 |
             |
COMMISSIONERS OF PUBLIC WORKS A public hearing and meeting of the Board of the Greenwood Commissioners of Public Works was held on Thursday, May 24, 2007, at 5:00 p.m., in the board room at 121 West Court Avenue. In attendance:
I. Chairman Watts called the meeting to order. II. Chairman Watts gave the statement of compliance with the notification provisions of the Freedom of Information Act. Chairman Watts stated the purpose of the public hearing which was to receive comments from the public regarding a proposed 3.8% increase in natural gas rates, and revisions in electric and water rates which may result in an increase or decrease depending on usage. Commissioner Hancock gave the invocation.
Ms. Brown provided an overview of total revenue excess or deficiency for each system. She provided an explanation of how the present revenues were first calculated and then fuel and purchased power adjustment revenue was added. She noted that purchased power fuel does affect the bottom line of a bill and would get a rate increase; however, the purchased power fuel adjustment portion is pass through costs that go through adjustment clauses each month. There may be timing differences from month-to-month as to when it is collected; however, over time it should be completely a wash between what is collected and what is spent. Ms. Brown referred to the base rate revenue requirement for electric of $17,333,684; $9,674,163 for water; and $7,117,040 for gas. She noted that pipeline demand charges are $3.4 million due to the Transco increase where they had been $2.5 million last year. She pointed out an increase of $900,000 just in the last couple of months which accounts for a big portion of the overall revenue increase requirement for gas. Commissioner Monaghan asked if that was in the base rate. Ms. Brown responded that it is right now, but they are looking at separating and moving it into a separate charge to be able to track it and make decisions if and when FERC decides to give a refund. She added that another reason would be to provide a “distribution only” rate to some of the larger industrial customers. Ms. Brown continued by noting a 1.69% revenue excess in electric; .01% in water; and a revenue deficiency of 3.8% overall in gas. Ms. Brown stated that because electric and water are pretty much at a breakeven, they simply looked at rate design issues. Ms. Brown noted that the best time to implement rate design changes are when you are at a breakeven position in a cost of service study or a rate study, because it helps to avoid “pancaking” with customers who might receive an increase through a rate design change along with a rate increase. Ms. Brown pointed out concerns with large power rate design in the electric system due to the way the current rates are structured. She stated that customers with exactly the same load characteristics in terms of load factor are allowed to have much bigger discounts just because they are a bigger customer. She provided an example of a 50 kWh customer that would not get the type of benefit even with a 100% load factor as a 1,500 kWh customer with the exact same load factor. Ms. Brown noted that under the wholesale power supply contract, the marginal cost of trying to bring in larger customers with good load characteristics would be greater than marginal revenues. That makes it difficult to add new customers who should otherwise be very attractive to our system. She explained that adding larger customers helps the whole system to share the fixed costs and thereby bringing down the cost for everyone. Commissioner Monaghan referred to a previous slide and inquired as to whether it was 3.8% of the base. Ms. Brown responded that it was 3.8% overall. Commissioner Monaghan asked about calculating overall when the purchased fuel is a pass through. Ms. Brown responded that we want to show what people will see on their bills. There will be a higher increase if you look at base rates only, but what they will see on their bills would only be about 3.8% overall on average for the system based on expected fuel costs. Otherwise, it would look worse than it really is. It is not as bad as it would seem when you look at the total bill. Somebody with a $100 bill will not see a $20 increase; they will see about an increase of around $3 to $4. Manager Reeves noted that the base rate itself would go up around 20% to 21%., but that would be misleading to the public who would be anticipating a 20% increase on their bill when it is actually more like 3.8%. Ms. Brown continued with an explanation of rate design revisions for large power. She stated that they tested those designs with the objective of wanting to have a margin over the incremental wholesale power supply cost for any new load brought on. She emphasized an effort to not have extreme rate changes for any customer and they were phased in over time where they could. Ms. Brown commented that the objective was to remain competitive against Duke Power’s rates, and to have equitable rates where customers with similar load factors and characteristics would receive similar benefit. She stated that a rate was designed that would best meet all of those rate design objectives knowing that all cannot be met, but all must be balanced. She referred to the proposed large power rate design showing that the customer charge was left “as is”. Ms. Brown pointed out that the current rate structure gives a “discount” for energy used over 400 hours. She explained that basically somebody with a “demand”, which is the maximum that they place on the system in a particular hour, causes CPW to incur demand cost from the wholesale