or loss to the City of Escanaba if we plan this transition in the above method?: If the plant is sold, the Escanaba Electric Department would see the proceeds from the sale of the plant. If the plant is not sold, the City would be ultimately responsible for it when it is no longer useable and would be responsible for dismantling costs. The ten (10) year energy cost forecast prepared by PSE shows savings for the Escanaba Electric Department for each of the next ten (10) years, thus the costs would go down. The Department would not see a payback or a loss as it is generally budgeted to break even, but the customers would see the benefit of lower electric bills.
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If power is purchased whole sale, through a long term power purchase agreement, how many years would a purchase agreement be? 5, 10, 15, 20, 25, 30.....?
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The proposals received have various term lengths associated with them. 1 of the proposals is a ten year term, the others are a minimum of 5 years, with a 1 year termination notice. So, it is possible that these agreements could go on for 10 years, 20 years, or more. These terms are what has been proposed. Final terms would need to be determined in more detailed negotiations.
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Would the city and EAC post their meeting notes promply this month (April 2009) so we have current updated information on your sites?
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The DRAFT EAC minutes are done. However, the City does not post draft minutes. If you would like a copy of the draft minutes, please contact the Electric Department at 786-0061.
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Can you explain what will happen to the power plant after a yes vote and no party purchases the plant? From what I understand through this past weeks meetings, if Tryxes does not get the contract to provide the city with power then they would not be interested in purchasing the plant. DTE stated they need to find someone to purchase the power from the plant before they would purchase it. So what I struggle with is, if I vote yes, but no party purchases the plant you still have the authority to dispose of the plant. I'm all for selling and or leasing, just not the dispose of. So I'm still confused on which way to vote. Thanks
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If no party is interested in purchasing the plant, it would greatly complicate the situation. The City would need to take a very close look at all facets of continued ownership.
If we continue to run the plant, the customers will have to bear the burden of high costs.
If we shut the plant down, the City will be faced with the cost to tear it down, which was estimated to be $13,000,000 by Sargent and Lundy in their new plant study a couple of years ago. This option would also result in higher congestion charges and loss costs from the Midwest Independent System Operator.
If the City was to buy power wholesale and run the plant as a coal-fired merchant plant, we would lose money doing so. And by law, we cannot run it as a merchant plant.
If we wanted to convert the plant to biomass ourselves, we would first need to get financing, which may not be easy to do currently. Then we would have to pass the conversion costs onto the customers through higher ratesx. Preliminary studies show that a conversion cost of more than $15,000,000 would result in higher costs than the current coal-fired generation costs. Even if the conversion were 0, biomass self generation would still be more expensive than the wholesale options available today.
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With the election over, and without the yes vote at 60%; One negotiate to purchase the city's average power about 15mwatts from an outside supplier for a long term contract. That will immediately reduce our electric bills. Secondly, run the power plant only when needed to supply the demands from our city over and above the average contracted power to prevent high demand charges. This would keep the cost of operation down, maintenance down and support reliability. Thirdly, negotiate with someone to run the power plant to OUR TERMS and to maximize our return on investment. Fourth, run the the generators to maximum output when we can sell power and make good profits. Fifth, purchase coal thru a long term contract at the low prices available now which are substantially lower than what was predicted a few months ago. If any of the above are not allowed legally, please provide the exact reason why with reference to the existing charter.
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One and Two: we could negotiate a contract with an outside supplier for 15MW, but there are some problems associated with that plan. While this power purchase may be able to save us about $2,000,000/yr, we would still have all the fixed costs of the plant, which run about $5,000,000/yr. Therefore, we would be roughly $3,000,000/yr worse off than we are today. Also, each boiler has a minimum output of 5MW, and the City load swings from 12-24MW on a typical day. Even if we only ran 1 boiler, we would either have to shut it down nightly, or continue to run, selling power during the low load periods at a substantial loss.
Third: We have been in discussions with various potential plant operators for a few months now and it absolutely is our goal to find the best deal for the City.
Fourth: Good idea. This would help us reduce our overall costs via power sales, but overcoming the $5M fixed costs may be difficult. As an offshoot to their main study a couple of years ago, PSE looked at the profitability of running the plant as a merchant plant (before we knew it was illegal to do so) and they estimated that we would lose money doing so.
Fifth: We could request bids for coal on a long term basis, but we have found that suppliers hedge the bids against future prices by adding some $ onto their bid to protect themselves should the costs go up in the future. With our recent experiences of being "force majeured" twice in the past 18 months, I would be skeptical of any long term deal. There are too many loopholes in coal contracts to be 100% certain that what they are telling us today can happen in the future.
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Plant still for sale?
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Yes, the City will be sending out Requests for Proposals (RFP's) in regards to a possible plant sale soon.
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I am in the University of Phoenix B.S. Organizational Security and Management program and I am writing a paper on Escanaba Emergency Security Response. I did a google on the plant and could not find any information on how the plant will respond to a potential disaster or terrorist attack. Since I could not find one, I was wondering if the plant had a plan and if a public version could be made available. Thank.
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