power supplier. If they use their energy associated with that demand for a lot more hours, they have a higher load factor and those are the customers that would fall into this energy over 400 hours use. Ms. Brown noted a pretty substantial decrease for those customers. Right now the first 400 kWh hours pays almost $.0458; over that 400 hours use drops to $.0238. The problem comes in because the existing rate design within the first 400 hours has these four different blocks (first 10,000 kWh, next 90,000, next 150,000, and over 250,000). She stated that essentially that gives a benefit to someone for nothing more than their size and has nothing to do with their load characteristics. A very large customer with a much poorer load factor will still fall into the higher blocks and get a discount than a smaller customer who might have a better load factor and just too small to get out of the first 10,000 kWh. She pointed out that in an effort to alleviate that situation, the first three blocks were combined and a little more was moved into “demand”. She referred to the contract with the wholesale supplier whereby CPW pays $8.65 per kWh for base load capacity, and between $4.50 to $5.50, depending on the season, for supplemental capacity. Ms. Brown noted that if that much is paid for demand and our cost is recovered through energy cost, there is a mismatch between fixed costs that we are incurring on a demand basis versus the energy. Ms. Brown provided charts to show the impact through a rate comparison for large power customers. Ms. Brown noted that CPW was able to compete with Duke Power very well within all of the rate designs. A smaller 50 kW customer who at this point would not get the benefits would actually benefit from the new rate design because some of the unfair benefits of the huge customers were brought down. To show the effects, Ms. Brown noted that with 1,500 kW, the proposed rate is slightly greater. The differences are not huge but it does start to bring us toward a more equitable rate design and allows marginal revenue for those new customers we are trying to propose over and above what is paid to bring that load on the system. Ms. Brown stated that this does not change the overall revenue received from the system, it simply “divvies” it up differently. Chairman Watts inquired about average usage for a homeowner. Mr. Meredith responded that it averages around 1,000 kWh per month. Ms. Brown noted that residential rates were not being touched. She summarized electric by noting that it is essentially at a break even position. The changes suggested to the large power rate would help us to become more equitable, to start meeting other rate design objectives, and would still allow us to compete for new load. Ms. Brown reported on the water system and current revenue requirement.. A capacity fee analysis was also done. She pointed out that the current rate does not reflect the American Water Works Association (AWWA) meter rating factors, and currently there is no charge in the rate design for the first 400 cf. Ms. Brown stated that the first concern was to establish a monthly incremented service availability charge based upon standardized capacity criteria established by the AWWA relative to the size of the water meter. She noted another concern with moving towards elimination of the 0 to 400 CF “discount”. She added that the way the rate is now, those who only take 0 to 400 CF do not have a charge there and only pay the meter charge. Then when you get to the middle, the rate goes up to the highest point and over 15,000 CF per month, the rate goes way down and essentially gives these customers about a 60% discount. She noted that there really is no justification in a water system to give that type of a discount for using more water, and the goal was to start to move toward of elimination of the 0 to 400 CF discount and to soften the discount for usage over 15,000 CF per month. Ms. Brown provided information in equivalency factors used by AWWA. Commissioner Monaghan provided an example of a person using 200 CF and asked if that would go down. Manager Reeves responded that the total bill may not be less because the basic facility charge will have to go up because it was insufficient in the current rates. Commissioner Monaghan stated his understanding that the current meter charge covers the first 400 CF. Ms. Brown responded that the guy that is paying pays the $7.84 and does not pay anything else, but the $7.84 is not sufficient to cover the cost that should be there if you were to do it based on true costs incurred by system. Therefore, when the rate was redesigned, they did not take the rate and cut it in half in order to put charges into the first 400 CF. The goal was to get to a more cost based rate overall. Ms. Brown explained that the person at 400 CF currently pays $7.84 and it would go to $9.70, for an increase of $1.86 in the overall charges. Ms. Brown stated that water would not increase overall, but there are rate adjustments whereby some would realize an increase and some a decrease depending on their consumption. The overall system does not receive an increase or a decrease. The larger customers are getting hit too because they were falling into the greater than 15,000 CF. We are attempting to levelize to be more equitable for all customers because the first gallon does not cost any less or more than the tenth gallon, so straight across the board is the most equitable type rate. Commissioner Monaghan stated concern over residential customers’ rates going up. Mr. Chapman provided an example stating that the average household uses about 4,000 gallons per month which would equate to an increase of around $0.04 on their bill. Ms. Brown continued with a bill comparison chart based on 6,000 gallons usage in a month with the proposed rate change and noted that the total month charge would be $15.15. She stated that in a comparison with other water systems in the state, CPW would fall pretty much in the middle. Mr. Chapman noted that in Columbia, the $12.72 number is misleading because they have assessed a flat hydrant fee of $5 that they residents pay monthly making that charge $17.72. Commissioner Monaghan noted that this was for “inside city” rates, and noted that the “outside city” charge was 80% higher. Ms. Brown continued by stating that in addition to the water rate design for base rates, they also looked at the capacity cost incurred by the system. She explained that a capacity fee is basically a one-time charge that is implemented to recover the costs associated with capital investments in order to provide service to future users of the system. She stated that a fee analysis was done to determine cost on a per gallon basis and per residential unit, and what the cost would be should you implement a capacity fee. Using the AWWA meter factors, the analysis showed that costs could be covered with a $1,080 charge for a typical 5/8-in. or ¾-in. meter. She noted discussion at the last meeting whereby they had determined they did not want to go that far at once but would prefer to phase it in starting at $500. She referred to a phase-in ranked by meter size by the AWWA meter factor starting at 5/8-in. at $500 and going up to 8-in at $40,000. Ms. Brown then provided a comparison of these capacity fees versus other utilities, noting that the average is $1,023, but by phasing it in, it puts CPW third. Commissioner Monaghan explained that this $500 would be for a new home construction and the impact of that new home, noting that we had never had this before. It is a one-time fee for a new connection. Ms. Brown noted that there is not a phase-in plan; they will start with this and re-evaluate each year and the Commissioners would determine if and when there is a need to raise it based on actual cost. Commissioner Monaghan asked how much was spent just this past year on the water plant alone. Manager Reeves responded that it was in the $3 million plus range due to regulatory upgrades. Commissioner Hancock added that CPW has cheap water that is also good water, there is plenty of it, and is recognized as the fourth best in the United States. Ms. Brown explained revenue requirements issues faced for the gas system and stated that the trend of warmer weather has reduced sales levels over the last ten years, resulting in the need for a rate increase to cover fixed costs of providing service. She stated that in addition, even though sales have gone down, customers have gone up. We have more customers to service and yet they are buying less gas. She noted that the trend of warmer weather seemed to be continuing. She stated that in developing the cost of providing service, they looked at a ten-year weather normalized load expected to be sold this year. In addition, Transco has requested an increase at FERC resulting in a 32% increase in pipeline demand charges and an 8.3% increase in CPW’s non-fuel budget. Ms. Brown further explained that when CPW purchases gas from the hub, they have to bring the gas to the city gate; they have to basically transport that gas. There is a company that owns all of the pipelines and does that transportation. We have to contract to make sure that there is enough capacity on the pipeline so that when it gets cold and everybody turns on furnaces, etc., there will be enough capacity to bring the amount of gas that will be needed. Ms. Brown stated that CPW does an excellent job of controlling these costs and actually has a program where they try to release capacity in months that it is not needed. Last year that cost was about $2.5 million; this year it has gone up to $3.4 million effective March 1, 2007. She noted that it is subject to some sort of refund and was sent to FERC for a decision. If they decide the rate increase is not justified at that level, they can reduce it. She added that it could be three or four years before that decision is made. If they do they can come back and order them to make refunds with interest. At that point, one of the things we are looking at doing is moving this into a separate charge so that it can be fairly recovered at CPW’s actual cost with no margin so that CPW would have the ability to monitor and treat the customers fairly if and when an adjustment is made by FERC. For now, we are paying and have had this 8.3% increase in the non-fuel budget for this cost alone. Ms. Brown continued with the presentation and referred to a previous slide showing a 3.8% overall need for a rate increase with gas included. She noted that in calculating that, they look at which classes are causing the cost on the system and at appropriate ways of allocating that on an equitable basis. She provided an overview of system cost of service analysis showing a breakdown of the allocated costs of service. She explained that they started with present rates given the weather-normalized load forecast with the expected sales from each class and what would be recovered in the test year on present base rates. They then add gas revenues that are expected to be recovered to get total revenues for each class. The base rate revenue requirement consists of all operating and maintenance costs including salaries, trucks, and everything necessary to maintain the distribution system and administration allocations, to pay debt service, etc. , except for the gas. She stated that she had now removed the pipeline demand charges to put that into a separate “bucket”. Right now it is all recovered in the base rates. She noted that total base rate and pipeline demand charge revenue requirement now is $10.5 million. This means that we will be $1.751 million short on the total bill for the total cost of providing service under base rates and pipeline demand charges on a weather-normalized test year. When compared with total revenues that is a 3.8% increase; compared against base rates only, it is 20%, but what will be seen on the bill will be more like 3.8%. In looking at different classes, that equates to almost 7% for residential and commercial and firm industrial and interruptible industrial have a smaller increase primarily due to the way the pipeline demand charges are allocated. She noted that with interruptible industrial we have the ability to interrupt them and therefore we can arrange for our pipeline capacity in a manner that allows us to release that capacity because we can interrupt them. Therefore, they do not get a full allocation of those pipeline demand charges. She added that is pretty standard in the industry because those customers have given us the ability to control and reduce our costs by allowing them to be interrupted. Commissioner Monaghan stated that depending on the consumption of gas with weather normalized, it would raise or lower the required increase. Ms. Brown responded that was correct, but there had to be some starting point to set rates and that was done on weather-normalized. She added that even with the weather-normalized forecast for the test year, the first four months of 2007 are already less than what was forecasted. Ms. Brown stated that they went back and looked at sales and the number of customers from 1996 to 2006. She pointed out reductions in sales for the total system, residential and commercial classes, whereas there were small percentage increases in customers. Even with the addition of about 3,000 customers, gas sales have gone down. Commissioner Hancock noted an incentive program to try to add load and investments made in things such as rights-of-way in order to get the new schools back in as customers to keep load going. Ms. Brown continued that almost all cost other than gas are fixed costs and are incurred to put pipes in the ground and to maintain them and to have the staff. To the extent that we sell less gas, we take a hit. When we sell less gas, those fixed costs do not go down; they stay right where they are. She provided a breakdown of total revenue requirements at the time of the last rate increase in June of 2005. Overall, there was an $8.7 million revenue requirement needed from expected sales and a $500,000 margin was put in to provide a cushion to provide capital improvements. Now, we are at $10.5 million without having any margin. From the 2005 test year to the 2007, there has been a 20.7% increase whereas there was only an 11.9% increase in expected sales based on assumed weather-normalized in 2005 versus 2007. Ms. Brown stated that part of the reason for an increase is because there are fewer units for the amount of money we need to recover. Ms. Brown commented that mild weather also really affects the system overall. She stated that there are also some design issues, one being that interruptible customers are exercising options to utilize alternative sources of fuel or switching to electric. She noted that existing rates are mainly volumetric, or variable, giving the wrong price signal to those customers with alternative sources and allowing avoidance of CPW’s fixed costs of providing service incurred to serve them. She stated that the reason is that CPW still has the fixed costs whether they use gas or not; we have put in the pipes to serve them and when they compare to an alternate source of fuel, they are looking at a variable cost on and avoid our variable gas costs and also our fixed costs. Ms. Brown commented that we know that some of these customers might want to provide their own gas and transportation to the city gate. For that reason, we wanted to give them an unbundled rate so that they could do that and we would provide a “distribution only” rate that would be a fair rate to recover our cost of having that distribution system in place to serve them. She pointed out that we would not go all the way to a pure fixed variable type rate, but rather are trying to move toward that with this rate design. Ms. Brown stated that they were unbundling rates and implementing a pipeline demand charge adjustment clause; would shift a portion of the cost recovery from volumetric to demand and customer-based rates to reflect the nature of the cost curve incurred; and developed a distribution rate. Ms. Brown summarized that the pipeline demand adjustment clause would assure monthly recovery of pipeline demand charges; would give a mechanism for handling FERC-ordered refunds; shifts $3.5 million out of base rates and moves it into another category with no margin; and by unbundling rates can get the “distribution-only” rate and have them pay pipeline demand charges. They pay gas costs if they are buying gas. “Distribution-only” customers would only pay that rate. Ms. Brown explained the methodology for the pipeline demand charge adjustment clause. She stated that it is allocated to classes based on the previous year’s winter months’ sales because that is how we have to contract for the capacity in any year going forward. She noted that it is unfair to interruptible customers to allocate a full load because they do give us the ability to manage somewhat and allow us to interrupt in cases where there is not sufficient transportation capacity. 80% of cost is allocated to firm classes only; only 20% is allocated to all classes which based on last year’s winter months sales gives interruptible customers an overall allocation of about 11% right now. The industrial rate would be based on maximum daily quantities which allows for addition or loss of customers and give less ability for customers to avoid fixed costs incurred to serve them. She noted that the goal is a “zero sum” gain. Every month your bill is $300,000, that is what is billed to customers and there will not be a plus or minus. She noted that having interruptible customers allow CPW to save and those costs are saved for everybody on the system. She continued that residential and commercial total revenue requirements had increased approximately 7% overall, while industrial revenue requirements have increased approximately 1.3% – to 1.7%. She noted a variance with customer impacts depending on usage. Residential and commercial customers will experience larger increases in summer and smaller increases in winter due primarily to Transco pipeline demand charge recovery. Right now, because it is in base rates on a volumetric-type rate, you are getting a much higher cost in winter than summer. Now, the customer will pay what it really is in the winter and what it really is in summer. Commissioner Monaghan asked for an explanation of how the rate would increase if you only have a pilot light on during August. Ms. Brown explained that the rate would increase because the pipeline demand charge goes down from January to June; even though you have less overall system pipeline demand charge, there are less units that you are selling. When you divide the amount you have by the lesser unit, the unit charge will be a little higher in summer than in winter for customers that are paying this pipeline transportation cost. For the year, it comes to about to about 7% overall. Commissioner Hancock noted that as a year-around user, his rates would still go up. Some of those in the winter would get an advantage by just having gas heat. Ms. Brown referred to residential customer rate comparisons with other cities showing that the winters are still slightly below the others they were able to get. She noted difficulty obtaining this information because many cities have purchased gas adjustment clauses that may be implemented differently. The summer charge showed us at the top of those five but because we are so much lower in winter when people are using a lot, overall it is still very fair over the year. Ms. Brown concluded the report by providing an explanation of the Commissioners concerns over the income statements appearing to show $2million in net income and questions as to why there is a $1.7 million deficiency. She provided an example whereby gas costs are incurred in December and are incurred in a calendar month basis. When we pay our bill for gas for whatever we pay in December, the customers are billed on cycles. The gas costs that we incur in December, part are incurred and paid for then, but a bunch is paid for in January. You have a lag between gas cost incurred and gas cost collected in a PGC. In the net income report, the amount collected is not shown on the report the Commissioners receive. It is not shown as a “Receivable” in December. We have gas cost billed versus gas cost incurred. These are two different months; there is a half of a month’s lag. For example, if you have cost of $2.1 million gas in December, half of that is not collected until January. In April, you only sell $600,000 of gas and half of that is not collected until May. The difference between those two shows up in the income statement so that you are getting half a month of December sales showing up in your revenue against cost that are way lower because now you are looking at a “shoulder” month. For purposes of the cost of service and rate study analysis, all of the gas cost is removed because the PGC is designed to and the way the industrial customers are charged is gas costs are simply a “pass-through”. There may be a timing difference, but over time there will be a “zero” net income associated with it. Ms. Brown stated that she has to remove that and show with all of the other costs what is needed to be recovered. She referred to the most recent report showing $2,063,000 at the end of April. In looking at rate making adjustments, she explained that they first remove the net income associated with gas cost recovered in the PGC which is the timing difference. That alone was $1.24 million that was unbilled in December but showed up as a revenue in January so there is a revenue in January that really did not have its’ associated gas cost in the net income statement. Of the $2 million, $1.2 million was related to a prior period gas costs. If you take all of the gas cost out, and all gas revenues out, this is “false” income. Commissioner Monaghan asked if the “unbilled revenue” line would compensate for this phenomenon. Ms. Ogletree responded that it would by the end of the summer when everything would be fully accrued. Right now, it is on a modified accrual basis and would be fully accrued at the end of the year. Future reports will have this line and that will offset what Ms. Brown is explaining. Ms. Brown stated there are issues with accounting rules and sometimes it is hard to reconcile the two, but they hope to get information for ratemaking so they know what is needed “cash-in-hand” to operate. Ms. Brown added because of the nature of a PGC and how auditors say it has to be accrued cause issues. She and Ms. Ogletree are trying to get to a point so that what is seen can be explained. For ratemaking purposes, they are also saying that there are certain capital expenditures that are going to be recovered from rates. Some capital expenditures will be recovered from new debt service, but there are ongoing capital expenditures that do not show up in the income statement because those are the items that are accrued and depreciated over time. They have to put them in because they have to have the revenue to recover those. They are adding back the depreciation because for ratemaking purposes, they do not use depreciation but instead use capital improvements plus the principal payment. They are trying to get to more of a cash flow basis to know what is needed in cash to run the system. They are adding back depreciation to the net income because that is a “non-cash” item and instead subtracting out principal and capital items. Then they subtracted revenue from CPW and “muni-sales” because under the policy they have in the City, there is a $1.2 million transfer liability that consists of a certain amount that will be transferred plus reimbursement of all of the “muni-bills”. Of the other transfers to the General Fund, over the year equals $1.2 million for all three systems. For this system over the year is showing at about $366,000. That is not real revenue when it comes in one hand and out the other. For purposes of January through April, $171,339 was taken out for Transco pipeline charge increase. That increase was not really experienced in January and February because it did not happen until March 1, but for purposes of setting rates on a prospective basis, if that is not included, then you will under-recover for the year. Then the PGC had an adder put in on a temporary basis for March and April to recover the incremental cost of the pipeline demand charge increase until they could determine how to handle the pipeline demand charge issue. Therefore, in the net income you recovered $118,000 more than you really would had you not had that adder. Ms. Brown stated that at the end of April, there was really only $472,000 on a ratemaking basis. The reason there is a profit there where a loss is shown for ratemaking purposes for the whole year is because all of the gas is sold during January and February. It is expected that you will have a bigger net income at the beginning of the year that will keep eroding throughout the year. She stated that the major December projections were done and added together to show that at year end based on what we have to do, which is the January through April sales that are lower than anticipated, we are looking at a $1.991 million shortfall as opposed to the $1.751 that rates were designed around because they already had the reduction. It is the nature of accounting statements versus what is actually needed “cash-in-hand” in order to run and operate the system. Most of it simply due to the timing difference on gas cost. Ms. Brown concluded the presentation by noting concern that if an increase is not implemented at this time, the debt service requirements would not be met because of the expected increase in expenses relative to debt. This would be even more relevant with the new bond issue. She stated that preliminary calculations showed that we would not meet the coverage without it. With no further comments, Chairman Watts closed the floor for public comments.
The Commissioners noted that much of the financial statement was covered during the presentation portion of the meeting. Commissioner Monaghan noted the inclusion of “unbilled revenue” as a new item in the report. Ms. Ogletree responded that they would true-up for the whole year in January as if they had accrued in December’s statements.
VII. Other Business: 1. Manager Reeves presented a request to adjust the stop loss limit for the health insurance program. He noted that the stop loss is currently at $60,000, and that there would be a premium increase regardless of the decision. Mr. Reeves explained that they are offering an opportunity to increase the stop loss limit to $70,000 or $80,000. He stated that Ms. Ogletree ran a report to compare our previous history at each stop loss level. He noted that even if we increased the stop loss and payed a lower premium, because we are incurring additional costs, our overall cost is much greater, to the tune of about $100,000 per year. Mr. Reeves recommended keeping the stop loss limit at $60,000 for that reason. A motion was made by Commissioner Hancock to keep the stop loss limit at $60,000; the motion was seconded by Commissioner Monaghan, and unanimously approved. VIII. Executive Session: The meeting returned to open session. Manager Reeves stated that based on discussion during Executive Session, it would be appropriate for there to be a motion for CPW to contribute up to $7,500 into the insurance program for additional cost. A motion was made by Commissioner Hancock, seconded by Commissioner Monaghan, and unanimously approved. Manager Reeves noted the receipt of a request for an ad in the City Directory at a cost of $1,472. Commissioner Monaghan noted that the last directory contained outdated and incorrect information because they can no longer call people to get updated information. Commissioner Hancock stated that he still uses it to find names and addresses. Mr. Reeves suggested that since there is a charge for listings and a charge for the ad, that the ad on the outside cover be eliminated and just continue the listings. Mr. Reeves noted that a motion was not necessary. The Commissioners requested copies. IX. With no further business, the meeting was adjourned.
|
